Oil and Gas Q & A Dashboard


1	Visit the Data Snapshot for news and updates.
2	Notice	Date Posted
3	The trigger canister analysis for the April 26th event (including Livingston 1 and Anthem 1 stations) can be found here.	4/30/2021
4	Pipeline removal on the former Livingston 43-7 pad (just east of the active Livingston Pad, near the intersection of Sheridan and Lowell) is anticipated to begin on Monday May 3rd. See the full public notice here.	4/29/2021
5	The real-time sensor system at Interchange 01 triggered at 10:38 AM on 4/26/21. The trigger notification can be seen here.	4/28/2021
6	PUBLIC NOTICE 4-16-21 Oil & Gas Regulations View this public notice on the final draft of the oil and gas regulations. You will find links in this document to the following: latest redline version of the regulations, latest clean version of the regulations, and the memo with answers to recent Council questions on the regulations.	4/16/2021
7	Regarding the real-time sensor system at Interchange 01 that triggered at 1:38 PM on 3/14/21, the trigger cannister analysis report can be seen here.	3/26/2021
8	Broomfield inspection staff were notified in the field on March 23, 2021 that decommissioning of the Bickler well pad and restoration of the Kats well pad would start in the next day or two. The public notice is linked here.	3/23/2021
9	On March 12, 2021 Broomfield Engineering issued a public private improvement permit (PPIP) for decommissioning of flowlines associated with the Bickler 34 well pad location at 424 Lowell Lane in Palisade Park. Additional information can be found here.	3/19/2021
10	The real-time sensor system at Interchange 01 triggered at 1:38 PM on 3/14/21. The trigger notification can be seen here.	3/16/2021
11	Extraction Bankruptcy Update: Broomfield filed an objection to Extraction's Motion to Assume its Executory Contract (the Operator Agreement) on December 11, 2020. A hearing on Broomfield's objection was set for March 18, 2021 at 10am (EST) in the bankruptcy court in Delaware (the hearing will be virtual). Following a conference with the bankruptcy court today (March 15), that hearing date and time will now be used to address Broomfield's Motion to Abstain, and a discovery dispute before the parties. Special counsel will represent Broomfield in that hearing. Extraction's response to the Motion to Abstain is due March 17. The hearing on the motion to assume will be set for a later date. Special counsel will represent Broomfield in that hearing. Here is a link to the Bankruptcy Judge's page that has information about the virtual hearings for those who are interested.	3/16/2021
12	Late today, the Colorado Department of Natural Resources (DNR), Colorado Department of Public Health and Environment (CDPHE) and the Colorado Oil and Gas Conservation Commission (COGCC) reported to Broomfield staff that they have received data regarding an anomalous methane detection in Broomfield. A summary of the information report can be seen here.	3/12/2021
13	Western Midstream Partners submitted a 20-Day Environmental Clearance Letter on March 8, 2021. Additional information and the 20-day Environmental Clearance Letter can be seen here. The Western Midstream Pipeline Maintenance Map can be viewed here.	3/12/2021
14	An update on the Davis 43-6 methane attenuation project can be found here.	3/9/2021
15	An update RE scheduled pipeline maintenance on the Carlson 1-24 well (near 136th and Aspen Street) can be viewed here.	3/5/2021
16	An update on the Anthem 01 and Wildgrass 01 service level availability can be viewed here.	2/22/2021
17	An update on the Davis 43-6 plugged and abandoned well can be viewed here.	2/12/2021
18	Trigger canister results from the Interchange 01 event on December 20th can be viewed here	1/13/2021
19	Occidental has notified the Town of Erie (via this letter from December 22nd) that they will begin the completion phases of the development on the Cleland well pad (north of Erie Parkway and west of I-25). Read full public notice here.	12/23/2020
20	Extraction Bankruptcy Update: On June 14, 2020, Extraction Oil and Gas (Extraction) filed for bankruptcy protection in an effort to reorganize under Chapter 11 of the Federal Bankruptcy Code. Since this initial filing, there have been numerous developments in the case. Those developments are summarized, along with an FAQ document, here. On December 23, 2020, the bankruptcy court entered an order confirming Extraction's latest plan of reorganization. Court Order. Broomfield's objection to Extraction's Motion to assume the Operator Agreement remains pending before the court and a hearing date on Extraction's motion has not been set.	12/23/2020
21	The sensor system at Interchange 01 triggered at 12:57 pm on 12/20/20. This was a short-lived event lasting about 8-minutes with a max TVOC indicator reading of 638mV. The trigger report can be viewed here. Canister analysis will be provided by CSU within 5-7 business days.	12/21/2020
22	In the Chapter 11 bankruptcy case, on December 4, 2020, Extraction filed its Plan Supplement, which included the Broomfield Operator Agreement (OA) on its list of executory contracts that Extraction intends to assume pursuant to its Third Amended Joint Plan of Reorganization. In response to the Plan Supplement and Extraction’s claim that it does not have any cure obligation under the OA, Broomfield filed this objection to the assumption of the executory contract.	12/15/2020
23	Today, Extraction work crews are sandblasting the pigging station east of Huron and south of the Northwest Parkway, near the Interchange Pad. This is in preparation for painting the pipe at this site the color of desert tan. Work is anticipated to be completed today. Pig stations do not have any vents or flares on them. As such, there would not be any emissions generated by their normal function.	12/1/2020
24	A three day trial on Extraction’s noise ordinance violations was scheduled to begin December 7, 2020. That trial has been continued and will be rescheduled to a date in 2021.	11/30/2020
25	The Baker/Stipanovich well pad plugging and abandonment work is anticipated to finalize work on the last well on Friday. The crew will move to the Katz battery site on Saturday. Read the full public notice for more information.	11/25/2020
26	Pipeline and pigging stations are all painted at the Huron and Livingston sites, except for one water pipe at Livingston. The perimeter fence at Livingston is complete, see photos 1, 2.	11/25/2020
27	Broomfield’s Air Quality Monitoring Sensor System at Livingston 02 triggered at 5:17 p.m. on 11/17/20 with a peak volatile organic compound (VOC) indicator signal of 410 mV. The event appears to be a short term event, lasting approximately 15 minutes. Livingston 1 also registered the event with a smaller VOC indicator signal peaking at 5:18 p.m. The sample canister results from the 11/17 trigger event are linked in the public notice here.	11/25/2020
28	Update on noise lawsuit with Extraction Oil & Gas: On November 19, 2020, Extraction served Broomfield with a lawsuit appealing what it alleges is Broomfield’s denial of Extraction's request for a noise variance. Extraction submitted a request for a noise variance on September 16, 2020. On October 16, 2020, the City requested Extraction to submit additional information to support its variance request so it could be submitted to City Council for consideration. On November 12, 2020, Extraction submitted a document titled “Request for Reconsideration of Broomfield's denial of Extraction request for variance from BMC 9-36-080.” Extraction filed a complaint in the District Court in Broomfield on November 13, 2020 appealing the denial. The summons and complaint were served on Broomfield on November 19, 2020. The complaint alleges three claims: 1) mandamus requesting the court to find that Broomfield is required to grant a variance and ordering Broomfield to grant one; 2) an appeal of a quasi-judicial decision alleging that Broomfield denied the variance, which was an abuse of discretion; and 3) a request for a declaratory judgment that the noise ordinance and any future regulatory ordinances do not apply to Extraction because of the terms of the Operator Agreement. Since no final decision has been made by City Council the variance request, this lawsuit is premature.	11/24/2020
29	The Colorado Oil and Gas Conservation Commission (COGCC) announced today, November 23, 2020, it has Unanimously Adopted SB 19-181 New Mission Change Rules, Alternative Location Analysis and Cumulative Impacts. The COGCC stated that it has completed the rulemaking hearings addressing Mission Change, Alternative Location Analysis, Cumulative Impacts, and Compensatory Mitigation for Wildlife, as required by SB 19-181. The hearings began August 24, addressing the 200-600 Series and then the 800, 900 and 1200 Series started in October. The rulemakings were required to implement the change to the COGCC’s mission from “fostering” to “regulating” oil and gas development in a manner that protects public health, safety, welfare, the environment and wildlife resources. Please read more in the full announcement.	11/23/2020
30	On Monday, November 23, 2020, the Colorado Oil and Gas Conservation Commission (COGCC) should finalize deliberations on the 1200 (wildlife) series and may also finally adopt the 800 and 900 series. The Commission has already deliberated the 800 and 900 series rules, so the final vote is merely procedural not substantive. Here is the agenda for Monday’s COGCC meeting.	11/20/2020
31	Colorado Department of Public Health and Environment (CDPHE) Air Quality Data Portal Update - The CDPHE sent notification that its new Air Quality Data Portal is now live on its website (in both English and Spanish). Right now the only data reported is from the Bell Romero well site in Weld County. The CDPHE plans to use this as the format for adding additional Oil and Gas Health Information and Response Program (OGHIR) data collected across the state. You can find the dashboards in the Weld County > Bella Romero section here. It is anticipated that data collected at the Livingston Pad by CDPHE’s mobile monitoring lab (CAMML) is in the process of being uploaded and, when live, that data will be available on this portal in the near future.	11/20/2020
32	REMINDER - Tomorrow, November 20, 2020, the Colorado Oil and Gas Conservation Commission (COGCC) should finalize deliberations on the 1200 (wildlife) series and may also finally adopt the 800 and 900 series. The Commission has already deliberated the 800 and 900 series rules, so the final vote is merely procedural not substantive.	11/19/2020
33	At 5:17 p.m. yesterday, November 17, 2020, a trigger event occurred at the Livingston 02 sensor. Please read the preliminary report here.	11/18/2020
34	As requested by Broomfield, Extraction is painting the pig stations at Livingston (see photo) and at 160th and Huron (see photo).	11/17/2020
35	The workover rig is currently on site at the Baker/Stipanovich well pad. One of the four Baker wells has been successfully plugged and abandoned. Read the full public notice for more information.	11/16/2020
36	Broomfield inspection staff noted that the workover rig is currently on site at the Baker/Stipanovich well pad in preparation for plugging and abandonment activities. Read the full public notice for more information.	11/12/2020
37	On November 10, 2020, the Colorado Oil and Gas Conservation Commission (COGCC) released the final Statement of Basis, Specific Statutory Authority and Purpose (SBP) for the 200-600 Series Rules. The revisions can be viewed here.	11/12/2020
38	Extraction notified Broomfield staff that on November 12th they will be performing an aerial survey of their legacy pipeline systems, a portion of which are located in Broomfield. The survey will utilize a low-flying helicopter and is expected to take approximately one hour to complete.	11/11/2020
39	The Colorado Oil and Gas Conservation Commission’s (COGCC) 1200 Series Rulemaking Hearing began today, November 10, 2020, at 1 p.m. Read more, including prefiled testimony, in the Data Snapshot linked here.	11/10/2020
40	The Colorado Oil and Gas Conservation Commission’s (COGCC) 1200 Series Rulemaking Hearing will begin on November 10, 2020, at 1 p.m. The 1200 series rulemaking concerns impacts of oil and gas operations on wildlife. The hearing agenda can be viewed here. (All time subject to change.) Broomfield is a part of the Affiliated Local Government group (ALG) for this rulemaking. Broomfield’s Open Space and Trails Director, Kristan Pritz, is scheduled to testify on behalf of the ALJ. The ALG is currently scheduled to present this Thursday, November 12th at 2:20, with 10 minutes allotted for that presentation. The Revised Draft 1200 Series Rules were published 10/10/2020. Staff released revised draft 1200 Series Mission Change rules and SBP, the revised draft rules and SBP can be viewed here.	11/9/2020
41	The Colorado Oil and Gas Conservation Commission (COGCC) adopted the 900 series on November 5, 2020, in a 5-0 vote. The new rules, which have not been posted yet, are a significant improvement over the current ones. The rules have a January 15, 2021, effective date and will be finalized on or around November 18, 2020. Next up is the 1200 series (wildlife) rulemaking hearing, which starts next week. Highlights include: - A clear prohibition on the venting and flaring of natural gas that could otherwise be sent to a gathering line. Operators of existing wells that are currently not connected to a gathering line can request permission to flare or vent for up to 1 year. However, all administratively approved venting and flaring must cease by January 15, 2022. - COGCC staff will report to the Commission yearly on cumulative impacts related to oil and gas facilities in the state. As a condition of permitting, COGCC may require an operator to participate in studies related to cumulative impacts from oil and gas facilities.	11/6/2020
42	Hydromulch has been applied to the berms around the Livingston well pad. Hydromulch is commonly used for soil stability and generally contains seeds to assist with the reclamation process. (See photo)	11/5/2020
43	Broomfield inspection staff were notified in the field that a workover rig would be moving to the Baker/Stipanovich well pad area in the next day or two. Read the full public notice for more information.	11/4/2020
44	The video for the Air Quality Monitoring 3rd Quarter Report presentation can be viewed here.	11/4/2020
45	The Air Quality Monitoring 3rd Quarter Draft Reports have been received and are linked below: - Ajax Analytics/CSU - Boulder AIR The third quarter reports will be presented at a virtual meeting on Wednesday, November 4th at 3 p.m.	11/3/2020
46	The 2020 Ozone Season Report, submitted by Extraction Oil and Gas, can be viewed here. This annual report is submitted as a requirement of the operator agreement.	11/2/2020
47	At approximately 12:00 p.m. on November 2, 2020, Broomfield inspectors reported that the Emission Control Device (ECD) was in operation at the Livingston Pad. The ECD was activated for approximately 15-20 minutes as part of routine pipeline maintenance performed by USA Gas Compression. Per the Operator Agreement (Exhibit B, Page 9: Section 20.A.13), Broomfield was not given advance notice of this event because routine pipeline maintenance does not require notification.This event entails the combustion of natural gas which mostly produces carbon dioxide and water vapor as by-products, however, the ECD has a hydrocarbon destruction efficiency rating of 98%. Additionally, the flare must be operated in a manner that will ensure no visible emissions during normal operation. At the time of posting, the air quality sensors surrounding the Livingston Pad did not detect any unusual readings.	11/2/2020
48	On October 27, 2020, Crestone Peak Resources notified staff that the four Bickler wells thought to be temporarily abandoned would be permanently plugged and abandoned. Please read the updated notice here.	10/27/2020
49	Ajax notified staff of testing being executed today on the Apis systems at Thunder Vista and Soaring Eagle. During the test, you may see a significant short-term spike in the VOC Indicator measurement. This is expected and does not reflect an actual VOC Indicator event. The test period will conclude at approximately 5:00 pm today, 10/29/2020	10/29/2020
50	On October 23, 2020, Crestone Peak Resources notified staff of plans to plug and abandon multiple wells beginning October 30, 2020. Please read the full Public Notice here.	10/26/2020
51	Broomfield has approved permits, which will allow cut/cap of the riser and sales line for the Green MA 17-8J and 17-16J wells located generally west of Zuni, between 144th Avenue and 149th Avenue, in Broomfield County. For more information, see the public notice here.	10/26/2020
52	Next week the Colorado Oil and Gas Conservation Commission (COGCC) will begin deliberations on the 900 Series rules, which includes rulemaking on flaring at oil and gas sites. The COGCC agenda for this rulemaking is linked here and the draft 900 series rules are linked here. (All times are subject to change.) On Monday, October 26, 2020, COGCC Staff will present their draft rules to the Commission starting a little after 9 a.m.; Public comment begins at 1 p.m. The Affiliated Local Governments (ALG), of which Broomfield is a member, are currently scheduled to make their presentation next Tuesday, October 27, 2020, at 3:20 p.m. The ALG supports the Environmental Defense Fund's (EDF) position in this rulemaking and the EDF's pre-hearing filings are linked here.	10/23/2020
53	Broomfield’s air quality monitoring team has partnered with EarthView, a Broomfield based business, to field test two methane air sensors. One has been deployed to the Soaring Eagle site, the other has been deployed to the Davis 43-6 location in Anthem Ranch. The initial purpose of monitoring at Soaring Eagle is to compare the methane concentration readings with onsite, research grade instruments operated by Broomfield and Boulder A.I.R. as part of an ongoing monitoring effort. Such comparison studies are needed to validate instrument performance in the open environment. The Davis Well 43-6 is being monitored to ensure elevated methane readings are not present (see latest public notice here). While no elevated methane levels are anticipated at this particular site, plugged and abandoned wells can be found all over Colorado’s Front Range and represent potential sources of fugitive natural gas leaks. This is a first of its kind study to use continuous, long-term 24/7 monitoring to better understand the behavior of these wells and to help inform area residents. All data are preliminary, the EarthView dashboard can be accessed here.	10/23/2020
54	Davis 43-6 Update - The COGCC confirmed today, October 16, 2020, that the current process to address subsurface methane appears to be working as recent testing shows lower levels. See the updated Public Notice for more information.	10/16/2020
55	Plugged and Abandoned - Pad Site Restoration Update: - Restoration of the Brozovich MA 8-8J pad site will begin Monday, October 19, 2020. This well was plugged and abandoned (PA’d) in December 2019 and is generally located southeast of Sheridan and the Northwest Parkway. Work is anticipated to take three weeks. There is an original lease road that goes to the site. Extraction is removing the road base on the lease road as well as any leftover road base where the pad was. In addition, they are going to be bringing in topsoil and will be mulching and reseeding the road/pad site. Equipment on site will be typical construction equipment including an excavator and/or backhoe, a disc, a tractor, and personnel trucks. Inspectors will monitor progress. - Final restoration of the Nordstrom 2-4 site is in process. This well was PA’d in June 2019, and is located northeast of 160th and Sheridan. Seeding and mulch has been completed.	10/16/2020
56	A redline of the draft regulations has been posted and is available here. Please read the public notice for more details. The updated regulations are scheduled to be discussed at the October 20, 2020, Study Session. Watch for the agenda and memo here.	10/15/2020
57	Rulemaking at the Colorado Oil and Gas Conservation Commission (COGCC) continues. The 1200 series rulemaking generally concerns wildlife and habitat requirements. COGCC is accepting written public comment on its 1200 Series rulemaking concerning, in part, wildlife and habitat as related to oil and gas operations. Submit your written comments to DNR_COGCC.Rulemaking@state.co.us. Written comments are due on 11/4/20 at 5 p.m. The proposed rules can be viewed here.	10/14/2020
58	Broomfield Public Health has written a Health Response related to the acetylene-rich plumes the air quality monitoring team continues to investigate. The response can be viewed here. (The original notice from October 7, 2020, on this phenomenon can be viewed here.)	10/14/2020
59	Rulemaking at the Colorado Oil and Gas Conservation Commission (COGCC) continues. The 1200 series rulemaking generally concerns wildlife and habitat requirements and has been rescheduled to the week of November 9, 2020. The most recent agenda for the COGCC rulemaking is linked here, with public comment scheduled for November 10th at 1:05 p.m. and COGCC's staff presentation on the 1200 series scheduled for November 12th at 9:00 a.m. The documents being considered by the COGCC for the 1200 series rulemaking are linked here. The Affiliated Local Governments (ALG), of which Broomfield is a member, are currently scheduled to make their presentation on Thursday, November 12th at 10:10 a.m. The ALG's prehearing statements are linked here. Kristan Pritz, Broomfield's Open Space and Trails Director, has provided input on changes concerning the wildlife provisions and will provide testimony for the ALG.	10/13/2020
60	Yesterday, October 7, 2020, after a day and a half trial, Broomfield Municipal Court found Extraction Oil and Gas, Inc. guilty of violating Broomfield’s noise ordinance for failing to submit a noise modeling study as required by the ordinance. Broomfield issued seven citations to Extraction for this failure, and the Court found them guilty of the violation on each of the citations. The court levied a $300 fine plus $50 fees and court costs for each of the seven violations. Extraction intends to appeal and the sentence has been stayed pending appeal. The appeal will be to the district court in the 17th Judicial District. There will be another three day trial on other noise ordinance violations that will begin December 7, 2020. A link to the press release on this case is here.	10/8/2020
61	Extraction notified our inspectors today (October 8, 2020) of current activity on the Interchange B pads. They are setting tools (Plungers) downhole on three wells on Interchange B. This work is part of routine operations on the wells and should take about an hour per well. The equipment being used is a truck mounted crane and a wireline truck. Work is expected to be completed today.	10/8/2020
62	The air quality management (AQM) team continues to investigate potential causes of the acetylene & benzene rich plumes that have been observed over the course of the summer. The public notice that was originally posted on September 24th has been updated and is available here. The AQM team is investigating further with the COGCC and CDPHE as to potential causes of this phenomena.	10/7/2020
63	Extraction court case update: 1) In the noise cases, trial started the afternoon of Tuesday October 6, 2020. The City and County of Broomfield (CCOB) completed presenting its case the morning of October 7, 2020. Extraction moved for acquittal at the completion of CCOB’s case. The court denied the motion for acquittal. Extraction began to present its defense case the afternoon of October 7th. 2) On June 14, 2020, Extraction Oil and Gas filed for bankruptcy protection to allow it to reorganize under Chapter 11 of the Bankruptcy Code. Early the week of October 4, Extraction and its midstream companies continue to argue the issue of whether Extraction can set aside its contracts with the midstream pipeline companies. This includes the contract with Elevations Midstream which was a subsidiary of Extraction and which operates the pipelines in Broomfield under a contract with Extraction. The City and County of Broomfield is not a party to this separate adversarial proceeding, but did submit a declaration stating that the Operator Agreement requires Extraction to use pipelines in specific easements to transport its oil, gas and produced water. The Operator Agreement does not allow trucks to be used. The next hearing on this issue is October 20, 2020. 3) Broomfield has filed a request with the Court for additional time to respond to a lawsuit that Extraction filed against Broomfield on September 14th in U.S. District Court. This case is substantially similar to the suit filed last spring in state district court but it adds civil rights claims under 42 USC 1983 and a regulatory takings claim. The City & County Attorney has made the following statement with regard to the lawsuit: " I wish Extraction would put the money it is spending on legal fees into efforts to address the noise from its industrial operations that disturb the sleep of Broomfield residents who live a mere 1,000 feet away. Broomfield's noise ordinance is an effort by Broomfield to protect the peace of its residents and such future regulations are expressly allowed by the Operator Agreement. Broomfield will vigorously defend this lawsuit." The complaint can be viewed here.	10/7/2020
64	Crestone Peak Resources has notified the Town of Erie that they will begin a plug and abandon operation within Erie limits (west of Co Rd 5, north of Co Rd 6) on the 'Costigan 6-8-20' well site. According to Crestone, the operation is expected to begin on or around October 19, 2020 and will take approximately 10 days to complete. This activity will include the use of a service rig, temporary tanks, worker pickup trucks and other heavy equipment. Emission controls will be in place during all operations at this site. All work will be done during the day and all access is restricted to the designated access road. More information can be found on Erie’s interactive mapper here.	10/7/2020
65	Three air quality sensors are being temporarily relocated from their current locations (near inactive, future well pads) into more southern parts of Broomfield. This will allow Ajax/CSU to get a better understanding of Broomfield’s urban air quality and how planned and proposed development may change certain air quality markers over time. The new locations at Emerald School, Civic Center, and Lac Amora are collecting data.	9/30/2020
66	On September 28th, the Colorado Oil and Gas Conservation Commission (COGCC) staff presented proposed revisions to the COGCC rules, which can be viewed here. Please read a detailed update on the COGCC Rulemaking here. Broomfield participates in these rulemakings as a member of the Affiliated Local Governments (ALG). Here is a link to the current agenda for the COGCC rulemakings. A reminder that full agendas for the 800, 900, and 1200 Series rulemakings will follow later.	9/29/2020
67	The Air Quality Control Commission (AQCC) just finished the Regulation 7 rulemaking less than a week ago, however, the Air Pollution Control Division is planning to request the AQCC hold another rulemaking this December. This one includes an update to the State Implementation Plan for ozone as well as new proposed requirements for pneumatic controllers. The Local Government Coalition (LGC) of which Broomfield is typically a member, is planning to participate.	9/29/2020
68	On September 28th, the COGCC staff presented proposed revisions to the COGCC rules, which can be viewed here. Here is a link to the current agenda for the COGCC rulemakings. A reminder that full agendas for the 800, 900, and 1200 Series rulemakings will follow later.	9/28/2020
69	Three air quality sensors are being temporarily relocated from their current locations (near inactive, future well pads) into more southern parts of Broomfield. This will allow Ajax/CSU to get a better understanding of Broomfield’s urban air quality and how planned and proposed development may change certain air quality markers over time. Watch for updates here.	9/28/2020
70	Broomfield’s second set of comments on Erie’s Draft Oil and Gas Uniform Development Code were submitted on September 24th and can be viewed here.	9/25/2020
71	Please read the report from CSU and Boulder A.I.R. on the acetylene-related air quality events observed since the beginning of summer. This includes data from the CSU Plumetracker.	9/24/2020 (updated 10/2/2020)
72	Last night the Quality Control Commission (AQCC) unanimously adopted rules that reduce emissions from oil and gas facilities and require more monitoring of emissions. Please read the Public Notice for more information.	9/24/2020
73	Extraction notified inspection staff that they would begin removing the sand cans from the 4 wells on the Livingston pad beginning tomorrow, September 23, 2020. Inspectors plan to be onsite to observe the process	9/22/2020
74	Reseeding of the Shirk Well area is expected to begin this week. See an update on the Shirk Well remediation here. (This plugged and abandoned well is located south of the Northwest Parkway, east of Via Varra, north of Highway 36, and west of South 104th Street.)	9/20/2020
75	Extraction filed a lawsuit against Broomfield on September 14th in U.S. District Court. It's substantially similar to the suit filed last spring in state district court but it adds civil rights claims under 42 USC 1983 and a regulatory takings claim. The City & County Attorney has made the following statement with regard to the lawsuit: "Broomfield has not yet been served with the complaint in this lawsuit, but it looks substantially similar to the complaint Extraction dismissed last spring. I wish Extraction would put the money it is spending on legal fees into efforts to address the noise from its industrial operations that disturb the sleep of Broomfield residents who live a mere 1,000 feet away. Broomfield's noise ordinance is an effort by Broomfield to protect the peace of its residents and such future regulations are expressly allowed by the Operator Agreement. Broomfield will vigorously defend this lawsuit." The complaint was served on Broomfield today and can be viewed here.	9/18/2020
76	Today, September 18, 2020, the COGCC staff presented revisions to the draft mission change rules pursuant to COGCC Commissioner direction, The clean and redline format of the draft rules, can be viewed here. The latest draft of the 600 series rules includes a 2,000 feet setback requirement, but also includes some exceptions to this requirement. The revised Mission Change Rulemaking hearing agenda for September 18 - 24 is available here. Please NOTE there will be no hearings on Wednesday, September 16 and Monday, September 21. Broomfield is a member of the Affiliated Local Governments (ALG), which has presented testimony on several of the rules to date.	9/18/2020
77	An update on the Air Quality Control Commission (AQCC) hearings can be viewed here.	9/18/2020
78	Information has been received from the Colorado Oil and Gas Conservation Commission (COGCC) on the Davis 43-6 plugged and abandoned well. Read the updated public notice here.	9/16/2020
79	Extraction filed another lawsuit against Broomfield last night in U.S. District Court. It's substantially similar to the suit filed last spring in state district court but it adds civil rights claims under 42 USC 1983 and a regulatory takings claim. The City & County Attorney has made the following statement with regard to the lawsuit: "Broomfield has not yet been served with the complaint in this lawsuit, but it looks substantially similar to the complaint Extraction dismissed last spring. I wish Extraction would put the money it is spending on legal fees into efforts to address the noise from its industrial operations that disturb the sleep of Broomfield residents who live a mere 1,000 feet away. Broomfield's noise ordinance is an effort by Broomfield to protect the peace of its residents and such future regulations are expressly allowed by the Operator Agreement. Broomfield will vigorously defend this lawsuit."	9/15/2020
80	Today was the pre-trial conference in the Extraction noise citation cases in Broomfield Municipal Court. Yesterday Extraction's counsel filed a motion to continue the noise citation cases, citing a litany of issues and concerns. In addition, Extraction filed a motion this morning asking for 7 additional days of trial. After an hour or so of argument with Broomfield opposing both the continuance and the longer trial time, the Court made a number of rulings: 1) He denied the motion for additional time and made it clear, again, that the only issue to be heard is whether Extraction violated the noise ordinance and any defenses for failing to comply - not the constitutional or contractual issues Extraction wants to argue; 2) He moved the first trial to 1:30 on October 6 for 3 days and the second trial to the week of October 27; 3) Extraction waived its right to a speedy trial - to ensure that it will not/cannot raise that defense.	9/15/2020
81	Livingston Pad and Interchange A Update - Broomfield inspectors noted a crane onsite today removing the water coolers. All water coolers have been removed. (See photo)	9/15/2020
82	A revised COGCC mission change hearing Agenda for September 18th to the 23rd can be viewed here. Broomfield is a member of the Affiliated Local Governments (ALG), which has testified on noise recommendations and other rules to date.	9/15/2020
83	Broomfield inspectors observed equipment and crews on the Northwest A Pad last week. Today, Extraction gave written notification of what Extraction said was “minor, ordinary course flowline work (that) will begin this week during daylight hours at the Northwest A pad.” (Please read public notice here.) Extraction also stated, “With respect to restarting drilling and completions activity, our plans remain the same in that Extraction does not currently have any plans for any development operations in Broomfield for the remainder of 2020. Extraction will provide a 30 day advance written notice prior to the re-commencement of any drilling or completions operations. However, there may be other minor, ordinary course non-drilling or completions operations from time to time to maintain the existing well sites.”	9/14/2020
84	On September 17, 2020, the Air Quality Control Commission (AQCC) begins its hearing on Regulation 7, which includes new air monitoring requirements for oil and gas operators. Here are links to the September 17-18 agenda and meeting materials. Broomfield will be participating in the AQCC hearing as a member of the Local Government Coalition (LGC), along with many other local governments and CC4CA. The LGC’s pre-hearing statement is linked here. Dr. Jeff Collet will be testifying on behalf of the LGC. His testimony before the AQCC on Broomfield’s Air Quality Program, is currently scheduled to begin at approximately 10:45 a.m. on Thursday.	9/14/2020
85	Broomfield submitted comments on certain sections of Erie's draft oil and gas regulations today.	9/14/2020
86	Broomfield inspectors noted that flowline installation will begin soon at the Northwest A Pad site and is expected to last one to two weeks. Extraction has also indicated they will be placing separators on the Northwest B Pad in the near future. Other than these activities Extraction has indicated in writing that their "plans remain the same for future drilling and completions activity in that Extraction does not currently have any plans for any development operations in Broomfield for the remainder of 2020." Please read the public notice here.	9/10/2020
87	A revised COGCC mission change hearing Agenda for September 16th to the 23rd can be viewed here. Broomfield is a member of the Affiliated Local Governments (ALG), which has testified on noise recommendations and other rules to date.	9/10/2020
88	On September 9, 2020, the Colorado Supreme Court denied Extraction’s petition asking the Supreme Court to intervene in the prosecution of the noise citations Broomfield issued to Extraction. Trial for the citations for Extraction’s failure to submit a noise modeling study or to curtail nighttime operations is set for three days beginning September 21, 2020. Trial on the citations for creating excessive noise is set for three days beginning October 6, 2020.	9/9/2020
89	Registration to offer public comment opens up 8 a.m. on Tuesday (9/8) and will probably fill up immediately for the AQCC's September 17 meeting. The public can sign up either general public comments or to comment specifically on "Regulation 7" (air & carbon pollution from drilling).	9/8/2020
90	The revised COGCC mission change hearing Agenda for September 3-9, can be viewed here. The Affiliated Local Governments (ALG), of which Broomfield is a party, has testified on noise recommendations and other rules to date. The next time the ALG is scheduled to testify is Tuesday, September 8, 2020 at 12:45 pm, advocating for a 2,000 setback. (Times are subject to change.)	9/3/2020
91	Ajax notified Broomfield staff that the trigger system failed to open during the August 23rd air event. Due to this, no additional analysis will be completed. Ajax is working with APIS to determine the cause of the failure and to avoid this from happening in the future.	9/2/2020
92	Ajax is performing testing on sensors in the field. This has created multiple false trigger events. (No air quality events have occurred.)	8/28/2020
93	The Air Quality Monitor Program sensor system at Interchange 01 triggered at 9:30 p.m. on August 23, 2020. The initial report can be viewed here.	8/25/2020
94	On August 12, 2020, the North Metro Fire Rescue District (NMFRD) responded to fire west of the Anthem Ranch in Boulder County (see Newsflash). As a result of that fire, Broomfield requested that NMFRD do a wildland fire survey for Extraction’s Livingston and Interchange A & B Pads, the results of which are linked here. In summary, the surveys completed by NMFRD personnel of the Livingston Pad Site and the Interchange A & B pad sites revealed a Low Risk to the site if a Wildland/Urban Interface fire were to occur in the area. Pad site construction further reduces risk due to the use of compacted rock and other hard surface materials that provide an additional firebreak from surrounding fuels.	8/23/2020
95	The report for the August 11, 2020, trigger event can be viewed here.	8/21/2020
96	The Colorado Oil and Gas Conservation Commission (COGCC) is beginning the Mission Change Rulemaking on Monday, August 24, 2020. The Affiliated Local Governments, of which Broomfield is a member, will be making its presentation on the 300 series rules on Tuesday, August 25, 2020, at 3 p.m., and its presentation on the 500 series rules on Friday, August 28, 2020, at 4 p.m., with these times being subject to change. The agenda for the rulemaking can be viewed here and includes COGCC sign-on information if you would like to listen in to the hearings.	8/21/2020
97	On August 17, 2020, the Colorado Oil and Gas Conservation Commission (COGCC) issued the current draft of the 200-600 rules in the Mission Change Rulemaking. The documents can be viewed here.	8/18/2020
98	Please read a Newsflash regarding the wildfire on the Boulder County open space, west of Anthem Ranch and south of Highway 7, which occurred on August 12, 2020.	8/13/2020
99	The 2020 2nd Quarter Air Quality Reports for Ajax and Boulder AIR have been released and will be presented at the August 18, 2020, Study Session.	8/13/2020
100	The sensor system at Soaring Eagle triggered at 11:04 p.m. on 8/11/20. This was a short-lived event lasting about 5-minutes with a max TVOC indicator reading of 320mV. During the event, there were light winds out of the southeast. Ajax will follow up on this notification when the canister analysis is completed and the canister analysis. Read more here. (NOTE: The sensor system at Wildgrass 01 also triggered at 11:40 a.m. on 8/12/20. Ajax confirmed this was due to field maintenance, and was not an air quality event.)	8/12/2020
101	Broomfield’s consultant, ERO Resources, has completed additional Soil Gas testing for the 2020 program. Please read more here.	8/12/2020
102	Today, August 7, 2020, the COGCC issued a Final Prehearing Order in the Mission Change Rulemaking. Read more here. Please note the COGCC made one correction to the schedule. Item 8 of the order incorrectly states that August 14 is a Monday. The oral sign-up sheet for public comment will be made available on Friday, August 14.	8/7/2020
103	On Saturday August 1, 2020, between 4 a.m. and 6 a.m., an air quality event was observed by the shelter monitoring stations at Livingston and Soaring Eagle. A report on the event can be viewed here.	8/6/2020
104	The Air Quality Control Commission will hold its next meeting on August 20, 2020, at 9 a.m. Here is a link to the meeting agenda.	8/6/2020
105	The COGCC adopted the proposed mill levy rate increase from 1.1 mills to 1.5 mills, which is COGCC’s main source of revenue, at its August 4, 2020, hearing. Read more here.	8/4/2020
106	As reported on July 14, 2020, the Associated Local Government Coalition (Broomfield, Boulder County, Lafayette, Erie, Longmont, Ft.Collins, and NWCCOG) filed its pre-hearing statement in the Colorado Oil and Gas Conservation Commission (COGCC) Mission Change Rule Making. In its response statement, filed with the COGCC on July 31, 2020, the LGC is responding to other party’s statements. Read more here.	8/3/2020
107	August 2, 2020, Update on the Davis 43-6 Testing. COGCC's contractor will begin testing on Monday, August 3, 2020. For more information, see update here.	8/2/2020
108	In May 2019, Broomfield contractor, ERO Resources, tested and found methane in the soils around the Davis 43-6 plugged and abandoned well, which is located on Graham Peak Way in Anthem Highlands. After requests from Broomfield, the Colorado Oil and Gas Conservation Commission (COGCC) repaired the well, however residual methane was still detected in follow up tests. COGCC informed Broomfield that it is anticipated that this additional sampling and vapor extraction pilot testing is scheduled to begin Tuesday August 4th. For more information, see update here.	7/31/2020
109	The COGCC invites the public and stakeholders to attend the Commission’s Mill Levy Rulemaking Hearing on Tuesday, August 4. See more information here.	7/30/2020
110	Today, the Local Government Coalition (LGC), of which Broomfield is a member, submitted its Prehearing Statement to the Colorado Air Quality Control Commission (AQCC) in the current Regulation 7 rulemaking. Read more here.	7/30/2020
111	On July 28, 2020, the Broomfield Municipal Court held an arraignment hearing in the Extraction noise violation cases. Judge Fisher noted that he had previously denied Extraction’s motion to dismiss and he confirmed that his written order dated April 1, 2020, stands. He then ruled on Extraction's pending motion, finding that the automatic stay provisions of the US. Bankruptcy Code do not apply to these municipal court cases. Extraction then entered a plea of not guilty for all nine cases. The cases have been consolidated and set for two three-day trials, the first beginning Sept 21, 2020, and the second beginning October 6, 2020. A pretrial conference is set for September 15, 2020.	7/29/2020
112	Crestone Peak Resources is anticipating starting work on Tuesday, July 28, 2020, to remove the produced water storage tank at the Alaux/Sears Facility. (This facility is located just east of I-25 and south of County Road 6.) From there Crestone will evaluate the next steps that need to be taken to remediate the spill. For more information, including a map of the site, read the newsflash.	7/23/2020
113	Extraction has filed for Chapter 11 bankruptcy and the Bankruptcy Court has issued a stay on many proceedings. Extraction has argued that this stay applies to pending alleged criminal municipal code violations of Broomfield’s noise ordinance by Extraction. On July 21, 2020, Broomfield filed a reply brief in the noise ordinance cases, arguing that the Bankruptcy Court’s stay does not apply to the criminal code violations in Municipal Court. Extraction can file a reply brief no later than July 27. The hearing on this issue is set for July 28, 2020, in Broomfield Municipal Court. If the court agrees that the bankruptcy stay does not apply, then the judge will set the case for trial.	7/22/2020
114	With the adoption of Senate Bill 19-181 by the State, local governments were provided additional authority to adopt oil and gas regulations to protect the public health, safety and welfare of their citizens. Please read more here, including an anticipated timeline for the adoption of the amended local oil and gas regulations.	7/22/2020
115	Please read an update on the proposed work plan for the Davis 43-6 plugged and abandoned well here. (The Davis 43-6 well is located on Graham Peak Way in the Anthem Highlands.)	7/21/2020
116	Additional information was received from CSU/Ajax on the July 11, 2020, air quality event. An updated notice can be viewed here.	7/17/2020
117	Crestone Peak Resources reported an approximate two barrels of produced water that spilled at Crestone’s Alaux/Sears facility in Broomfield. Clean-up will be overseen by COGCC and Broomfield. The Public Notice can be viewed here.	7/16/2020
118	The CDPHE report from the CAMML air quality monitoring lab can be viewed here.	7/14/2020
119	Please view the air program trigger reports for the events on June 25, 2020 (Anthem 01), and July 3, 2020 (Livingston 01 - report updated 7/15/20).	7/13/2020	(updated Livingston 01 report 7/15/20)
120	The‌ ‌trigger‌ ‌notification‌ ‌for‌ ‌the‌ ‌July‌ ‌3,‌ ‌2020,‌ ‌Livingston‌ ‌01‌ ‌trigger‌ ‌event‌ ‌can‌ ‌be‌ ‌viewed‌‌ ‌‌here‌.‌	7/4/2020
121	Please see the Public Notice on the Shirk 21-4D riser removal and reclamation here.	6/26/2020
122	The Apis system at Anthem 01 triggered a canister sample at 2:03 p.m. on June 25, 2020. Ajax has concluded that this does not reflect an air quality event. The increase in the PID signal is from a faulty sensor that will be replaced. The sensor at Anthem 01 is providing data that can capture an actual event most of the time but does have brief periods of erratic signal. The report can be viewed here.	6/26/2020
123	Soil Gas Testing and Davis 43-6 - Please read a status update on the soil gas testing here.	6/25/2020
124	Carlson 1-24 - The COGCC reports (Form 5 and Form 21) on the completed well repairs can be viewed here.	6/25/2020
125	On June 14, 2020, Extraction Oil and Gas (Extraction) filed for bankruptcy protection to allow it to reorganize under Chapter 11 of the Bankruptcy Code. (Read the public statement here.) There is a hearing on Extraction's motion to approve the Debtor in Possession Financing Agreement set for July 14, 2020. If approved by the bankruptcy court, this agreement will provide finances for operations while the bankruptcy plan is negotiated. The Bankruptcy court has already granted a number of motions, including, among others: an order to allow Extraction to continue to pay taxes and fees for the next 21 days, an order to allow payment of insurance premiums, an order to allow payment of mineral interests, an order limiting the trading and transfer of Extraction debt and stock, order allowing payment of utilities, and an order to allow payment of wages, salaries and other compensation. Extraction has filed a notice of bankruptcy and the automatic bankruptcy stay in all it's pending court cases. This includes the noise cases filed in our Municipal Court. The bankruptcy code provides an exception for enforcement of government regulatory and criminal prosecutions. On June 19, 2020, Broomfield filed this motion in Municipal Court advising the Judge that the automatic bankruptcy stay does not apply to the noise citation cases and asking the court to proceed to set the cases for trial. The Judge set the noise cases for arraignment on July 7, 2020 at 9:00 a.m. and advised he would take up the question of the bankruptcy automatic stay at that time.	6/22/2020
126	Ozone information, and a link to the AirLive site, have been added to Broomfield Public Health’s Air Quality Page. This information is also linked on the Air Quality Monitoring page and includes the CDPHE’s daily air quality forecast & conditions.	6/22/2020
127	The report from the June 3, 2020, trigger event at Anthem 02 can be viewed here.	6/19/2020
128	This morning the Colorado Air Quality Control Commission (AQCC) approved going ahead with Regulation 7 (oil and gas) rulemaking, with a proposed September hearing date. AQCC documents associated with the Reg 7 rulemaking are linked here. Broomfield is a part of a local government coalition (LGC) with 34 local governments, participating in the Reg 7 rulemaking. As indicated in the LGC statement of support, submitted to the AQCC today, the LGC early comments are in support of the proposed requirement of controls for flowback vessels and tanks at disposal wells and additional air quality monitoring by oil and gas operators in the pre- and early production stages, but will be requesting more specifics in the rule regarding pollutants to be monitored, approval of a monitoring plan, and enforcement.	6/18/2020
129	Carlson 1-24 site: New casing and wellhead successfully installed. Completion estimated this week, depending on the weather. (See updated public notice here.)	6/17/2020
130	Extraction Bankruptcy Statement	6/15/2020
131	Davis 43-6 site: Road repairs are underway. The COGCC program engineer for orphaned wells has received a draft report from their consultant, which is currently being reviewed. Read more here.	6/12/2020
132	In 2019, Broomfield issued a citation to Extraction Oil and Gas (Extraction) for adversely affecting wildlife in open space. One of its subcontractors working on a legacy well drove heavy equipment over a prairie dog burrow that had been occupied by burrowing owls. On June 10, 2020, Extraction pled "nolo contendere" (No contest) to the municipal citation and will pay a $400 fine.	6/11/2020
133	On June 10, 2020, the COGCC unanimously adopted new rules governing wellbore construction and monitoring. The wellbore integrity rulemaking is one of the rulemakings required by SB 19-181. Read more here.	6/11/2020
134	The report from the June 3, 2020, trigger event at Anthem 02 can be viewed here.
135	An update on the Allison 24-2RC plugged and abandoned well (in Weld County) can be viewed here.	6/11/2020
136	On June 1, 2020 a Noble Energy well on the Weld County Farm (owned by Broomfield in Weld County), was disturbed by livestock in the area, after a fence failed. The well was plugged and abandoned on Friday, June 5th.	6/6/2020
137	Maintenance work has started at the Carlson 1-24 well site. Workover rig and crew onsite. (Please read the updated public notice here.) Work is expected to be complete the week of June 7th, dependent on weather.	6/5/2020
138	An update on the Davis 43-6 plugged and abandoned well can be viewed here.	6/5/2020
139	The COGCC announced the June Wellbore Integrity Rulemaking Commission Hearing, June 10-11. The Wellbore Integrity rulemaking, required by SB 19-181, proposes to improve oversight through the entire lifecycle of the oil and gas well, ensuring protection of groundwater resources. Read more here.	6/5/2020
140	Maintenance work is expected to begin soon at the Carlson 1-24 well site. Workover rig and crew onsite. Please read the updated public notice here.	6/4/2020
141	The trigger canister at Anthem 02 activated at 10:11 a.m. today, see notification here. CSU will analyze the canister and results will be available within 5 working days. With summer and higher temperatures approaching, we do expect to see all the sensors running higher baselines. This potentially means more triggered canisters. Ajax will not adjust trigger thresholds to account for this until trigger canisters are analyzed and can justify setting higher thresholds. All trigger threshold adjustments will be communicated in a timely manner.	6/3/2020
142	ERO Resource Corporation, Broomfield’s consultant, will begin soil gas testing and location verification (using a magnetometer) of the plugged and abandoned (P&A) wells in the Anthem Ranch area. These P&A wells were soil gas tested last year. This will be part of the city’s ongoing maintenance moving forward. Read more here.	6/3/2020
143	The report for the Trigger Canister events on May 25, 2020, at Livingston 02 and 03 can be viewed here.	6/2/2020
144	The report for the Trigger Canister event on May 24, 2020, at Prospect Ridge can be viewed here.	6/2/2020
145	The Anthem 02 sensor triggered today at 10:39 a.m. Read the notification here.	5/29/2020
146	Extraction Oil and Gas (Extraction) is planning to perform maintenance work at the Carlson 1-24 well site in Broomfield, beginning on June 1, 2020. Please read the public notice here.	5/28/2020
147	The CDPHE will be publishing a revised report for the Livingston Pad and statement of errata soon, which corrects a data processing error for the Colorado Air Monitoring Mobile Laboratory. It will be posted under the "Community Investigations" section of the Oil and Gas Health Information and Response Program's website (www.colorado.gov/oghealth). It is anticipated that it will be available by the week of June 1, 2020. While this correction has resulted in revised values for VOC concentrations, it does not change the overall outcomes or recommendations of any of our community investigation reports.	5/28/2020
148	Broomfield is a party to the Colorado Oil and Gas Conservation Commission's (COGCC) upcoming series 200 to 600 rulemaking along with other local governments, known as the Affiliated Local Government (ALF) group. The ALF's initial comments on the COGCC’s 200-600 series rulemaking can be viewed here.	5/27/2020
149	Broomfield hired a third party consultant to create renderings of the Livingston Pad during production. Information on the production equipment was provided to the consultant to assist in the development of the renderings that indicate how the Livingston Pad will look from the Anthem Ranch, Anthem Highlands and Wildgrass neighborhoods.	5/26/2020
150	Read 5/24/2020 Trigger Event Notification.	5/25/2020
151	Read 5/25/2020 Trigger Event Notification.	5/25/2020
152	Read a summary of Broomfield’s State Regulatory Efforts here.	5/22/2020
153	On May 18, 2020, Extraction filed a notice of voluntary dismissal of its lawsuit against the City and County of Broomfield. On May 19, 2020, the court entered the order granting dismissal. This concludes the suit that Extraction filed against Broomfield in March, alleging breach of contract, along with other claims.	5/18/2020 updated 5/19/2020
154	United Pad - Updated Notice of Spud	5/18/2020
155	Alternate Truck Route - Extraction Oil and Gas	5/18/2020
156	Public statement on Extraction Oil and Gas	5/15/2020
157	On March 30, 2020, Extraction filed a lawsuit for declaratory judgment, breach of contract, and injunctive relief alleging that Broomfield has been using its regulatory and police powers in bad faith to shut down Extraction’s operations. Extraction filed its Second Amended Complaint on May 1, 2020. Extraction added a civil rights claim under Section 42 USC 1983 alleging impairment of contract and violation of equal protection. Extraction also added a claim for damages and an injunction alleging that Broofmield violated the Colorado Constitution's prohibition against impairment of contracts and retrospective legislation.	5/12/2020
158	Updated notice regarding spudding on the United Pad.	5/8/2020
159	The Air Quality Report on the April 30th trigger event can be reviewed here.	5/7/2020
160	Extraction provided notice spudding to begin on the United pad as early as May 18.	4/17/2020


1	Complete
2	In progress
3
4	Status	Complete?	question	date rec'd Newest to Oldest	submitted by	date of response	answer Staff: If you link to an answer, please confirm the sharing settings are "anyone with the link can view"	outstanding issues/timeline for answer	#	who is responsible	Follow up 1	Follow up 2	Follow up 3	Follow up 4	Follow up 5

5			[RESIDENT] has been experiencing some rumbling sounds (she says it's like an earthquake and won't stop) and her address is XXXX W 150th Ct, Broomfield, CO over by the Livingston pad but that pad hasn't been active in quite a while and has completed the fracking stage a while ago and is now in production with the 18 wells. What other reasons could she be experiencing constant rumbling sounds in that area? I haven't heard from any other neighbors in that area but didn't know if staff was receiving reports of rumbling? The rumbling comes and goes. It may last for a few days and stop. From what I understand about fracking, the oil company has to push compressed air into the shafts in order to force the natural gas out.	3/5	Resident via Heidi Henkel	3/8	With regard to your email below, an oil and gas inspector investigated the 150th court area today to see if he could find the source of the "rumbling". There is no activity on the Livingston Pad today. Also, he did not detect any significant noise at the time of his field inspection. There is however construction equipment not far from the location on Lowell. It is not uncommon for idling heavy equipment diesel engines to produce a low frequency "rumbling" noise. From Public Works: We've had boring crews along 144th Ave working on street lights and signals for quite awhile, but I'm copying [STAFF]. Response from staff: We recently added rip rap (rock) to the ends of the FRICO ditch culvert at 149th Ct. The rock placement at 149th Ct was completed last week (Thursday). The rock will be grouted today beginning at noon. There was no work occurring on Friday and I would assume this morning until the grout arrives. When I was out there, they were placing the boulders with a small/midsize excavator. It could have been the boulder delivery however, that would have been a short duration and would have been earlier in the week. We haven't received any rumbling complaints along Dillon/144th or started any new work items that would cause it. As Katie mentioned, we've been boring fiber and street light conduit along the corridor for months.
6			JULY 2020 Below
7			What is causing the steady hum of the equipment that can be heard at 1000 feet from the pad to the south and in some of the Anthem Ranch residences to the north? Is there anything besides the compressors that could be causing this hum? Is the source of this hum different than what is causing the noise impacts felt by some Anthem Highlands and Wildgrass residents further away? What else can be done to eliminate this noise so that residents do not need to listen to it for 30 years?	7/24	Jean Lim	7/24	Noise from compressors on the Livingston Pad is what is reported as the only pad noise by Broomfield’s inspectors. As you know, Broomfield has requested that Extraction put in place different sound walls around the compressors that our research indicates may have a measurable impact on dBC noise. Extraction has indicated their willingness to do this. The latest response from Extraction today on this issue is: "Our noise consultants are planning to reach out this next week to begin reviewing frequency data. The removal of sound wall equipment should be finalized this next week which will help for discussion of a monitoring plan. This determination will then drive what permanent mitigation strategies around noise are necessary and will be most impactful." Staff is continuing its work on this issue. We have received a noise complaint from only one person in the last few weeks. If you are receiving others, it would be good to know the general locations so that these can be investigated with sound equipment.		0.5
8			MAY 2020 - Below
9			A homeowner reported that the pipe clanging was loud near the United Pad at about 10 pm and said there would be a written and phone report filed. Were the reports filed and did the night guard do a reading?	5/23	Jean Lim	5/24	The noise complaint on Friday night was received before 10 p.m. so the night staff did not respond to the location. The Broomfield inspector noted the complaint to Extraction staff on Saturday during the site visit. They stated they would be more aware of the noise created by their activities. There were no noise complaints received Saturday night.		1
10			Thank you for talking to the COGCC about the possible noise issues in 3 - 5 years and posting the details on the Oil and Gas Dashboard. To summarize their response: yes, there could be additional gas lifts and pump jacks needed by Extraction on the site in 3 years and Extraction is not required to notify COGCC or CCOB when they add them. So we can either wait to have a noisy surprise when the Livingston wall is down and the added equipment starts in a few years or, if Extraction is ever forced to do a noise study, can we have Extraction model that later noise situation also?	5/15	Jean Lim	5/18	Broomfield discussed the equipment that could be installed at the Extraction sites in 3-5 years with the COGCC. This equipment could consist of either plunger lifts, gas lifts or possibly even pump jacks, and is determined by the operator depending on what is needed to achieve well production. COGCC does not have specific requirements as to what equipment is installed and they do not require advanced notification. A brief description of this equipment based mostly on information from COGCC is provided below. Plunger lifts operate off of the well formation pressures and do not make much noise. Extraction's legacy wells in Broomfield all operate off of plunger lifts and the Broomfield inspectors have noticed very little noise from those. Gas lifts would require the well gas to be compressed at the ground surface and then injected down the wellbore to help lift the production fluids from the well. The gas compression units could generate noise but COGCC indicated this noise could be mitigated. Pump jacks move rods up and down in the wellbore that operate downhole valves. The pump jacks are operated off of motors which would be electric motors on the Extractions sites in Broomfield. These motors could generate some noise but COGCC indicated this noise could be mitigated. The type of equipment that will be used in 3-5 years has not been specified.		1	T.Y. & E.P.
11			I would like to see the documentation from before the OA and CDP were approved where staff or the Task Force evaluated the information provided by Extraction for both the natural gas compression stations, and the produced water compression stations including: • engine specs • orientation of sound generating equipment away from residences • Use of the best technology, in this case quietest systems • Consideration of improved exhaust mufflers and intake silencers • Permanent Sound walls and/or housing structures The real question is, did Extraction provide this information to Broomfield before we signed agreements? In prior discussions with Vibratech, we know that the monitoring at 1000' from the site near roadways may not have been the best strategy. And we have already found that, even during the extremely loud fracking operations, the 65 dBC limit was rarely sustained for over 15 minutes - at least not by the time the inspector was on site. Not to mention that the frack operation noise levels remained below the baseline noise limits which is seemingly impossible, if our baseline was established correctly. I don't think we can solve the noise problem by sending our inspector out to take readings each night. The problem is one of noise entering homes and causing more of a vibrational, low frequency drone. So here is what was presented to me as one possibility... Take Extraction's own marketing and request that they uphold what they've already promoted: Extraction's Above and Beyond Report: https://extractionog.com/wp-content/uploads/2020/03/2019-XOG-ESG-Report_March-2020.pdf -- Tankless Facility Designs: Extraction’s Broomfield Development Plan is built around Tankless Facilities that are a stepchange for the oil and gas industry— multi-well production pads that have near-zero emissions: • Because of our air-tight, closed-loop system that captures 99.9 percent of air emissions, Extraction’s facilities are considered some of the most environmentally friendly operations in the state. • Oil, gas and produced water flows directly through Extraction’s own pipelines to Extraction’s Central Gathering Facility and Compression Station in Weld County. • Tankless Facilities eliminate venting, millions of miles of truck traffic, noise, dust and visual impacts. -- If Extraction is marketing that their Broomfield operation's tankless facilities eliminate noise, then lets hold them to that. Even our inspectors have heard the noise. Anyways, I would appreciate feedback on how we can better address these very real noise concerns. Perhaps we could initiate a conversation with a company that specializes in noise mitigation methods, see what they recommend, and then try to get Extraction to implement these noise mitigations that work, rather than their 20' sound wall. Or can we have our inspectors enter the homes of residents when they are able to?	5/13	Laurie Anderson	6/24	After a exhaustive review of the data and literature, we believe we have identified a source of low-frequency noise that may be causing the public health impacts that are being reported. Strategic Initiatives, Public Health, CCOB's noise contractor (Vibra-Tech) and Legal have prepared a letter to Extraction O&G counsel that they work with us to mitigate the issue under BMP 31 of the Operator Agreement. Reference documents can be seen here: - Noise study and literature review - Public health investigation - Report from Vibra-Tech EXO is planning maintenance on the compressor station in mid-August, which will provide an opportunity to measure before and after noise data at the suspected source. Vibra-Tech and EXO's noise contractors are working on design of an experiment to test this and take data.		20	A.V. from Strategic Initiaitves, M.W. from Public Health and Legal	From Vibratech RE dBC testing in homes: For now I would suggest following COGCC 802 guidelines for measuring dBC at 25 feet outside the house. In the event there is measured dBC noise above 65 for an extended period, further building response testing may be required to demonstrate dBC noise is responsible for vibration felt in the house. VT can do this type of testing if required but for now I dont believe its warranted for the cases I have reviewed for CCOB. Staff is researching noise mitigation companies and other communities that have dealt with this issue.	Extraction has been contacted and has stated that they will work with their noise mitigation consultant (in possible collaboration with our noise consultant Vibra-Tech) to isolate the problem and consider remedies. From Chandler Newhall on 7/14/20: It is disappointing to hear that Broomfield is still receiving complaints. We will begin conducting frequency monitoring in an effort to understand this issue and the potential cause, and we will get back to you as quickly as possible. In the meantime, we would like for our noise consultants to be able to reach out to your consultants so we can better understand the frequency data you’re referencing and how this noise is being created. We are not opposed to the idea of a controlled shutdown and will look into the additional mitigations noted in your email.	UPDATE SEPTEMBER 3 - EXO has indicated they are 1) unwilling to shut down the compressor station 2) unwilling to tune the fan blades to resonate at different frequencies and 3) won't allow us to take any measurements close to the station. I'm seeking $11k to do a source attribution study, which would look at all potential noise sources in CCOB (including the Livingston pad) as well as receptor locations. We are waiting for legal clearances and follow up from the contractor (Hankard Noise & Environmental)
12			Regarding 5/9 question and response: The construction at Anthem Reserve has not conflicted with the operations at Livingston (and certainly not in the middle of the night), nor do I see any documentation for why we added another 3.5 dBA to the averages where 4 dBA was already added. I also don't see why we would do anything in Extraction's favor when our residents have suffered due to elevated noise, but.rather we could begin to look at our noise data from the standpoint that the dBA maximum is 62.5 dBA at Livingston North (and not 66 dBA).	5/13	Laurie Anderson	5/14	The dBA thresholds appear to be derived from a document (linked at right) written by Broomfield's noise consultant Vibratech. From the document: L90 and L95 are most commonly used to describe ambient sound levels, while L99 may be used to eliminate infrequent peaks in the data. For this data set, LN 99 = 62 dBA indicates that 99 percent of the 15 minute LEQ values were 62 dBA or less, while 1 percent of the values were greater than 62 dBA. Suggested dBA Threshold Level LN 99 + 4 dBA Liv N=66, Liv S=63, Liv E=69		1	AV	Vibratech report: https://drive.google.com/file/d/1P65xt7TkeY1QowGGvZ_ae4iCGBbFMj6e/view?usp=sharing
13			a knowledgeable resident told me that it is common practice that Extraction would add noisy lifts to aid flow in 3-5 years. Can someone investigate that?	5/11	Jean Lim	5/14	Broomfield discussed the equipment that could be installed at the Extraction sites in 3-5 years with the COGCC. This equipment could consist of either plunger lifts, gas lifts or possibly even pump jacks, and is determined by the operator depending on what is needed to achieve well production. COGCC does not have specific requirements as to what equipment is installed and they do not require advanced notification. A brief description of this equipment based mostly on information from COGCC is provided below. Plunger lifts operate off of the well formation pressures and do not make much noise. Extraction's legacy wells in Broomfield all operate off of plunger lifts and the Broomfield inspectors have noticed very little noise from those. Gas lifts would require the well gas to be compressed at the ground surface and then injected down the wellbore to help lift the production fluids from the well. The gas compression units could generate noise but COGCC indicated this noise could be mitigated. Pump jacks move rods up and down in the wellbore that operate downhole valves. The pump jacks are operated off of motors which would be electric motors on the Extractions sites in Broomfield. These motors could generate some noise but COGCC indicated this noise could be mitigated. The type of equipment that will be used in 3-5 years has not been specified.		4
14			A resident pointed out to me that the upper noise limit for Livingston A should be 62.5 dBA, and not 66 dBA which was previously noted as the max allowable. This could change the number of actual violations considerably, so this is critical. The ENRG noise study for Livingston North is linked here to the right. 72-Hour dBA Average (Leq): 58.5 dBA Allowable Noise Level: 62.5 Also from the ENRG report: "As shown on Table 1, ENRG and XOG have measured and reported a 72-hour ambient noise level of 58.5 dBA. Therefore, based on the CCOB Operator agreement the permissible allowable of 62.5 dBA will be utilized during operations..." The other two noise monitoring stations may have a similar higher than required limit set. Or am I missing something regarding how we ended up with 66 dBA as the limit, instead of 58.5 dBA + 4 dBA?	5/9	Laurie Anderson	5/12	Thank you for bringing this to our attention. In response to your questions, we went back and reviewed correspondence with Extraction's noise consultant, ENRG, and with Broomfield's consultant, Vibra-Tech, to better understand how the noise limits were determined. On June 6, 2019, Broomfield received a letter from ENRG expressing their concern that their ambient noise studies did not account for the noise that would be generated by the Anthem Reserved development that would be going on simultaneously with development at the Livingston Pad. See the June 6th letter to the right in link. In response, Broomfield asked our noise consultant, Vibra-Tech, to take these concerns into consideration for determining the appropriate noise limits at 1000 feet from the sound walls. Consequently, Vibra-Tech installed three monitoring stations at 1000 feet from the sound walls around the Livingston pad and monitored ambient noise levels from 5/25/2019 to 6/16/2019. The evaluation and subsequent recommendations for the noise limits for each of these three monitoring stations is presented in the attached document, and includes the 66 dBA limit for Livingston North.		2		ENRG Study: https://drive.google.com/drive/folders/1sL2YAad__H2gKXrn_ONYUVue55vNXrhv	Ambient Noise Studies: https://drive.google.com/drive/folders/1sL2YAad__H2gKXrn_ONYUVue55vNXrhv	Davis Letter RE Anthem Construction: https://drive.google.com/file/d/1P4cXVm2GZdBdU4G34x0zVMcJ3q1Qegw1/view?usp=sharing
15			In reference to Lim 4/28 question - https://drive.google.com/file/d/1OM2MyPDskhWSbp2xfu9X4wt13J1Duq80/view - what is line 731? I think this comment is referring to me, but I do not recall referencing a line item. Also, I did not indicate that this would cause structural damage. This is a loud noise that is irritating, and I was under the impression that after fracking,... and then surprise coiling and tubing,.. that Anthem residents would finally get relief from the noise. I was shocked to hear the noise continuing in flowback... and then more concerned that we were not aware of all this noise generating equipment they were bringing on site, or that they had planned a permanent sound wall which clearly indicates that Extraction is well aware that they anticipate generating considerable noise.	5/9	Laurie Anderson	5/9	The report's reference is to a 4/28 question I asked about the high noise readings at Livingston South when Tami responded to your noise questions by sending noise readings from the sensors (4/27 Original email from you titled "Mitigating Noise On Compressor Stations," Tami's response included: Here is a link to the sound readings spreadsheet with the last two night's data.) My 4/28 question is on Line 16 on the Oil and Gas Dashboard, Noise. Vibratech's response in the report is that the Livingston South noise is not sustained at a high level and there would have to be a controlled study to prove anything at the required distance close to a home.		0.5	Jean Lim response
16			In that last graph, the dBC levels were approaching 90, so not sure why they picked a reading in the middle of the night that was much lower to state that it wasn't a problem?	5/6	Jean Lim	5/9	See answer on low-frequency noise above.		3	A.V.
17			Has the City requested the noise study? Certainly Extraction shared with the City the plans to run large engines 24/7 for flowback and production, right? If yes, we must have those specs to have agreed to them. Can we get those engine specs... short term produced water related engines... longterm production related engines?	5/6	Guyleen CASTRIOTTA	5/7	You are correct that the CDP did include the initial layout drawings of the permanent equipment to be installed for the production facilities at the pads. These plans were reviewed and questions were asked as part of the CDP approval process. While the sales gas compressors were shown on the drawings, the water coolers were not, possibly because either they are not considered permanent equipment and mostly necessary for flowback. Broomfield is currently in the process of trying to obtain additional information for the water coolers and will pass that information along when it becomes available.		1		List of all equipment on pad: https://drive.google.com/file/d/1QH788i1pdoX56zR_lBg0-WoOcHVmGMDn/view?usp=sharing	Water cooler Spec: https://www.alfalaval.com/globalassets/documents/products/heat-transfer/finned-tube-air-heat-exchangers/product_leaflet_ace_model_a_en.pdf
18			1) What information did Extraction provide to Broomfield regarding production/flowback noise before the OA was signed? Did they provide noise studies, engine specifications, sound mitigation methods, or nothing indicating there would be associated noise? 2) Which staff, Councilmembers, Task Force members, or subcontractor with a background in noise analysis reviewed the provided information for noise? And what was the outcome of their decision? 3) Or did our team at the time have no indication that we should be concerned about noise? Was Broomfield supposed to pull this detail from a site drawing and determine for themselves this would be a problem without any indication from Extraction at the time to be concerned?	5/6	Laurie Anderson	7/7	Broomfield inspectors have identified the fans on the water coolers as a potential source of the noise that citizens may be hearing from the pads. The cooler fans are manufacured by Ace, and the specifications for a Model A Ace fan can be found at link to right. Broomfield was aware of the use of the sales gas compressors because they were included in the Comprehensive Drilling Plan (CDP). The use of the water coolers, while not specifically called out in the CDP, were added as part of the Next Gen flowback methods being utilied by Extraction at the Broomfield sites to reduce volatile organic compound (VOC) emissions. The purpose of the coolers is to cool the flowback water coming out of the wells before it enters the water pipeline which is poly lined. While traditional flowback methods may have eliminated the need for cooling the water, the tradeoff would have been potentially higher emissions, more truck traffic that comes with exhaust emmissions and diesel engine noise, and possibly even a greater potential for spills because of the use and transpost of temporary tanks for traditional flowback methods. (see linked documents >>>>)		20		List of all equipment on pad: https://drive.google.com/file/d/1QH788i1pdoX56zR_lBg0-WoOcHVmGMDn/view?usp=sharing	Water cooler Spec: https://www.alfalaval.com/globalassets/documents/products/heat-transfer/finned-tube-air-heat-exchangers/product_leaflet_ace_model_a_en.pdf	We requested that VibraTech review two concerns that were indicating low frequency vibration and rumbling. The data from these concerns was cross referenced with noise study data from before the Livingston Pad was constructed. From the report: Ambient testing conducted by ENRG on Jan 18-21, 2019 at Livingston North, which is the same location of the Vibra-Tech remote station, over a 72 hour period the dBC noise levels were greater than 65 dBC for 49% of the time before the Livingston Well pad was constructed. During this study, night time (19:00 – 06:59) dBC levels ranged from 54 to 77 dBC. The 72 hour average dBC noise level was 71.1 dBC. Based on this, it appears that there were and still remain many sources of dBC noise in this area prior to well pad development. The main source of dBC noise in this area may be due to traffic noise as the highway is located much closer to the remote sound level meter and the neighborhood to the north compared to the well pad. In addition, in order to potentially cause structural resonance and constant vibration of a structure, the low frequency noise may need to be constant, with an amplitude, frequency, and duration sufficient enough to keep the structure responding over an extended period of time. The dBC readings at 1000 feet do not indicate long term dBC noise at the time of the complaint in question. See Figure 1. Based on this location, it seems daytime dBC noise levels may be related to increased traffic noise during the day. A pattern of decreased dBC levels is apparent during night time hours. The full report is linked to the right.	Full report linked here: https://drive.google.com/file/d/1RwzpG_j3Ei6ZngF-w4lo9Uh2vpo6cwcc/view?usp=sharing
19			Would it be prudent for Broomfield to request a noise study from Extraction since this is a new phase. This should include: Nose study for Flowback with equipment on-site now Noise study for Production once the produced water compressors are removed	5/5	Laurie Anderson	5/7	Question 1 - The Comprehensive Drilling Plan (CDP) provides: (1) ambient noise monitoring data and modeling studies for each pad in Sections E and M; (2) a list of expected electrified equipment on the pad in Exhibit C of Section U (page number 1272 of this link); and (3) Bales, and Sound Wall information in Section V (beginning on page number 1286 of this link). The noise modeling presented in Section M focuses on drilling and hydraulic fracturing operations. The list of electrified equipment in Section U does not provide equipment specifications. Also, new ambient noise studies were performed after the CDP was completed and before work on the new well development began. The new ambient reports for the Livingston Pad can be found here. (SEE LINKS TO RIGHT) Question 2 - The ambient noise reports were reviewed by Broomfield staff in combination with Broomfield's noise consultant (Vibra-Tech). This review included an evaluation of the methods, monitored locations, and data collected for the ambient reports. The outcome was the selection and or confirmation of the allowable noise levels for each pad. Question 3 - Broomfield was very concerned about noise at the time and that is why we contracted with Vibra-Tech to help us understand noise and to install monitor stations around the pads to monitor noise levels. Broomfield made their best efforts prior to signing the operator agreement to understand what equipment is responsible for making noise at oil and gas sites. This included all of the effort that went into the Comprehensive Plan update. Consequently, Best Management Practices such as electrified equipment and quiet fracking fleets were incorporated into the operator agreement.	Additional response on noise studies, will be provided soon.	2	Strategic Initiatives and legal	Sections E & M: https://drive.google.com/file/d/10fnWvMwztxbaGw4NjjEmPm96DNvuwtlp/view	Exhibit C Section U: https://drive.google.com/file/d/1oeT8RF5fpTzp2m5qD1gv9eVQSbDtwjaF/view	Section V: https://drive.google.com/file/d/1oeT8RF5fpTzp2m5qD1gv9eVQSbDtwjaF/view	Ambient Reports: https://drive.google.com/open?id=1sL2YAad__H2gKXrn_ONYUVue55vNXrhv
20			Noise complaint near Zuni and 144th ave. For the last week, excessive and VERY LOUD noise reaching INSIDE my home at night. between midnight and one AM. I am officially complaining about the noise from the well and drilling. This entire area of Broomfield is under perpetual assault from the well noise. Rather than having less noise after 10 PM, the noise ramps up after dark.	5/5	Laurie Anderson	5/11	We requested that VibraTech review two concerns that were indicating low frequency vibration and rumbling. The data from these concerns was cross referenced with noise study data from before the Livingston Pad was constructed. From the report: Ambient testing conducted by ENRG on Jan 18-21, 2019 at Livingston North, which is the same location of the Vibra-Tech remote station, over a 72 hour period the dBC noise levels were greater than 65 dBC for 49% of the time before the Livingston Well pad was constructed. During this study, night time (19:00 – 06:59) dBC levels ranged from 54 to 77 dBC. The 72 hour average dBC noise level was 71.1 dBC. Based on this, it appears that there were and still remain many sources of dBC noise in this area prior to well pad development. The main source of dBC noise in this area may be due to traffic noise as the highway is located much closer to the remote sound level meter and the neighborhood to the north compared to the well pad. In addition, in order to potentially cause structural resonance and constant vibration of a structure, the low frequency noise may need to be constant, with an amplitude, frequency, and duration sufficient enough to keep the structure responding over an extended period of time. The dBC readings at 1000 feet do not indicate long term dBC noise at the time of the complaint in question. See Figure 1. Based on this location, it seems daytime dBC noise levels may be related to increased traffic noise during the day. A pattern of decreased dBC levels is apparent during night time hours.		6	Strategic Initiatives and legal
21			Requesting follow-up per 4/27 question on engine specfication and additional questions - provide specifications for the "temporary" equipment that is being used for the produced water, and when that equipment will be removed.	5/4	email from resident	5/4	Resolved. Was related to a construction event on 144th back in February and a technical glitch made the email come in as recent even though resident confirms this was resolved in February. The sender stated in a later email to councilmember Henkel that the email had been sent a month ago. The noise had been investigated due to another complaint and was determined to be road construction related.		0.5	Strategic Initiatives
22			Will there be two sales gas compressors on each of the 6 pads for a total of twelve gas compressors?	5/4	Laurie Anderson	5/4	1)Unable to acquire specifications from a visual observation. Might need to ask XOG. 2) The equipment will be removed whenever water production declines and it is no longer necessary to cool the water. It is not a function of time.There are currently 2 water coolers on the Livingston site. Eventually one will be removed, and then the second will turn on and off as needed. Until water is minimal there will probably be at least 1. They could eventually remove both or leave 1 on site and use as needed.		0.5	Strategic Initiatives
23			The Livingston Site was as loud last night as it was during fracking. 6AM.	5/4	Laurie Anderson	5/4	No. Some sites are commingled to utilize one production facility. For example all production equipment for Interchange A and B are located at Interchange A and use the same vessels/scrubbers and compressors. Same thing goes for NW A and B. From the CDP it appears that there will be a total of 8 compressors as following from East to West: Interchange A (2) United (2) Northwest B (2) Livingston (2) Same thing goes for gas compressors as a function of production. Initially large amounts of hydrocarbon are being handled at the production facility. As volume declines it is possible to reduce the amount of compressors being utilized from 2 to 1 speculating 3-5 years here. Unlike the water coolers I would imagine 1 will be permanent, but will still turn on and off as needed to bring gas pressure up to equalize to the line.		0.5	Strategic Initiatives
24			What is Broomfield doing to follow-up on noise concerns associated with the Livingston Pad during flowback?	5/1	Laurie Anderson	5/1	Link to email response		0.5	Strategic Initiatives
25			APRIL 2020 below
26			The reading at 1:24 overnight at Livingston South when the night staff heard "slight rumbling noise from pad" was 64.07 dBC, which is of course close to the 65 dBC limit in the noise ordinance. Does that warrant more monitoring overnight?	4/30		5/5	The protocol is: If a noise complaint is received, staff will perform a preliminary review. If the the complaint has validity (after checking noise, geolocation, sound bites & wind data), staff will forward to noise consultant and/or COGCC for further analysis & determination if a vioilation of code or ordinance was broken. If noise consultant determines there is enough evidence that a code or ordinance was broken, staff will forward the complaint to COGCC and/or Broomfield's legal department (as appropriate).		4	Strategic Initiatives
27			The reading at 1:24 overnight at Livingston South when the night staff heard "slight rumbling noise from pad" was 64.07 dBC, which is of course close to the 65 dBC limit in the noise ordinance. Does that warrant more monitoring overnight?	4/28	Jean Lim	4/28	Our standard process is to send to Vibratech to review potential actionable recordings,. as they have to be the expert witness. We will do that in this case and take it on to legal if Jon Ferdinand of Vibratech thinks he can testify. We will do that. One thing I would note is that our staff listens to all the recordings, which were linked in the matrix I sent you. There is some traffic in that recording, which typically makes it difficult to defend that oil and gas contributed solely to the elevated decibel level. I was going to ask Laurie if she was measuring dbc or dba on the picture of her meter that she sent, where she was located and what time of day?	Jon @ Vibratech is currently reviewing the data, we are awaiting follow up.	0.5	Strategic Initiatives	Incident on 4/28: In order to investigate specific instances of dBC low frequency noise complaints of increased human perception and also structure response such as building resonance and vibration, a controlled low frequency noise impact analysis should be completed at the specific location of concern. This analysis should consist of controlled and specific noise and vibration measurements at the point of complaint to quantify airborne and ground borne noise and vibration inside of a structure. As per the ambient testing conducted by ENRG on Jan 18-21, 2019 at Livingston South, 20% of the measured dBC ambient data exceeded 65 dBC prior to the well pad development. Because of this, careful and controlled testing should be completed to determine the contribution and influence that the well pad has on the existing dBC noise environment. Based on the permanent remote dBC monitoring station at Livingston South, which is 1000 feet from the sound wall, the dBC readings at the time of concern are under 65 dBC, and would be even lower the further you get from the remote station. Low frequency noise attenuation may be as much as 6 dB per doubling of distance between the noise source and the receptor location. In addition, in order to potentially cause structural resonance and constant vibration of a structure, the low frequency noise may need to be constant, with an amplitude, frequency, and duration sufficient enough to keep the structure responding over an extended period of time. The dBC readings at 1000 feet do not indicate long term dBC noise at the time of the observation in question. Report
28			Can we check on new reports of low frequency noise that residents at the top of the hill in Anthem Highlands, believe is coming from Livingston. There must be equipment generating significant noise, or they wouldn't be constructing the sound wall. Do you know the specifications (make, model, ratings, etc) for the compressor and other equipment that is running behind the new 20 ft sound wall? Are they using engines powered by pistons or turbines? Are the above ground pipes wrapped with insulating materials?	4/27	Laurie Anderson	4/28	An extensive low-frequence noise study was commissioned, the final report can be viewed here. The study was unable to establish a connection between noise emanating from the pad and a receptor location in Anthem Highlands neighborhood. Department staff will continue to investigate reports of low-frequency noise and research the issue to better understand the possible connection between the two.	Staff is researching noise mitigation companies and other communities that have dealt with this issue.	1	Strategic Initiatives	From Vibratech RE dBC testing in homes: For now I would suggest following COGCC 802 guidelines for measuring dBC at 25 feet outside the house. In the event there is measured dBC noise above 65 for an extended period, further building response testing may be required to demonstrate dBC noise is responsible for vibration felt in the house. VT can do this type of testing if required but for now I dont believe its warranted for the cases I have reviewed for CCOB. Staff is researching noise mitigation companies and other communities that have dealt with this issue.
29			MARCH 2020 - Below
30			Can the compiled air, health (compiled complaints), and sound data from the XOG project be sent to me please?	3/5	Heidi Henkel		The aggregate data of health concerns will be sent to Councilmember Henkel. Draft document is being reviewed internally. (On hold)	SI - document in review PH - work on redacted info	5	Public Health and Strategic Initiatives	Noise information sent to CMO for review.
31			Will residents who filed complaints and requested noise readings ever be sent those readings?	3/4	Jean Lim	3/5	Staff will be posting the noise readings weekly. A draft document is being reviewed internally. (on hold)	Document in review	1	Strategic Initiatives	SI will post the data weekly, once format is approved
32			Is the night guard being dispatched to Adams County?	3/4	Jean Lim	3/5	If noise complaints are received from adjacent Adams County residents, the night staff will respond. As of March 5th, no noise complaints have been received at night from Adams County.		1	Strategic Initiatives
33			Can COGCC pursue clear dBC noise exceedances?	3/4	Jean Lim	3/5	The COGCC stated that they reviewed everything and, with the exception of a couple of spikes which appear to be wind influenced, everything appears to be compliant and they don't see any exceedance of COGCC rules.		1	Strategic Initiatives	Tami shared these readings with COGCC and made the request that they need to respond to the exceedances on 1/24.
34			What is the status of Vibratch providing sound bites?	3/4	Jean Lim	3/5	The link to the Vibra-Tech website was added to the updated Oil and Gas webpage on April 29, 2020.		1	Strategic Initiatives
35			What is the status of the Vibratech model with correct elevation data?	3/4	Jean Lim	3/5	Vibratech is rerunning the model with elevation data.	received by legal	1	Strategic Initiatives
36			When will the 3 new stationary noise monitors be installed closer to neighborhoods?	3/4	Jean Lim	3/5	The three stationary noise monitors were installed the first week of March.		1	Strategic Initiatives
37			CDP Plan for Noise – is this part of the project being executed as described below in the CDP?	2/24	Cristen Logan	2/25	link to answer	Q's 2-5	1	Legal	question 1 of 5
38			Tami-do we know what was causing the horrific noise all weekend and what is being done to stop it?	2/24	Guyleen Castriotta	2/24	It is likely the three sets of mill out/tubing equipment that is currently operating on site. The City Attorney has requested that Extraction use one unit for this process instead of 3. We did receive 8 complaints on Friday night and 16 on Saturday night. Our contract inspectors were on site and taking readings at these complaint locations and our consultant is reviewing the data now. Ultimately, the CIty Attorney's Office will make a determination as to whether the evidence is sufficient to pursue noise violations in Court. We have been citing Extraction every night.that their operations continue overnight in violation of Broomfield's Noise Ordinance and the hearing on those citations is March 3rd.		0.5	Strategic Initiatives
39			Would it be possible to reinforce the public disturbance noise regulations in Broomfield?	2/24	Jamel Benbrik	2/25	link to answer		1	Strategic Initiatives
40			Were there any noise alerts on the noise monitors stationed at 1000 feet from Livingston at any point in the last 30 hours? What were the highest readings at those stations?	2/23	Jean Lim	2/23	Emailed readings on 2/23		0.5	Strategic Initiatives
41			Is the night guard also out on the weekends, or just Monday through Friday night? Please verify that residents did indeed file "Immediate Concerns" with the City over the past 48 hours. And are they filing them at night when they hear the noise such that our night guard can respond, or are they waiting until morning to file?	2/23	Laurie Anderson	2/23	The night staff is working seven nights a week. They receive information from the complaint line, either online or by phone.		0.5	Strategic Initiatives
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1			Trigger Matrix Tracking link						#
2	Status	Complete?	question	date rec'd Newest to Oldest	submitted by	date of response	answer Staff: If you link to an answer, please confirm the sharing settings are "anyone with the link can view"	outstanding issues/timeline for answer		who is responsible	Follow up 1	Follow up 2	Follow up 3	Follow up 4	Follow up 5
3			Can we clarify in the opening remarks that Broomfield is carrying the cost burden of our current AQM program? Extraction's opening remarks seems to indicate that together we have a vast monitoring program and this addition is just a small addition. This monitoring requirement per Reg 7 should ultimately place the full cost burden on the operator to continue the monitoring programs that is already underway in Broomfield. I think it is important to clarify for items 1-3 that these plumes are not necessarily of short duration, but only cross the monitoring location for just minutes at a time before drifting in another direction or dispersing with the wind. Item 12 may provide an opportunity to better define first six months of production. Rather than requesting that the APCD "ask Extraction to clarify whether the six months runs from the time that the first well is drilled on the pad or from the time the last well is drilled" which is misleading since production does not begin when the "first well is drilled". I think this should be restated to request that the APCD ensure that the monitoring will remain in place for each pad until the last well to enter production on that pad has been in production for at least 6 months. If we are asking for any clarification, we should be requesting that Extraction indicate what they refer to as the start of production (i.e., does production start with the first salable gas or when the sand cans are removed). Did the plan indicate access to data? If this type of monitoring under Reg 7 is going to ultimately take the place of monitoring by local municipalities, the data needs to be publicly accessible in near real-time. Also, the monitoring needs to be done by an approved third party.	5/3/21	Laurie Anderson	5/3/21	Here is the final draft of the comments, which incorporate many of your comments below. I did want to respond to your comment that the plumes that have been detected are not all of short duration. The reason the comments mention the short durational spikes in emissions that have been monitored is because we are recommending APCD require Extraction’s sensors to be capable of monitoring for very short term spikes in order to detect short term spikes of toxic air pollutants. It is our expert's opinion that the staff at APCD understand that each short term spike represents a snapshot in time at a particular location and that plumes move with wind.
4			Question #3. The comment indicates it is not clear how and when a responsive action will be reported to CCOB or Adams County. Question #4: The comment asked which state agency can request log records from Extraction. Question #5. The comment asks what actions Extraction will take on forecast air quality action days beyond what is suggested in the OA, BMP 20(D).	5/3/21	Jean Lim	5/3/21	Here are the updated comments to be sent to the Air Pollution Control Division on these plans, which incorporate most of your comments. Question #3. Response: Extraction’s plan, at p.14, for the NM B Site states that Extraction will notify APCD and the LGD whenever there is an alert level of 5 ppm over a period of 4 hours which requires the operator to be deployed to the site. Question #4: Response: APCD can request all records required to be kept by the rule. VI.C.2.a. Local governments can request those records from the Division who shall request them from the Operator if the Division does not already have them. Id. Records required to be kept include activity logs, monthly reports and the data necessary to inform monthly reports and the raw data associated with each monitor. Question #5. Response: This is not covered by the monitoring plan requirements. APCD rules do not require operators to tell them of their plans to respond to air quality action days in advance.
5			In the April 26 Trigger Canister report in yesterday's Oil and Gas Update, the CCOB inspector who happened to be on the Livingston Pad provided interesting detailed notes about activities on the pad at the time of the AQM Livingston 01 trigger. I appreciate the detailed notes and have these followup questions: 1) Has the inspector seen Extraction shut in a well for parts replacement before? 2) Was there anything in Monday's observed Extraction activities that seemed irregular or not consistent with best practices to the inspector? 3) Would it be likely that any replacement of a separator drain valve by Extraction would result in the separator being blown down, usage of the ECD (Emissions Control Device) and enough emissions to cause a trigger event? 4) Should CCOB have been informed that this maintenance activity was to occur? 5) Did Boulder Air's Soaring Eagle site detect elevated emissions? 6) Were there any health complaints filed around that time Monday morning?	4/28/21	Jean Lim	4/28/21	1) The inspector has observed this activity numerous times in the past. 2) No. Fluids and processes were conducted correctly. Weather conditions (temp, wind direction, etc) could have been different. 3) The separators being blown down and the use of the ECD are always part of a drain valve replacement. This is the first time that a trigger event has occurred during this type of maintenance. 4) The Inspector was informed the day of the maintenance and observed the activity as it took place. 5) Neither the Livingston or Soaring Eagle GC stations picked up the event. 6) No health concerns have been filed since April 17th.
6			According to the data snapshot, there was a high methane reading of 4,789 ppb @ 6:30 a.m. on April 15 at Soaring Eagle (background 1,910 ppb). Could you ask if the scientists noted any other elevated readings at that time? I don't recall methane being that elevated for a while. Were there any health impacts reported in the morning?	4/16/21	Resident & Jean Lim	4/16/21	Broomfield received two health complaints from the same person on this date. The resident described the headache symptom as starting on the 12th (Monday). The Apis network did not show elevated total VOCs outside of normal parameters during this time. Benzene and toluene have been below 0.2 PPB for both Livingston and Soaring Eagle sites since the 14th, and the PTR data is also showing baseline levels of BTEX species. We did note that the very light winds were consistent from westerly directions all morning with one exception. Between 6:15 and 6:45 AM on the 15th, the wind shifted to come from a northerly direction (plot). Assuming that the Picarro methane system (at Soaring Eagle) was operating normally, this indicates that there was a methane-only source to the north of Soaring Eagle, and this methane plume shifted toward Soaring Eagle with the changing wind. We don’t have enough data to fully characterize the type of source, duration, or scale of the methane emission. The resident also reported throat irritation on the morning of 4/15. PM 10 was elevated at 7 a.m. on 4/15 (83 ug/m3). PM 10, while not as damaging to the lungs as PM 2.5, can still cause adverse health effects. Wind was from the NNW at this time. The elevated reading was short-lived. In context, the elevated methane plume detected on the 15th does not deviate much from the levels and patterns we have seen at Soaring Eagle since the beginning of the year.
7			What was the COGCC's response to the idea that nearby Extraction's P & A activities caused the Anthem Ranch methane plume that showed up in the March 1 CDPHE flyover? Please see my March 12 email below and your reply that you would ask them and the AQM folks about that possibility.	3/31/21	Jean Lim		The message received from Greg Deranleau @ COGCC this week on this topic is: We were hoping to have more info from Extraction and data from CDPHE's canister before we went out, so we are kind of delayed at this point. Based on that information, we would determine how--and frankly, if--to proceed with a soil gas test.
8			The Ajax website shows the following sensor outages: - Anthem 01 since 2/12 (10 days) -Wildgrass 01 since 2/15 (7 days) Boulder Air at Soaring Eagle and Livingston show some significant VOCs on 2/18 at around noon, so there are reasons why we should have all of the sensors operating. What is the status of returning these to service? The 2/18 Oil and Gas Snapshot states, "Service Level Availability (SLA or Sensor up-time) since last report on 2-16-21= 80% Wildgrass & Anthem 01 are offline. Ajax has been notified and restart is anticipated on Friday [2/19]." There is a contract provision to "maintain at least 2 cold-spare sensor systems in order to facilitate the monitoring network uptime commitment and minimize downtime due to sensor issues. Malfunctioning sensor systems with more than 8-hours of continuous downtime will be replaced with a cold-spare system within 2 business days of confirmation of the issue."	2/22/21	Jean Lim	2/22/21	From Ajax: Councilmember Lim is correct. These systems have been down and we did not fulfill our promise for monitoring site uptime in this case. This issue is entirely due to a failure in communications and issue identification and response processes within Ajax. We have identified the root cause issues and will make changes to ensure a delayed downtime such as this does not happen again. Ajax field staff is heading to Broomfield this morning to resolve these issues. We will do everything we can to ensure that these sites are back online today. We’ll provide an update on the sensor status, as well as a summary of the internal initiatives we are enacting to help us avoid this type of failure in the future.
9			There has been a sudden rash of well unloading activity in Erie, including this just added today to the several notices in the past 2 weeks: https://www.erieco.gov/DocumentCenter/View/14075/Cosslett-1C-22H-B168-212021 I have been signed up for Erie notifications for years and don't recall this volume before. Can someone provide an explanation why operators would want to do this volume of well liquid unloading at this time? Given the winter air inversions described by the scientists and the possibility of plumes from this unloading, it does not seem like the best time to do this over the winter weeks.	2/1/21	Jean Lim	2/1/21	Here are some thoughts about the questions posed below concerning liquids unloading. The process of oil and gas production is dependent primarily on the geologic performance and well engineering. Every well varies in the quality of the production. So there are "good wells" and "bad wells". Because this is based on the natural geologic properties it is difficult to predict when fluids - primarily formation water and other liquids - will accumulate in a well. Liquids in a natural gas well produce pressure in the well - when this pressure exceeds the pressure of the gas in the geologic formation the flow of gas either slows or stops. This condition in the well then requires maintenance to restore production. Manual liquids unloading is a temporary operation where the flow of gas from a well is diverted to the atmosphere which allows the liquids in the well to rise to the surface and be removed. The duration of the liquids unloading depends on the size, depth, and type of well along with the properties of the geologic formation specific to that well. The timing of liquids unloading can be dependent on availability of service maintenance companies, permitting, disposal options, and company economic considerations to name a few. However typically an oil company will want to restore the full production capacity of the well as soon as possible. Since there are no regulatory requirements restricting the time of year unloading can occur currently on the books an oil company can typically perform unloading at any time with the appropriate notifications to the COGCC.
10			It appears there was another large toluene spike around 1.5 ppb last night with a i/n pentane ratio signifying it has an oil and gas influence. I continue to get texts from residents when these spikes occur. Were any canisters triggered last night or early this morning? That 1.5 ppb toluene spike last night was at Livingston at about 10 pm, and ethane and propane spiked at about the same time. It is interesting that last night at about 5 pm acetylene went up to 10.11 ppb, which may be the highest it has been since the mysterious cause of the Sept spikes went away.	1/29/21	Jean Lim & Laurie Anderson	2/1/21	From Ajax: Toluene at 1.5 ppb is equivalent to a truck passing by the equipment or a vehicle idling near the sampler. Our ACES urban weekly monitoring canisters saw toluene between .3 and 1 ppb with weekly averages of 1.3 ppb as traffic increased on certain weeks. The health guideline for toluene is 2,000 ppb. The most common ambient sources of toluene are traffic emissions. Acetylene is also primarily sourced from traffic emissions. Unfortunately, at these low concentrations it is difficult for us to determine what may be causing variance within these expected background levels. We also want to keep in mind that i/n-pentane ratio is a datapoint that can influence an source estimate, used along with wind data, plume composition data, and operational activity. On its own, especially in winter, i/n-pentane ratio isn’t a perfect indicator of specific sources of a spike. It’s entirely possible that a calm regional air mass is being influenced by regional oil and gas activity and, at the same time, a vehicle passes by a sensor to generate an individual toluene and acetylene spike. Ultimately, the solution to resident concerns may be to place some context bands on the plots in the Boulder AIR website that show the expected background range for toluene and the health guideline level. This may help concerned citizens contextualize these events. From Boulder AIR: Brent is correct that benzene is a component of vehicle exhaust. However, it is a very minor component of gasoline and diesel fuel. Benzene is one of the aromatic compounds. And those have been reduced and reduced and reduced over the years in those fuels. So, they are at a pretty low percentage now. When you get exhaust plumes then you typically get many, many VOCs all at once. And toluene may be one of them. But you would expect many others, and many of those more prominent. But you for sure would not get a lot of toluene without much else. These samples didn't quite look like what I would expect if it was a full hit by an exhaust sample. Toluene is also used in some domestic and industrial solvents. In those cases it may be more of a distinct appearance, without much else. It's hard to tell in this case. The concentration wasn't really all that high, so it's not like a very strong source nearby. Remember, at LUR we have seen VOCs concentrations 1000 x higher than that. Those then have pretty clear signatures. But in the low ppb range, it gets pretty tricky as the signals are not that strong
11			On 1/22, the readings were significantly higher at 6 pm at Livingston than at 7 pm at Soaring Eagle. Does that support the stated conclusion that the Livingston Pad was not the source of the spikes and the source was from the north?	1/29/21	Jean Lim	1/29/21	From CSU: Concentration differences between Livingston and BSE reflect plume strength and position. A plume from the north can yield higher concentrations at the more distant (Livingston) site if that site experiences the plume at a time of higher emission and/or if there is less dispersion in transit. This could also happen if the Livingston site experienced a more direct hit of the center of the plume than did Soaring Eagle. From Ajax: Along with Jeff’s points regarding spatial position, we have to keep in mind that the GC measures 10 minutes out of each hour. It could be that one site caught the “shoulder” of a peak in its 10 minute sampling window, while the other site caught more of the plume’s peak period during its 10 minute sampling window. From Boulder AIR: Link to Report Addendum on 1/22 events.
12			In following up to my 1/21 question about any next steps about the methane source investigation, there were large spikes on Friday evening at Soaring Eagle and Livingston. On Friday evening 1/22 about 6 pm, there was the largest toluene spike in the last 30 days and a little less than an hour later there was the largest methane spike in a month recorded at Soaring Eagle. Can someone take a look at these spikes and provide some insight if it is possible they are related and point to Livingston as a source?	1/25/21	Jean Lim	1/25/21	Here are the BTEX data from the PTR-MS. The high time resolution gives a more complete picture of the toluene and benzene concentrations than the auto-GCs You can see a double spike in BTEX just before and after 6 PM. The second spike in toluene is especially high by recent standards (nothing this high has been measured in January), briefly exceeding 5 ppbv. Winds in this time period, per the Boulder Air timeline, were shifting between NNW and NE. Given this transport pattern, it is not likely that the Livingston pad was the source of these spikes. Transport from a source north of Broomfield once again seems likely. The double BTEX spike might reflect a source plume from the north crossing the Soaring Eagle Park monitoring site twice as the wind direction oscillated with, perhaps, a short very local toluene spike (truck emission?) superimposed on the second plume crossing. I suggest a separate toluene source given that the two spikes are very similar to each other for benzene and xylenes+ethylbenzene, while the second toluene spike is much higher than the first.
13			“Hey! I'm smelling a sickly almost candy factory scent outdoors. You know where I live, no candy factory out here. I've noticed it on and off the last couple of weeks. Any ideas?” Do you know what type of work XOG might be performing on the pads right now?	1/20/21	Resident via Guyleen Castriotta	1/20/21	There are no current operations on the Northwest Pads other than some electrical work that was noticed last week and the sound walls are down, so any activity would be visible. I have confirmed with Extraction that no work has been conducted since the electrical work. Staff informs me that a sweet odor is not typical of oil and gas emissions, but may be typical of a family of chemicals associated with other industrial uses. In looking at the air quality data from last night and the air data was fairly normal. Here's Apis sensor data for the past week for both interchange sites (green and yellow) as well as wildgrass 01 (in blue). The volatile organic compounds (TVOC) readings are within normal parameters for all 3 locations, and particulate matter (PM) for all 3 locations appear to move in tandem, with the interchange locations being somewhat elevated from the wildgrass location. Given proximity to the Interstate, this seems logical. A preliminary reading of this by staff is that whatever is going on with PM (which may or may not be indicative of an odor issue), it's probably a regional phenomenon and not unique to the interchange pad or sensor locations. There is a small enhancement at 8PM last night (per the resident concern), but again the wildgrass sensor picked up the same enhancement. See graph here. Also, if an inspector is available, if the citizen wants to log the complaint at the time, on the website, we can have this investigated at the time. Here is the link to the website:: https://broomfield.org/1820/Oil-and-Gas
14			We know that recently there was an equipment failure at the BSE site that resulted in bad data which was subsequently removed/corrected. For both Ajax/CSU and Boulder AIR, is this need to remove/correct data rare? Or does it happen more frequently, but we just don't see the deletions and/or corrections being made? And when there is data deleted and/or modified, is the change annotated in the data log for future reference? Also, is the original erroneous data still there, if someone wanted to see it, or is it forever deleted from the data log? I received a couple questions about data integrity and just want to make sure the procedures are solid.	1/19/21	Laurie Anderson	1/19/21	- With regard to your questions below, here is the response from Dr. Helmig at Boulder AIR: That's a very good question. Since all instruments are running and producing data 24/7, there is always a chance that a measurement may have a problem, is reporting data, but it may take us some time to notice it. And the bad data may make it to the website before we can stop it. This has been very, very rare thus far. For sure less than 1% if you take all measurements together. We will intervene and correct as soon as this comes to our attention. We also have automated checks in place that will detect certain errors and send us an e-mail right away. It works for a fair amount of possible issues, but not for everything. We will remove bad data from what's displayed on the website as soon as we can. But please note that the data on the website are all preliminary. That's stated on the website. As we review the data we may make some corrections every so often, for instance as we recalibrate the instruments. Most times these corrections are very small. For most issues, the raw data files, including the bad data, are stored as a raw data file (unless the computer or data system crashes and isn't recording any data).. When we remove the bad data segments, we then store the cleaned data file as a revision with a new file name. Quite often, there are many revisions of the data as we clean the data up more and more. For instance, for the Boulder Reservoir VOCs data, we now have a revision #7 from prior years. All the prior revisions were saved. So, there have been at least 6 corrections/adjustments made. For most cases, these adjustments are very, very small, and most people will never notice. There is a lot of work happening behind the scenes like that happening all the time. - Here is the response from AJAX: The need to invalidate or correct data is rare. Ajax does not delete or manipulate sensor data once it has been placed in our master data lake. We do tag certain data as invalid when we know of sensor issues or maintenance activities so that we can ignore that data during analysis. Likewise whole air canister lab results are generally static. There have been occasions when lab data is revisited or lab calculations are “double-checked” which may result in a change to the reported concentrations, though I believe there have been a total of 3 times when this has been done – none of which impacted reports or conclusions. All changes to data are logged with before and after values, however there is no easy (user website) way to see the data history. It takes a bit of custom digging by the technology team, but we do maintain a full history of every piece of monitoring data that is captured. - Here is the response from CSU, specific to the PTRMS data: Our goal is to provide the most complete, accurate set of data feasible. If an online instrument malfunctions, generating faulty data, we will attempt to recover accurate data whenever possible and place those into the final dataset as part of our quality control procedures. If accurate data cannot be recovered, the data would be reported as missing due to instrument failure. We would not retain known faulty data alongside accurate or missing data in final reported data records. Such issues are relatively rare. More common is the updating of preliminary data with final, quality controlled data due, for example, to application of post-calibration.
15			There do not appear to be methane or carbon dioxide readings at Soaring Eagle since yesterday at 2 pm. See attached. Is there a Boulder Air equipment problem? A resident wants to know if we can access methane data in real-time any other way. I think the PTRMS should measure methane in real-time, but do we have access to that data? We can't see methane separately in the Apis data and Brent Buck stated once in an email that, "The Apis systems do have a methane sensor, but these sensors will only see very large methane events."	1/15/21	Jean Lim	1/15/21	9:02 AM from Boulder AIR: Just wanted to let you know that the methane analyzer at BSE crashed yesterday. We are working with the manufacturer on troubleshooting. Not sure what the issue is and how long it will take to get it fixed. 12:00 PM from CCOB Staff: We only get BTEX data from the PTR (although I don't know if it also measures methane). The Earthview sensors do measure methane, but on a much less precise scale (PPM) and I would remind everyone that these sensors are not reference-grade, so drawing any conclusions from preliminary data should be cautioned. Here is a link to their data dashboard: http://evdash.com/broomfield_public.html Clicking on the Soaring Eagle location will take you to data of the 2 sensors they have installed there. 12:20 PM from CSU: Quantitative methane data are provided by the Picarro Cavity Ringdown system operated by Boulder Air, a similar Picarro methane analyzer in the CSU plume tracker, a Li-Cor methane analyzer in the CSU plume tracker, and GC measurements made in collected weekly and triggered canisters. The PTR-MS does not measure methane. I suggest we wait and see what Detlev finds out from Picarro about the problems with the BSE methane analyzer. If the problem is expected to last for an extended period, CSU could potentially deploy one of our methane analyzers in the trailer as an interim solution. 2:42 PM from Boulder AIR: The Picarro system is fixed now. I am informed that the technical solution was to "reseat connectors on the motherboard and logic board of the Picarro" and to make a back-up drive for remedying this in the future.
16			Were there any triggers near Livingston last night or this morning? According to Boulder Air, - Benzene peaked at 40 ppb at around 8 pm last night and was above 10 ppb from 1 am - 8 pm - Ethane and propane were extremely high this morning: ethane 204 ppb, propane 121 ppb	1/14/21	Jean Lim	1/14/21	From Boulder AIR: We had an instrument problem with the BLV VOCs system yesterday around noon. Jacques went out and fixed it right away. But the first three ambient runs after that still show elevated benzene as a result from the instrument being opened up. Those samples need to be removed from the record. Things started to look normal again shortly after midnight. The website should have this correction uploaded within the next hour or so. BSE did not have any issues. Those data are fine. We had a pretty big ethane spike there yesterday. Quite interesting as we have also seen some unusual spikes in Longmont over the past few days. From Ajax: These events seem like two or more legitimate plumes. Our sensors picked up on the elevated TVOC levels during these periods, though either did not get hit directly or the plume dissipated before reaching our sensors. The duration of the elevated levels picked up by the sensors, coupled with the GC measurements tell a reasonably clear story. The first event started around 2:00 pm on 1/12 and generally traveled north to south, dissipating heavily toward the edge of the Wildgrass neighborhood. The plume hit the Boulder AIR station around 8:00 pm and dissipated into the air mass around Livingston throughout the day. The second event started around 8:30 am on 1/13. This plume also traveled north to south and was much more distinct. It’s harder to tell if this one is a short release that’s dissipating into the area, or if it’s an ongoing source like that on 1/12. For context, these plumes are not as large as many of the plumes we observed during active operations. They seem to be smaller sources that are building up around Livingston due to cold, calm conditions.
17			It looks like the Ajax data is not uploading since no sensors are showing data for today. I suspect they are not all down. It will be good to know if any sensors triggered today.	1/10/21	Laurie Anderson	1/11/21	Ajax removed the stations that were not on the 2021 plan on 1/8/20 and the six stations that were kept in the network are working as expected. Also, Ajax is currently keeping the Apis system at the Soaring Eagle site for continued comparison with the other equipment at this location.
18			In yesterday's Oil and Gas Update: "Today, Broomfield inspectors observed ‘well swabbing’ taking place at the Interchange Pads. This is a standard practice to stimulate pressure within the wellbore. The work involves a heavy-duty truck with a foldable mast. Work is expected to be complete within 1-2 days." Could you please ask Dan or someone else what the "well swabbing" action reported at the Interchange wells indicates about these wells? Is "well swabbing" usually needed so early in the life of a well? Can we anticipate greater emissions for any reason during or after the swabbing? Also, do we have the 12/20 trigger canister results back from Interchange 01?	1/8/20	Jean Lim	1/8/20	In short, swabbing is a form of “well control” that releases bottom hole pressure in order to “kick” the well off. When wells are first drilled, they are usually fractured by a pressurized liquid to help open up “production zones” where oil or gas can travel to. The next step is where the actual swabbing takes place. This is a standard process used on newly drilled wells, but can also be used on aging wells where internal pressure has reduced over time. "Swabbing a well" is a very typical well maintenance procedure especially for directional wells. Water collects in the casing of the well and causes a pressure differential that impedes the removal and production from the well at depth. Operators "Swab" the well to remove the water and liquid to improve production performance. It is not something that is typically associated with a large evolution of gases. Swabbing rigs are then used to remove the fluids from the production zones. These swabbing rigs normally have a winch with a cable and a foldable mast with a pulley on top. First, the rig operator must back the machine as close to the well as he possibly can. Next, the operator raises the mast and moves it until it is aligned with the center of the well. Next, the operator lowers the cable in and out of the well via the “winch drum”. Here, the operator must be able to maintain control of the machine while taking into account the well’s sound and depth. The activities of the swabbing rig then allow for the removal of the liquids inside the well. Standard practices involve removing 6 barrels of fluid out of the well. This practice is referred to as a “Run”. Some wells may take just one run while others may require multiple. Removing these fluids then causes the bottom hole pressure to increase. This allows the oil or gas to be pushed out of the well to cause it to start “flowing”. Oilfield workers may then start collecting and storing the natural resource that is being emitted from the well they are working on. As the well ages, the bottom pressure of the well may not be enough to push the oil and gas out of the well anymore. The well has then stopped flowing and the swabbing process needs to be started over again. CCOB inspectors verified that this was a closed process conducted under high pressure seals. No emissions or spills were reported or observed. Apis sensors have been within normal parameters for the past 24 hours. Linked are the traces for Interchange 01 (in green) and 02 (in yellow) compared against Wilgrass 01 (in blue). Max value over this period was 108 MV at Interchange 01 this morning around 8AM (and after the swabbing process was complete). Ajax has notified CCOB staff that a trigger canister report from Interchange 01 is forthcoming today.			Dan D.	Swabbing is a standard maintenance procedure for a typical well. Fluids such as water can build up in the column of the well and prevent freeflow of the hydrocarbons. How often you have to swab is really a function of the geologic formation and the specific properties of the reservoir. I would speculate that the reason they are swabbing is because reservoir pressures are relatively low.. Production data is highly variable due to a number of factors,everything from the price of the commodity, to deliverability, to refinery capacity, to demand, and a number of other items. I am not sure we can infer anything about the lifecycle of the Broomfield wells at this time if that answers the question.
19			December 2020 Below
20			Series of questions submitted by the Mayor RE a resident's reported health issues: Can someone tell me how far she lives from the Livingston Pad? And lets ask more specific questions with Collett and Helmig: Is there a possibility that Methane spikes or Toulene from the Livingston Pad could travel this distance in enough quantities to cause her daughter’s nose bleeds. And has resident received a canister yet? Has she used it? Has resident taken her daughter to a Doctor and has the Doctor provided an opinion. I understand HIPPHA plays a role in this. Can resident waive HIPPHA rights? Have there been other complaints at the same time?	12/29	Pat Quinn RE Resident	12/29	Emailed response developed by Public Health and Strategic Initiatives staff here. Official response on nosebleeds from CDPHE here.								Official response on nosebleeds from CDPHE here.
21			It is remarkable how many VOC indicators (ethane, propane, benzene, toluene) on the Boulder Air Soaring Eagle Site were highly elevated yesterday between about noon and 10 pm, along with NOx, PM10 and methane. And the i/n pentane ratio was below 1 the entire time. Did the canister trigger at Soaring Eagle with that combination? Do we have any other insights about the source? What does the wind tell us?	12/21	Jean Lim	12/21	Links to email responses: Staff email, CSU email. Further response from CSU: We have seen similar buildups on a number of other days recently, although the peak benzene here might be somewhat higher. It is not nearly as high as we have seen in some other strong source plumes, where values can reach several ppb or 10s of ppb for shorter periods. This pattern of buildup is not surprising for this time of year, especially when snow is on the ground and winds are calm. Under these conditions, the depth of the surface mixed (boundary) layer tends to remain shallow and emitted pollutants are trapped near the surface. They can’t mix vertically and if winds are calm they don’t disperse well horizontally. Per the Boulder Air website, wind speeds were low on 12/17, decreasing throughout the afternoon to < 1 m/s. Temperatures were also on the cool side, with a max T of ~40 F. Wind directions shifted from southerly in the morning to northerly in the afternoon. Boulder Air methane concentrations also showed a buildup during the day, similar to the BTEX buildup shown above, although the rise in methane is delayed a bit relative to BTEX concentrations and seems tied to the change to northerly wind conditions mid-day. As reported in the plume tracker report for the 12/9 outing, there is a rather large methane source either at or near the Coyote Trails pad. Peak methane concentrations were ~3.2 ppmv. We have previously seen much higher methane concentrations in strong source emissions plumes. Boulder AIR VOC concentrations also show a buildup along the lines of those discussed above for PTR-MS BTEX and methane. Here we again see the BTEX buildup start in the morning, while the rapid increases in the light alkanes (ethane, propane, butane, and pentane) seem tied more closely to the shift to northerly winds mid-day. There is an increase in the toluene/benzene ratio starting mid-day when the wind direction changes. Particularly interesting is the sharp decrease in the i/n-pentane ratio starting mid-day, also coinciding with the shift to winds from the north. This suggests to me that the bigger oil and gas contributions to this VOC episode are probably coming from a source to the north of Soaring Eagle Park. The higher i/n-pentane ratios in the morning indicate a bigger contribution from traffic sources. My interpretation here is that we are seeing ongoing emissions build up under typical winter stagnation conditions. We have seen other buildups like this at the site and I expect we will see more in the coming weeks. The association of the stronger oil and gas signature with transport from the north suggests we should continue to try to understand the Broomfield air quality impacts from sources in Weld County to the north of Broomfield, most likely in a box defined by Weld County roads 4, 5, 6, and 7.
22			Just wanted to follow up with a few more screenshots [screenshots of daughter's nosebleeds]. Out of curiosity, I also looked at Livingston readings. These levels were even higher at this monitoring station.	12/21	Resident	12/21	On 12/17 a health concern was submitted by a resident whose family member experienced a nosebleed. This resident has submitted several health concerns in recent weeks, citing nosebleeds. The resident is concerned about increasing levels of VOCs, in particular, toluene. Broomfield's Environmental Epidemiologist has been in communication with the resident. Nosebleed dates are recorded and evaluated against air quality monitoring data, including toluene levels near the Livingston pad and at a distance further from the pad (Soaring Eagle station). A trigger canister has been provided to the resident to collect an air sample. Instructions for canister use were supplied again on 12/18 to the resident so that an air sample can be collected at the time of the next nosebleed. An air sample may be able to provide further information about levels of VOCs present at the time of a nosebleed.
23			Was there a system-wide Ajax outage from about 11:30 pm to 2:30 am (last night)?	12/7	Jean Lim	12/7	Per Ajax, This downtime window appears to be a cellular outage by the cellular provider. The distinct 11:00 pm to 2:15 am timing indicates a cellular maintenance window. When cellular connectivity events like this occur, data is stored on the system itself and can be retrieved.		0.5
24			Thank you for passing along this report with Dr. Helmig's data analysis and I am looking forward to hearing if Dr. Collet has anything to add. A few further thoughts/questions: 1) The wind patterns and tracer elements do not clearly point to the source of the methane spikes as Livingston. What are other possible sources, given the data? 2) Would the scientists state that these unexplained recent methane spikes found at Soaring Eagle would be commonly found across the Front Range? Dr. Helmig's graph comparing the 4 Boulder Air sites shows some similar earlier volatility at Longmont, but Soaring Eagle definitely has higher more recent volatility. 3) Dr. Helmig appropriately tried to correlate these methane spikes with benzene, which is most frequently examined because it has received the most study of its health impacts. At the end of the day, we are still left with the broader problem of our lack of knowledge about the health impacts of the "chemical cocktail." 4) Even if we dismiss these methane spikes as not being an immediate cause for health related concerns, should Broomfield be concerned that our AQM system is detecting large methane spikes that will deter us from reaching our GHG goals?	12/4	Jean Lim		Staff is investigating
25			1) If a pigging station were to develop a leak, would that be liquid leaking out? Or would it appear more like a smoky emission? 2) The color of the smoke,does not look like a sandblasting operation. So when will this sand blasting end as it seems odd that I has been going on for weeks. 3) Pig launchers are supposed to use hazardous chemicals to clean out the pipelines. This would typically be solvents. What will XOG use to clean the oil out of all the pipelines? I thought that it is used to remove and separate liquids and that can result in the venting of hydrocarbons into the air. Also used for “various cleaning, clearing, maintenance, inspection, dimensioning, process and pipeline testing operations on new and existing pipelines”	12/1	Residents	12/1	1) If a pigging station were to develop a leak, it would depend on the type of pipeline (oil, gas, water) as to whether it could be seen with the naked eye. For instance, if the oil pipeline/pig station spilled (which is connected to the pipeline) you would have a visible oil spill but no visible smoke or emissions. If the gas pipeline were to leak, it would be invisible to the naked eye and you would need an LDAR camera to see it. I can't think of any situation where there would be a smoky emission coming from a pig launching station. I believe that the visible emissions coming from the pigging station are a result of the painting/sandblasting operations. 2) Painting operations have been on and off during November because of weather and Thanksgiving. Anticipate the work to be completed here in December. The sandblasting operation was visually verified by Broomfield's inspector at 11:30AM on Tuesday December 1. 3) The Pipeline Inspection Gauges (PIGs) do not use chemicals or solvents to clean/inspect the pipeline. They are inserted into the pipeline and pressure is then put behind them from the product in the pipeline. The cleaning process involves a rubber type plug that is run through the pipeline, the pigging process. The plug/pig is inserted into the pipeline and pushed to a receiver location. They clean using physical force to push debris/buildup forward. Also, PIGs are used to monitor the pipeline for corrosion as it passes through the pipeline. Pig stations do not have any vents or flares on them. The inspectors stated that the only visible emissions they saw was the dust/sand from the sandblasting operations and there are not any emissions generated by the PIGs normal function.		0.5
26			Residents noticed emissions from something at the pig launcher that is on the west side of Huron across from Interchange pads. Any time we have driven by, we have noticed something emissions being released. It appears to be a grey "smoke" from the South West corner of the pig launcher facility. Does not look to be diesel exhaust fumes. Can someone tell us what this is? Are there specific chemicals being utilized at the pig launcher? What potentially are we being exposed to? It is very visible from both Huron and 156th, significant and ongoing. I will also file a complaint for traceability, but wanted to reach out to you directly since this is worrisome.	12/1	Residents	12/1	At 11:32 AM on Tuesday December 1, Broomfield's inspector confirmed that work crews were sandblasting the pigging station near the Interchange Pad. This is in preparation for painting the pipe desert tan. Work is anticipated to be completed today. Pig stations do not have any vents or flares on them. As such, there would not be any emissions generated by their normal function		0.5
27			November 2020 Below
28			- Given the high level of radioactivity in Colorado, should the State pursue other studies to see if this is an issue for Colorado/Broomfield? - Could the State identify scientists who may be interested in this field and encourage them to do further study in Colorado/Broomfield? - Or do we have enough data near unconventional wellsites to know that this isn’t an issue in Colorado/Broomfield? - How hard is it to measure airborne particle radioactivity at various distances downwind of major drill sites? - Has it been done in Colorado?	11/9	Jean Lim & Deven Shaff	12/3	1. Given the high level of radioactivity in Colorado, should the State pursue other studies to see if this is an issue for Colorado/Broomfield? This study found a positive correlation between upwind oil and gas development and downwind particle radioactivity measurements using a national dataset. This is the first study to look at this measure. There are several reasons why it is hard to use this study to understand what this means for Colorado, including: The limited number of monitors in Colorado The monitors in Colorado were not placed to answer questions about oil and gas activity Both the geology and oil and gas development practices in Colorado differ from other areas included in the study Overall, the study found increased levels of particle radiation 20 km downwind from unconventional oil and gas development wells. However, the increase is small. At the closest distanced studied (20 km), the authors report particle radiation increased by 0.024 mBq/m3. Assuming these particulates are a result of radon decay this would represent a 0.000162% increase in radon concentration compared to the 0.4 pCi/l (14.8 Bq/m3) average national outdoor radon concentration. This may represent an increase in annual radiologic dose of between 0.000324 mrem per year. For reference, a person undergoing a chest x-ray would be exposed to 10 mrem during the procedure. This study uses its data to extrapolate to predict the potential increase in radiation at a shorter distance, but additional monitoring is needed to validate the findings. The study predicts an increase of up to 0.14 mBq/m3 with 100 unconventional oil and gas development wells within 10 km. For context, This is the same as the difference in regional levels between the northwest (WA, OR, ID) (0.24 mBq/m3) and the East Northeast (MN, IA, WI, MI) (0.38 mBq/m3). This is also the same as to the seasonal difference in regional levels between the spring and autumn in California and Nevada. These findings of increased radioactivity identified in this study indicates several potential areas for further research. However, the reported levels of radioactivity are not so high as to suggest immediate action by CDPHE. We know that all Coloradans are at high risk to be exposed to radon gas, the second leading cause of lung cancer. This is why we recommend that all Coloradans get their home tested for radon and install a mitigation system if needed. Additionally, the use of, or requirement for, radon-resistant new construction techniques presents another opportunity for communities and individuals to reduce the risk of health effects that may result from exposure to radon. 2. Could the State identify scientists who may be interested in this field and encourage them to do further study in Colorado/Broomfield? Or do we have enough data near unconventional wellsites to know that this isn’t an issue in Colorado/Broomfield? Neither CDPHE nor COGCC are monitoring radioactivity near wellsites. If Broomfield is interested in studying radioactivity near wellpads, it could reach out to academics and/or consultants that work in this area. There are three radnet monitors in Colorado (Denver, Colorado Springs, Grand Junction) that collect radiation data, however they are 30 km or more away from areas with significant oil and gas activity. See www.epa.gov/radnet for more information on the program and to download data. 3. How hard is it to measure airborne particle radioactivity at various distances downwind of major drill sites? (Was there any discussion of how difficult it would be to measure airborne particle radioactivity at various distances downwind of major drill sites?) It is not easy as concentrations are typically very low. Historically monitoring has been performed using high-volume air samplers with the filters being analyzed in a laboratory for uranium, plutonium and/or other radioactive species. Gamma counts can also be performed on the filters. Samples often need to be monthly or quarterly composites to get enough material for detection of individual species. Gamma or beta monitoring can be performed on a continuous basis, but analyzers are not available that can continuously detect different radionuclide species at low ambient concentrations. 4. Has it been done in Colorado? Yes. There was a lot of radionuclide monitoring performed around the former Rocky Flats Nuclear Weapons facility in the 1980’s to early 2000’s. CDPHE used high-volume air samplers, and the US DOE also had their own monitoring systems. Measurements from Colorado were included in this paper from the three monitors in the state. However these monitors were not placed to answer questions about oil and gas activity and the closest monitors are 30 km away from areas with significant oil and gas activity.		16
29			For Wednesday's biweekly oil and gas meeting agenda, I would like to discuss what we can do to keep track of the frequency and understand sources of so many methane spikes showing up in readings at Soaring Eagle. For example, with regional baseline for methane at 1910 ppb: - On Wednesday, Nov. 24 in the Oil and Gas Update, you published the CSU trigger analysis report for Nov. 17 at Livingston. It seems inconclusive, indicating an oil and gas source but the winds were calm so the report states it can't be pinpointed to Livingston. My view of Boulder Air shows the methane level was high at 2724. - Methane level Soaring Eagle 3,429 ppb of Methane @ 6:27 p.m., November 23. i/n pentane 1.06 (Boulder Air marks < 1.5 increasing oil and gas influence). No trigger. - Methane level Soaring Eagle 3,818 ppb of methane @ 7 pm, Nov. 25, my reading since no Oil and Gas report, i/n pentane 1.5. No trigger. - Methane level Soaring Eagle 4,226 ppb of Methane @ 3:42 p.m., November 3 and the i/n pentane ratio at that time was .97. No trigger. - Methane level Soaring Eagle 6,623 ppb of Methane @ 6:49 am, October 24 and the i/n pentane ratio at that time was about 1. No trigger. How can we investigate what is causing this repetition of methane spikes? Is there any chance that whatever Extraction did to stop the acetylene/benzene spikes caused the methane spikes to increase? My quick observation in looking at Boulder Air is that the methane spikes increased in intensity and frequency after the acetylene/benzene spikes stopped around mid Oct. We need this new technology to go to inexpensive, commercial production now. Carpenter, Scott. "Los Alamos Scientists Say Their New Technology Could Cut Methane Emissions By 90%." Forbes. 23 Nov 2020. https://www.forbes.com/sites/scottcarpenter/2020/11/23/los-alamos-scientists-say-their-new-technology-could-cut-methane-emissions-by-90/?sh=3637729ae420	11/30	Jean Lim	12/2	CSU and Boulder AIR are jointly analyzing air quality data from the October/November timeframe to determine if the series of elevated methane events that were observed could be traced to local, subsurface hydrocarbon sources (as opposed to regional methane variability). Boulder AIR's report can be viewed here.		2
30			Thank you for passing along both Dr. Helmig's and Mr. Buck's analyses. I understand that both concur that the calm wind data prohibited pointing to a source of the methane spikes. However, Dr. Helmig differed in stating that there were other indicators that pointed to a natural gas source. So, these are my questions: 1) Since Mr. Buck indicates that he would like to hear Dr. Helmig's thoughts, did you or could you pass along Dr. Helmig's analysis to Mr. Buck? 2) These methane spikes are curious to me, even from a GHG perspective. I saw other similar spikes over the last 30 days but only documented the 2 largest in my email. I'd like to know if the scientists have thoughts if these methane spikes are worth further investigation and how we could learn more about the source. 3) Would it be of value to have Mr. Buck reset the methane sensor in order to do sample trigger canister analysis? Mr. Buck states in his email that, "The Apis systems do have a methane sensor, but these sensors will only see very large methane events."	11/6	Jean Lim	11/6 & 11/9	1) The Boulder AIR analysis has been passed along to Ajax Analytics 2) Response from CSU: CSU’s primary focus for Soaring Eagle is on the PTR-MS BTEX data, since it is most relevant from a health perspective. The PTR-MS BTEX and Boulder Air methane data are both collected at high time resolution. If we combine the data sets, we could look in more detail at whether there are different categories of methane plumes that contain varying levels of BTEX. For example, biogenic sources of methane (e.g., animal feeding operations in Weld County) would not contain BTEX while raw oil and gas methane emissions would. Having the two data sets with their high time resolution is very helpful for this analysis. 3) The methane/hydrocarbon sensors in the Apis systems are not very sensitive for general ambient conditions. They are only expected to respond to methane levels in the many hundreds of PPM (the lower-explosive limit of methane is 50,000 ppm). Realistically, we would only expect the current generation of methane sensors to respond to exceptionally large emissions events at the near-pad monitoring sites. In short, this means that the current generation of Apis systems are not helpful for these smaller “methane-only” types of events. The deployed Apis systems will not see leaks of processed methane/natural gas. However, we have not seen any methane-only events related to oil and gas development and production activities, the events have always also included VOCs that the Apis system does see.		1
31			On the Boulder Air graph, it shows: Soaring Eagle 6,623 ppb of Methane @ 6:49 am, October 24 and the i/n pentane ratio at that time was about 1. I don't think this Oct 24 reading was in any Daily Update since it was on Saturday morning. Those methane readings are relatively high, as shown by the 30 day Boulder Air graph. My questions: 1) Are there other indicators at those times that point to a source? 2) The trigger sensor did not go off at either time. Although the sensors are TVOC, does the trigger algorithm weight the methane reading since it is of concern?	11/5	Jean Lim	11/6	1) Ajax and CSU do not have any indicators to help characterize either of these events. Winds were calm and swirling during both of these events, which makes it difficult to confidently trace a source direction. As this event did not include elevated measurements for other hydrocarbons (which the PTR-MS and Apis systems watch for), we don’t have a clear source composition. 2) The Apis VOC Indicator sensors do not respond to methane. The Apis systems do have a methane sensor, but these sensors will only see very large methane events. Typically in oil and gas operations plumes, we rarely, if ever, see methane without the hydrocarbons that the VOC Indicator sensor watches for (though we do regularly see hydrocarbon plumes without elevated methane). These particular events appear to have been methane events without the hydrocarbons that are typical of a ‘down-hole’ source of oil and gas emissions. The following information was submitted by Boulder AIR: Here are the screenshots for the October 24 event. It was a relatively short methane spike with a peak at 6:47 a.m. Now, when you are trying to match up the VOCs data, you need to consider that the sample collection there happens over a 10 minute window. The times that are given in the IDAT for the VOC data are the middle of that interval. So, you need to go back and forward by 5 minutes for capturing the whole sampling time. There is a VOC sample at 6:17 a.m. So, that reflects the conditions during the sampling from 6:12 - 6:22. And then the next VOC sample is at 7:21 a.m. That then reflects a sample from 7:16 - 7:26. So, we don't quite have a VOC sample that perfectly coincides with the methane spike. But we have some data from a bit earlier and later, and when you look at the methane trace, you can see that methane was elevated around those times as well, just not quite as much. Therefore, the VOCs data should give reasonably good insight in the nature of that plume. Acetylene stayed low, but the petroleum alkanes went up with the methane. So, this likely is a natural gas plume, and not an acetylene plume as those that we have seen from the Livingston pad. The wind direction was all over the place, which is what you can get during very calm conditions, which we had at this time with wind speeds below 1 m/s. The wind vane then just doesn't swivel itself properly. Looking at the wind direction data, I wouldn't be able to tell where this plume came from.		1
32			OCTOBER 2020 Below
33			It appears that Ajax did reach out to Extraction's environmental group, but that they were unable to establish a basis to understand the source of the acetylene rich plume. I would like to add this to our meeting agenda to discuss next steps. The plume tracker and other data has established that the acetylene plume is coming from the location of the Livingston Site, so it is concerning that Extraction's environmental group was unable to point to the source. Did Extraction staff appear willing to begin investigation to what sources on their pad are emitting? Or allow access to our inspectors and scientists to bring our equipment on site to seek out the source when our monitoring indicates levels are high? This of course would take coordination, but it would hopefully allow the parties involved to find the source and remediate it.	10/16	Laurie Anderson	10/16	Our inspector's do have authority to go on the pad and we will be doing so. Also, the plume tracker will be making some additional runs on this issue. We will revisit this again with CDPHE and COGCC to see if we can get a further response. Staff will update here on all of our efforts at our meeting next Wednesday.		0.5
34			(Regarding Ajax and Extraction meeting to discuss data.) Did you or the scientists ask Extraction for access to the pad to identify the acetylene source with the available CSU technology? Did you ask COGCC if they had any insights as to the source?	10/16	Jean Lim	10/16	Ajax reached out to Extraction's environmental group and were unable to establish a basis to understand the source. Extraction did not appear to be interested in meeting. We have followed up with the COGCC and should have more information to report on the acetylene/benzene spikes, next week. We will be sending out the plume tracker to try fo further identify this issue. We will continue to update you on the progress.		0.5
35			On Sept 10, a resident on Raven Run shared her Sept 4 grab canister results with me (see attached), along with the email that Andrew wrote to her. Andrew stated in the email that, "The data seems to suggest a fairly strong combustion/exhaust signature (versus a subsurface hydrocarbon signature) which we have typically seen in canisters near gas stations or busy roads. Since you aren't close to either of these, can you think of some way exhaust would be getting into your home?" Looking back on this now that the scientists are looking at the BA emissions pattern in September, can we ask if this Sept 4 canister was part of that pattern?	10/12	Jean Lim	10/12	From CSU and Boulder AIR - The high toluene to benzene ratio in the grab canisters (3.5) is consistent with a typical exhaust (from a car or other engine) signature - see pie chart here. The BA plumes have very low toluene, with toluene/benzene ratios on the order of 0.1 - see pie chart here. It is the consensus of the team that these two phenomena are not from the same source.		0.5
36			The sensor site graph shows that only 8 of 11 sensors in the north have been up during the last 24 hours but the report says that 12 sensors are operational (that would include the 3 in the south). Anthem 2, Livington 3 and Prospect Ridge have all been down. I just wanted to make sure that Ajax is aware of the outages.	10/9	Jean Lim	10/9	We count 12 active sensors - It appears that Prospect Ridge went down at noon yesterday and we are still waiting on the Anthem 02 sensor that shipped from the factory last Friday (and will be stationed at Lowell and Midway). We notified Ajax of the outage at Prospect Ridge.		0.5
37			Could the decommissioned compressor station at Sheridan and 160th be the source of the acetylene plumes?	10/7	Jean Lim	10/14	From CSU: The removal of the decommissioned compressor last week does not seem to be a likely source of the benzene and acetylene-rich plumes we have been seeing over the past 6 weeks. I would not expect a compressor that was not operating to emit hydrocarbons (especially those like acetylene more representative of combustion processes) and any combustion emissions from equipment used for the removal would have detectable emissions only during their operation (last week) while we saw these plumes over several weeks at least back to early September. As far as wind directions associated with detection of the acetylene+benzene rich plumes, the location of the removed compressor (shown as an X on this map, is that the right location), could be consistent with the direction of plumes detected at Soaring Eagle, but would not be consistent with the direction of transport of plumes detected by the Boulder Air GC at Livingston. We will also continue to look at any occurrence of the benzene plumes now that the compressor station has been deconstructed and removed.		5
38			SEPTEMBER 2020 Below
39			Staff comment regarding the air quality event on 9/26/2020	9/28	Staff	9/28	It is the opinion of the CSU air quality team that the increase in benzene levels (max of 1.6 ppb, around 7 p.m., Saturday September 26) observed over the weekend was due to the wildfire air mass that moved in at that time. PTR-MS data showed a very strong correlation between benzene and acetonitrile, a combusted biomass tracer. The air quality team will continue to investigate these phenomena.		0.5
40			A resident read the acetylene-benzene spike report and noted that it said that the plume was coming from combustion in the direction of the pad. That resident thought a possible explanation would be that the ECD is not operating with the high efficiency it is supposed to. Incomplete combustion of those waste gases could lead to higher benzene and acetylene. The ECD is also on the south side of the pad, fitting other details of the report.	9/25	Jean Lim	9/27	Response from Dr. Collett - We have a CO2 measurement onboard the plume tracker and did see some increases when we intercepted the acetylene plume coming off Livingston last week, so I wouldn’t rule out a possible combustion source. Given the high background CO2 level, maybe it is just harder to detect the CO2 increase by the time it travels to BSE. Or, given that we don’t see perfect correlation between acetylene and CO2 increases in the plume tracker intercepts, maybe we are just seeing two different sources. Response from Dr. Helmig - unfortunately, we do not measure carbon monoxide, which would be the best tracer for combustion. But we do record CO2 at high time resolution at BSE. There is no wiggle whatsoever in the CO2 trace that matches the timing when we see the acetylene spikes, which one would expect if the acetylene was from a combustion source just a quarter mile away. I am not 100% sure about this conclusion, but from this lack of a correlation it doesn't seem highly likely to me that the release of the acetylene is tied to a burning source. (See image 1 and image 2)		2
41			As a follow up on the COGCC Davis 43-6 remediation report: 1) The report shows that there were increases in methane concentrations in August 11 samples compared to August 3 samples in COGCC wells 2-18', 3-14.6', 5-19', 7-15' and 7-9'. (pages 12-14) Why is the COGCC not concerned about this, when the methane is supposed to be slowly dissipating? Should the COGCC be remeasuring these wells earlier than spring? 2) What is CCOB's plan for the length of time that the nearby housing permits will be held? The report notes that there is low soil permeability, so is CCOB considering that it could take years for all residual methane in the soil to dissipate?	9/24	Jean Lim	10/1	The increases in methane concentrations in August 11 samples compared to August 3 are due to a condition called "rebound" see graphic representation of this effect. The Aug. 3rd Pilot Test removed methane from the sample points - see example of SVE process. We then allowed the formation to equalize to see how much came back. Our formation has very low permeability so the area around the sample points where the gas was removed is small. The gas samples on Aug 11 were a measurement of how much gas migrated back toward the sample points.This is what we were sampling for and was actually significantly lower than expected. The drawings are from a MUCH larger project with more complex hydrocarbon systems. Our project is much smaller in scale. In deference to Ward 3 Council Member Lim's concern we are scheduling another sample round. COGCC agrees that waiting until spring is unnecessarily long. If building permit applications for Graham Peak Way were to be submitted, staff would schedule a meeting with appropriate COGCC staff, North Metro Fire, the developer and appropriate experts to determine if there are conditions which would allow the permit to be considered.		4		10-16-2020 The COGCC confirmed today, October 16, 2020, that the current process to address subsurface methane appears to be working as recent testing shows lower levels. See the updated Public Notice for more information.
42			It sounds like we are seeing plumes of Benzene and Alkenes, which have double bonds between its carbons. This study is noting not only Alkenes but also Alkanes, which have single bonds, and are noted alongside oil and gas development. Both alkenes and alkanes seem to be under the category of "cyclic alkanes" in this study though and are connected to oil and gas development. So, although we might be finding "alkenes", I need to understand how easy interchangeable it would be to go from an alkene to an alkane, etc. Can someone cross check this possible oil and gas signature? Also, what role does heat, fires/smoke, etc. play in this?	9/23	Heidi H	9/24	Please see preliminary report from CSU and Boulder AIR here. (Please see add'l responses above, posted 9/27)		1
43			The Boulder Air graphs showed spikes around 6:16 am on Friday 9/18 of: benzene 3.96 acetylene 170.55 ethane 35.75 Was there any comment from the scientists on that event? Does it seem similar to what they have been tracking and are puzzled by?	9/21	Jean Lim	9/21	Please see preliminary email response from Dr. Collett here. Please see additional responses posted on 9/24 & 9/27 above.		0.5
44			A resident asked me if CCOB had an update on the results of the COGCC additional sampling and vapor extraction pilot tests for Davis 43-6 that took place on August 3. During the 8/26 biweekly oil and gas meeting, you mentioned that the COGCC had the data back but was not ready to share it.	9/4	Jean Lim	9/9	Davis 43-6 Update (plugged and abandoned well located on Graham Peak Way in Anthem Highlands) - On September 9, 2020, the COGCC informed Broomfield that the additional sampling and vapor extraction pilot testing is complete. The COGCC indicates that the results of the testing indicate that the residual subsurface methane is naturally attenuating. Please read the full update here. See Follow Up >>>>>>	data	3		9/16/2020 Update - Information has been received from the Colorado Oil and Gas Conservation Commission (COGCC) on the Davis 43-6 plugged and abandoned well. Read the updated public notice here.
45			I am glad that Ajax agreed to try to get canister samples at Interchange 1 and 2 by slightly lowering the thresholds, at least temporarily. Regarding their #2 comment that refers to the graph, I think there is a typo and it should start with "This higher signal from Interchange 1" instead of "Interchange 2." I hope that we will still hear if there is any explanation from APIS as to why the trigger canister grab failed.	9/3	Jean Lim	9/3	Response from Ajax: We are still investigating root cause of the trigger canister failure and will keep you informed as we progress. We definitely want to make sure that this doesn’t happen again.		0.5
46			That was a huge VOC spike of 524mV at Interchange 1 that was missed for analysis on Aug 23 with the failure of the trigger canister and early indications were that it was from the Interchange Pad. Interchange 1 has not triggered since then, but has been running sporadically higher than usual, with a peak of 273mV just shy of the trigger. We don't have Boulder Air over there to do a deeper dive into what is going on. Would it be possible to ask Ajax to reset the trigger at Interchange 1 to 250mV so we can get a canister analysis to see if something looks wrong? Or do we have any weekly canister analysis back yet for that time period since Aug 23 to give us some idea of why the TVOCs are running higher? From the initial report: "The sensor system at Interchange 01 triggered at 9:30 p.m. on 8/23/20. This was a short-lived event lasting about 8-minutes with a max TVOC indicator reading of 524mV. The normal baseline range for this site is between 75 to 110 mV. During the event, there was a 6 mph wind coming from the SW which is in the direction of the Interchange B Pad. This appears to be an isolated event and none of the monitoring stations close by registered the event."	9/2	Jean Lim	9/3	Response from Ajax: Yes, we can lower the thresholds at both Interchange Pad stations to 250 mV effective Thursday morning. We will keep thresholds at this level until we have triggered two canister samples, at which point we will return the thresholds to their original values. If any triggered canisters show elevated concentrations (i.e.: over 1 ppb benzene), then we may choose to reduce the thresholds permanently. This higher signal from Interchange 1 is most likely a result of the sensor system that has consistently run a higher and wider baseline range than all of the other sensors (it was at Thunder Vista, then Wildgrass, then Anthem 2, now Interchange). The signal shows a similar baseline as we saw from this system when it was at Anthem 2 (see plot below of the sensor signal as the system moved from Anthem 2 to Interchange 1). It is possible that we may see increased VOCs from oil and gas or I-25 traffic in canisters that are triggered as a result of reducing the trigger threshold, so it is a reasonable request.		1
47			There have been a lot of intermittent outages in the Ajax sensors over the past 12 hours, not even during the heat of the day. There are only 2 sensors which have not experienced outages in the last 12 hours, Wildgrass 2 and Soaring Eagle. What does Ajax attribute these intermittent outages to? Is there any way they can reduce those outages?	8/25	Jean Lim	8/25	From Ajax - We believe these small data gaps are due to cellular network connectivity issues, based on our discussions with Apis. On occasion, the system cannot secure a connection to the cellular network in the time allotted to the system’s cellular modem. We believe that this issue is related to the load on the cellular network at the time. We may be able to ask Apis for a firmware update that extends the period that the sensor waits for a cellular connection before giving up, though that creates some risk to the solar/battery system, as the cellular modem is quite power hungry. The risk here is that we close these occasional gaps, and add large gaps due to a depleted battery.		0.5
48			I am very concerned about the string of short benzene, toluene and methane spikes in August and am hopeful that the Ajax, CSU and Boulder Air scientists' continuing investigation can pinpoint the source soon. The scientists clearly stated last night that they are puzzled and do not have an explanation. Dr. Helmig stated that one surprise within these concerning spikes is the level of acetylene, a tracer of combustion. The graph in Ajax's presentation appears to show that the spikes are consistently happening at night, when no one would be observing. (See p. 20-21) In light of that, I want to revisit a question I think I asked before: Would we know if Extraction was flaring on the Livingston Pad? I think the answer was no.	8/19	Jean Lim	8/19	From Dr. Collet of CSU to first paragraph in Council Member Lim's email below: I don’t think we meant to imply we are puzzled by the August spikes, but there is more analysis to do on these episodes to try and identify source type and location. There is always acetylene in an urban environment like Broomfield. Detlev is right that there has been at least one bigger event in July with an unusual profile (lots of benzene but little toluene and high acetylene). We will take a closer look at the acetylene increase (vs. BTEX, ethane and other compounds) in our last triggered can from Aug. 11. That was a big event and has a more dominant oil and gas profile (lots of methane, ethane, benzene, and toluene). I also want to look more closely with Brent at the wind data there, including cross-checking the Boulder AIR wind direction with the APIS values. Jie is doing a more detailed analysis of benzene vs. wind direction from the PTR. Our hope is to identify possible directions of the sources impacting Soaring Eagle with an eye toward a plume tracker deployment to see if we can pinpoint source(s). That will require a little luck to be in the field at the right time. Response to Second Paragraph of Council Member Lim's email below on flaring: The only flare on the Livingston Pad is the emission control device (ECD). Section I of the Comprehensive Drilling Plan discusses the limitations on flaring and notification requirements by Extraction to Broomfield. The CDP states that no "routine" venting or flaring is planned, and Broomfield inspectors have never seen routine flaring on the Livingston Pad. The CDP requires 48 hour advance notice for maintenance flaring and notice within 24 hours of any emergency flaring. (See CDP section below) Section I of the CDP can be found within this link starting on page 7 (page 921 of the entire CDP), with section 4.4.1 on Venting and Flaring below: 4.4.1 Venting or Flaring As part of production/operation, no routine venting or flaring is planned. Emergency flaring will be controlled with an enclosed combustor with 98% destruction efficiency, if necessary. A pilot flame or auto-igniter will be installed to ensure that the vented gases are combusted. Pursuant to the Operator Agreement, if any maintenance activity involves the intentional venting of gas from a well, tank, compressor or pipeline (beyond routine pipeline maintenance activity and pigging), Extraction will notify the City 48-hours in advance with the duration and nature of the venting event, a description of why the venting will be necessary, a description of the vapors that will likely be vented, and a description of the steps that will be taken to ensure the duration is minimized, to the best extent practical. Extraction will not execute any maintenance activity which necessitates venting until the appropriate notification has been provided. If emergency venting is required, Extraction will notify the City as soon as possible, and within 24-hours from the time of the event. All emergency venting will be routed to the enclosed combustion devices to the best extent possible, and with the goal of upholding the safety, health and welfare of Extraction’s employees and the public.		0.5
49			I understood that the CSU 8/4, 8/5 and 8/6 canister analysis report was back as of 8/12 for the Wildgrass resident but she says she has not received a copy by email yet. Is there still some processing going on for that before she receives it?	8/17	Jean Lim	8/17	Results from the 3 grab canisters were sent to the resident on Foxglove Trail the morning of 8/17. The summary report can be seen here. Further, we have added a tab in the Trigger Matrix for resident canister results (while making sure personal information is not disclosed).		0.5	A.V.
50			Regarding the Aug 1st events below: In addition to Laurie's questions, I'd also appreciate hearing what other information you had that led to a decision not to notify anyone of this event. This type of spike is concerning to residents and it leads to further questions when no one hears about it until the 3rd quarter report 3 months later. Should we have put out an AQ event announcement at the beginning of this week? Can the scientists comment on it at the 2nd quarter report on August 18?	8/6	Jean Lim	8/6	We will request that Ajax and Boulder AIR discuss the event during the presentation of the 2nd Quarter Report.		0.5
51			On Aug 1 at 5:48 am Livingston measured a spike: 18.33 ppl ethylene; 1.61 ppl benzene, and 82.27 ppb acetylene. On Aug 1 at 4:19 am Soaring Eagle measured a spike: 5.56 ppl ethylene, 0.35 ppl benzene, and 11.17 ppb acetylene. If the clocks are not off, I think it would be helpful to get a better understanding of how the higher readings followed the lower readings. And what may have caused this spike at Livingston. The readings at the APIS sensors did not seem to pick up anything at that time from the above graphs. Or am I missing something?	8/6	Laurie Anderson	8/6	Here is a link to a report on the event.		0.5
52			Regarding the update on the Dashboard that the Wildgrass 1 sensor was shipped out due to a "motherboard malfunction. The unit has been packed up and sent to Apis for replacement. ETA will be posted here as soon as a tracking number is provided to Ajax & Broomfield." Based on Ajax's track record, I am concerned about how long it will take to get the replacement and if Ajax should be asked to move a different sensor to Wildgrass 1 in the interim. Will you be willing to ask Ajax to move one if we don't get a favorable timeframe tomorrow? If this sensor system has any value, I don't think an entire neighborhood directly south of the Livingston Pad should be without a working sensor for the large amount of time that Wildgrass 1 has been out. In reverse chronological order, as recorded on the Dashboard, are the problems with the Wildgrass 1 sensor: - 8/4 - sent back to manufacturer -7/31 - 8/4 down - 6/8 - 7/7 intermittent connectivity issues until Ajax finally sent it back to the manufacturer on 7/1 and moved the Anthem 2 sensor to Wildgrass 1 on 7/7 - 5/18 down all weekend - 4/26 intermittent connection over extended period	8/4	Jean Lim	8/6	We have moved the monitoring system from Anthem 02 to Wildgrass 01. This system was previously a problem child, but has been stable since it received field repairs and new firmware a few weeks ago. Please note that Jean’s log from the Wildgrass 1 site does not necessarily represent the same serial number. We have had individual serial numbers moving around multiple sites. We are also keeping an eye on specific systems (serial numbers) that misbehave with an eye toward getting the more problematic systems out of the network.		2
53			The Wildgrass 1 sensor has been down since Friday at 8 pm. Please provide an update on the Dashboard when you have it.	8/3	Jean Lim	8/4	Ajax was aware of the problem over the weekend and has diagnosed the issue as a motherboard malfunction. The unit has been packed up and send to Apis for replacement. ETA will be posted here as soon as a tracking number is provided to Ajax & Broomfield In the interim, on August 5th, Ajax moved the system from Anthem 02 to Wildgrass 01.		1	A.V.
54			July 2020 - Below
55			The Wildgrass 1 sensor was showing consistently and significantly higher readings compared to other sensors over the period... [the resident questioned]. I am seeking a logical reason why the Wildgrass 1 sensor is much higher than the others recently. Are there elevated VOCs that are causing symptoms even though it is just under the trigger threshold?	7/22	Jean Lim	7/25	Following is the response from Ajax: The Wildgrass 1 sensor has diverged from other sensors on certain days starting around 7/9 without a correlated temperature or humidity difference at the site (which reduces the probability of outside influence on the sensor). It is quite probable that Wildgrass is experiencing VOC concentrations that are more elevated than nearby areas on certain days, though based on PID sensor data alone, we cannot be completely certain. I agree with Councilmember Lim that there must be a logical reason for these divergent PID readings at Wildgrass 1, we simply do not know what this reason is quite yet. We cannot speak to VOCs causing health symptoms. Based on the historic relationship between the VOC Indicator signal and measured VOC concentrations in canister samples, it is unlikely that any VOC compounds have reached a health guideline value. Historically this PID sensor has had a higher baseline than the other sensor in the network. This system was originally at ThunderVista, moved to Anthem 02, and then Wildgrass 01 and has always shown higher values while the replacements showed normal baselines. Ajax brought this to Apis's attention before and they confirmed that the PID sensor is still functional but has a higher baseline. Ajax will reach out to them again to make sure nothing has changed. (Apis confirmed this information on July 29, 2020.)		2
56			A resident asked that we verify the triggering thresholds at the Wildgrass 01 Sensor. Is this the highest that we have seen the Wildgrass 01 sensor?	7/20	Resident	7/21	The Wildgrass 01 sensor triggering threshold is set at 300. (see all the sensor threshold settings here) This threshold hasn't been changed by Ajax. The public will be notified if any thresholds are changed. The Wildgrass 01 sensor is seeing higher readings than in the cooler months, as have all the sensors. Ajax informed us in June that in the summer (due to higher temperatures) they expected to see all the sensors running higher baselines. Ajax will not adjust trigger thresholds to account for this until trigger canisters are analyzed and can justify setting higher thresholds.		1
57			I appreciated reading Dr. Helmig's July 11 Air Quality event analysis on Friday night to augment the original CSU analysis. I have these questions: 1) The analysis did not conclude where this short-term "raw natural gas release" with "the maximum benzene during the peak occurrence [was] likely many times higher than the measured 9.6 ppb average value" came from. Can the scientists state from the ESE wind pattern that this "relatively close emission source" could have been the Livingston Pad? 2) This entire investigation occurred because a resident happened to look at the Boulder Air graph. Yet the scientists seem to think it was a short, significant event that they cannot fully explain. How many other short, significant events are there that are similar? Is it possible that someone should be looking at the data regularly with a different lens? 3) Are there any health complaints that occurred during this time?	7/20	Jean Lim	7/20	1) Boulder AIR Response: Based on the wind direction measurements, I think it is unlikely that the plume originated from the Livingston Pad. But I wouldn’t say that it is impossible. Direct transport from Livingston would be more expected with winds from the 200 – 250 degree sector. And maybe give it another +/- 20 degrees uncertainty on each edge. Winds during the spike were outside these windows. But maybe they curved around some, as Daniel Bon suggested. That wouldn’t be impossible. One could look at the wind data from the Apex sensor as another source of information, but I don’t know how well those are calibrated. AJAX Response: We cannot rule out any source within a mile or two of the Soaring Eagle site. The calm winds during the event make it difficult to say anything with certainty. I don’t believe that there is enough evidence for us to confidently suggest any probable source(s). Regarding Dr. Helmig’s bullet assuming “the maximum benzene…was likely”: Boulder AIR’s equipment only saw a portion of the event due to their process of measuring for 10 minutes out of each hour and averaging the concentrations to a 10-minute average. Therefore, Detelv had to make assumptions about what the benzene plume may have looked like before and after his 10 minute measurement window and what the peak of the event may have looked like within his 10-minute measurement window. The PTR-MS and PID sensors on the other hand measured the entire benzene event at 1-minute resolution, meaning that the PTR-MS paints a better picture of the duration and scale of the peak and should be used as the “reference” regarding the event duration and shape in this analysis. The PID measured a 12.6 ppb benzene peak for 1-minute during the event, which supports Detlev’s 10-minute average of 9.6 ppb of benzene in an event that lasted 10 minutes. 2) Boulder AIR response: Well, we actually have an Alert system set up now, and when this event happened, high concentration Alerts for methane and benzene went out automatically within a few minutes to Boulder A.I.R. personnel and to Tami, Meagan, and Andrew (I think?). At least for me the Alerts worked. I went online right away and checked the data. My first thought was that something was wrong with the monitors, but then seeing the consistency in methane and benzene gave me confidence that these data were correct. The Broomfield people on the list contacted me on Monday with questions about the event. So, that all was nice to see. The Alert system seems to be working and people are paying attention and responding to them. It really was the first real test since we got this implemented. Ajax Response: This is a valid question and is a core component of the quarterly reports. From the Ajax perspective, one element of the Q2 report is to assess all of our data in order to find anomalies and events that were not recognized with real-time anomaly detection methods. This is an area where the industry as a whole is continuing to identify methods and innovations for recognizing real events faster and more accurately. As new anomaly detection methods are proven, validated, and put into practice, Broomfield will start seeing some of the benefits of this research. I will also caution and reiterate that there will be events that cannot be fully explained with the data available. Higher spatial coverage, continuous measurement, and good wind data help immensely, though, as is the case here, answers as to cause and source are not always readily discernable. At the same time, we must recognize that the density of the monitoring network and the continuous measurement capability has helped us identify many events where we were able to confidently identify the source throughout the program. 3) As of 7/20, no health concerns were received during the event, or have been received that have been attributed to the event.		0.5
58			There are currently 5 out of 14 sensors down, the most critical of which I would consider Anthem 1 which has been down for almost 48 hours. Yesterday's Daily Update marked 4 down, with 2 under investigation and 2 awaiting parts. It did not include Livingston 3 which went down about 20 hours ago. Is there an update from Ajax?	7/15	Jean Lim	7/15	Anthem 1, Livingston 3, and United 1 processors hung and required restart. These resets are being performed this morning. Anthem 2 and Wildgrass 1 are being shipped from the Apis factory, having been refurbished, re-calibrated, and field tested. Tracking numbers say they will arrive on July 16. We will deploy them either July 16 or the morning of July 17, depending on arrival time. 7-17 Update from Ajax - Two Apis systems, as part of the air quality monitoring program, have been received back from repair were to be placed in the field today. However, there was an issue and the systems will be fixed and deployed next week. As an aside: Livingston 2 is receiving field repairs on the PID sensor today, which should resolve some of the intermittent PID sensor malfunctions on that system.		0.5
59			1) In a July 6 email, I had requested that the analysis state that the Wildgrass 1 sensor was not operational and the Oil and Gas Dashboard reply was "1) Ajax will notice the fact that Wildgrass 01 sensor was down in the trigger analysis report." It is not mentioned in the report. 2) The analysis does not add up to me. "The most likely explanation for this short spike is that the PID responded to a small plume of a VOC that Ajax does not measure in the canisters. Considering the wind direction at the time, i/n Pentane ratio of 1.17, and the concentrations measured in the canister, this was likely an urban-sourced event, for example vehicle emissions, gas station plume, etc. At the time of the trigger event, wind was blowing from the south across the sensor." If the winds were from the south of the Livingston 1 sensor and the source would have been vehicle emissions (there is no gas station to the south), it would have come from Sheridan Parkway. The Wildgrass 2 sensor didn't pick it up (and the Wildgrass 1 sensor wasn't operational). So where did that source come from? 3) What type of VOCs from vehicle emissions might have been present that Ajax does not measure in the canister?	7/14	Jean Lim	7/15	The trigger notification has been revised and updated, it is available HERE. From Ajax: 1) This is an oversight from Ajax, as we did agree to include the caveat that Wildgrass 1 was down during the time of the event. [The trigger analysis notification has been updated to state this] However, Wildgrass 2 would have been the most direct upwind sensor station at the time of the event, with both Livingston 1 and Wildgrass 2 registering 20 mph winds from due South. While we cannot be certain, these appear to be direct winds from the south across both Wildgrass 2 and Livingston 1. Wildgrass 2 did not register an anomaly in the minutes or hours around this event, but it is possible that a narrow plume bypassed the monitoring station. It is also possible that the source stood between Wildgrass 2 and Livingston 1. It is unlikely that Wildgrass 1 factored into this event, though we cannot be certain because the Wildgrass 1 system was offline. 2) The results from the sensor, nor the canister results allow us to pinpoint a source for this small VOC Indicator spike. The PID systems will respond to compounds that are not or cannot be measured in the canister samples. Based on the PID sensor data alone, we are unable to pinpoint source location, nor identify the specific compound that the PID picked up. Said another way, the PID sensor informed us of the event, and canister data and wind direction helps us judge some sources as unlikely. In this case, however, we did not get a clear picture of the most likely source. In our Trigger Canister summary report, we stated: “The most likely explanation for this short spike is that the PID responded to a small plume of a VOC that we do not measure in the canisters. Considering the wind direction at the time and the concentrations measured in the canister, this was likely an urban-sourced event.” For additional clarity, we could add to this statement: “While the plume source does not appear to be subsurface O&G emissions (given the pentane ratio) it doesn’t necessarily have to be traffic. It could be other solvent emissions, for example, that would trigger the PID but that we do not measure in the canisters. This could be things like acetone or various alcohols.” The Ajax-provided Trigger Canister report did not originally mention the pentane ratio. A pentane ratio of 1.17 is somewhat typical for the background air we measure across Broomfield in weekly canisters. 3) We do not have a clear answer for this question. To answer this question, one would need to compare the list of 900+ PID response compounds with available research on the components of typical traffic emissions and then compare the results of that union with the compounds measured in the CSU canisters. This analysis is not on our current roadmap for research or investigation.		1
60			When I was checking out the Boulder AIR monitoring site yesterday, I noticed a huge spike on Sunday morning. Do you know anything about this? I look forward to hearing more from Dr. Helmig regarding these reading ASAP. If that is indeed a confirmed spike, the levels are concerning and we should provide some transparency as to the potential cause. Also, if this spike is confirmed, it will be beneficial to better understand the discrepancy with the readings from the PTRMS which reported a spike, but at a much lower level, and also the reading from the APIS station which did not report an elevated level.	7/13	Resident, Heidi Henkel, Laurie Anderson	7/14	On July 13th, staff requested analysis from consultants A preliminary report can be viewed here. Once additional information is received, the report will be updated. The report has been updated to include a report from Boulder AIR.		1
61			The reply on the Dashboard to my question to ask if the Wildgrass sensor needs to be reset after being moved from Anthem 2 isn't clear. It states, "Ajax has not reset any thresholds as yet. As thresholds are system-specific (not sensor specific), the threshold setting will have moved along with the system from Anthem 2 to Wildgrass 1." I thought the threshold was individually set per sensor. Also, can you please ask Ajax to send the latest threshold settings for all the locations?	7/10	Jean Lim	7/11	Please the attached file for the triggering thresholds for each site. None of the thresholds have changed since the last request for the triggering thresholds. You are correct, thresholds are tied to serial numbers.		1
62			I just noticed that note on the Oil and Gas Dashboard that Anthem 2 had moved to Wildgrass 1. Did Ajax reset the threshold to 250?	7/10	Jean Lim	7/10	Ajax has not reset any thresholds as yet. As thresholds are system-specific (not sensor specific), the threshold setting will have moved along with the system from Anthem 2 to Wildgrass 1.		0.5
63			1) There was no working Wildgrass 1 sensor to make sure the plume did not carry toward the Wildgrass townhomes and western Wildgrass. In the initial analysis of the trigger alert for the July 3 event that was published on July 4, it does not mention that the Wildgrass 1 sensor has not been operational for 9 days since June 25 so it could not have captured the plume. The analysis refers to the fact that the Wildgrass 2 sensor and no other sensors were triggered, but does not mention the Wildgrass 1 sensor was inoperative. Please have CSU mention that in its trigger canister report. 2) In response to my 6/29 question, the Dashboard states, "Staff will work with Ajax to determine if other sensors can be moved to these locations in the interim." Has that conversation occurred? Thank you.	7/6	Jean Lim	7/7	1) Ajax will notice the fact that Wildgrass 01 sensor was down in the trigger analysis report. NOTE: It was determined that wind direction was from the south across the sensor during the trigger event (not the north, as originally reported). This has been noted and corrected in the original trigger notification. 2) Staff is working with Ajax on a plan to redeploy a sensor to Wildgrass 01. Candidates are United 01 and Anthem 02. The relocation of the Anthem 02 sensor to the Wildgrass 01 location was completed on July 7, 2020.		1
64			JUNE 2020 - Below
65			...does Extraction need to be warned that BMP 20 D applies for tomorrow? Does removing the sound walls violate the BMP on an ozone alert day?	6/30	Jean Lim	6/30	Extraction is aware of ozone alerts, as is required by BMP 20. The sound wall work will not begin until the week of July 6th.		0.5
66			Is there an estimated date for the new antennas to be installed by Ajax to enable the Wildgrass 1 and United 2 sensors to be operational again?	6/29	Jean Lim	7/1 6/29	July 1 Update - The United 02 and Wildgrass 01 systems have been returned to the manufacturer for repairs. Staff will work with Ajax to determine if other sensors can be moved to these locations in the interim. Two antennas were ordered by Apis on June 29th, they will ship to Broomfield (estimated arrival will be posted here once we have a tracking number). Ajax technician is working on Wildgrass 01 sensor today (June 29th), intermittency may be due to a computer processing unit (CPU). Will post updates here. The Anthem 02 sensor is being relocated to Wildgrass 01 on July 7, 2020.	Update as new info received	1	A.V.
67			(Regarding the newly added ozone information on the Public Health webpage...) 1) So will there never be an ozone alert level that is sent from Boulder Air to staff that gets passed to Council or the public? 2) Will Extraction be reminded of and be held to BMP 20 D in the OA: D. Air Quality Action Days. The Operator shall respond to air quality Action Day advisories posted by the Colorado Department of Public Health and Environment for the Front Range Area by implementing their suggested air emission reduction measures as feasible. Emission reduction measures shall be implemented for the duration of an air quality Action Day advisory and may include measures such as: 1. Minimize vehicle and engine idling; 2. Reduce truck traffic and worker traffic; 3. Delay vehicle refueling; 4. Suspend or delay use of fossil fuel powered ancillary equipment; and 5. Postpone construction activities, if feasible. 6. Within 30 days following the conclusion of each annual Air Quality Action Day season, Operator must submit a report to the City that details which measures it implemented during any Action Day advisories.	6/24	Jean Lim	6/30	1) After discussion with Boulder AIR, ozone alerts from Broomfield would require more programming by Boulder AIR that would take time and more staffing by Broomfield to maintain. Residents that are interested in receiving ozone alerts can sign up for notices posted by the state. We have posted the link to sign up for State notices as well as links to Boulder AIR ozone information on the Public Health website here: https://www.broomfield.org/687/Air-Quality. We will circulate this information about how to sign up for ozone alerts via the State's system to Broomfield Department Directors to consider in planning their operations. 2) Extraction must comply with BMP 20 during ozone alert days.		5
68			Are all the sensors down since 6 pm or is the live feed not working?	6/24	Jean Lim	6/24	Ajax is aware of the issue, it appears to be a software/web issue on the Apis side. The Ajax site is up and the sensors are collecting data. Will work with APIS to correct the issue. The sensors were offline due to a synchonization issue between the data feed and the public webiste. All data has been restored.		0.5
69			(Regarding the newly added ozone information on the Public Health webpage...) Is this part of the public communication process for the Boulder Air Soaring Eagle ozone alert notices? Will Boulder Air notices still be sent/posted providing referrals to the Air Quality Monitoring page? The long range weather prediction looks like we are going to hit a drier hot stretch (inevitable towards July), so I was wondering if we were ready for a repeat of ozone alerts.	6/23	Jean Lim	6/23	Posting the AirLive website and CDPHE's air quality website on the Public Health (PH) webpage is part of the communication process to residents about ozone. PH has also added a paragraph to the website explaining the importance of ozone awareness, encouraging residents to check ozone levels in order to protect their health. PH will not be able to send out real-time notices to the public each time Soaring Eagle ozone hits 70 ppb. As we move into summer, this will happen regularly and PH advises residents to check ozone before engaging in outdoor activities. Boulder Air notices will still be sent to staff to keep us informed about ozone above 70 ppb throughout the day. So we will probably see a repeat of ozone alerts.		0.5
70			Did the 6/3 Anthem 2 trigger canister analysis come back from CSU yet? https://drive.google.com/file/d/1t8hWMbJvxgfIgBdIIxlcPQpST_XbZ0vG/view	6/18	Jean Lim	6/19	The report from the June 3, 2020, trigger event at Anthem 02 can be viewed here.		1
71			The Oil and Gas Dashboard is marked that on 6/15 Ajax was performing routine maintenance on some of the sensors, including Wildgrass 1. On 6/8 it was reported that the Wildgrass 1 sensor has always flipped several times a day between online and offline. The current past 12 hour log shows this pattern is still continuing. 1) Is Ajax aware that this problem is not fixed? 2) Has the factory opened to get new equipment?	6/18	Jean Lim	6/18	1) Ajax is aware of the problem with Wildgrass 01. It appears to be a cellular connectivity issue. Ajax is exploring the root cause and is working to resolve or mitigate cellular connectivity issues. 2) The factory has opened with limited capacity. For this particular issue, a new system would not solve the problem with cellular connectivity.		0.5
72			FYI FROM SI STAFF: Ajax is performing routine maintenance on some of the sensors, and we may see some trigger notifications (Prospect Ridge and Wildgrass 01 have triggered so far). Ajax has confirmed that these are not air quality events, they are strictly related to the maintenance.	6/15	n/a	6/15			0
73			Can you ask Dr. Helmig why the maximum wind speed over the last 24 hours is only 11.35 m/s (25 mph)? A resident pointed out to me that she is pretty sure it was windier than that last night.	6/9	Jean Lim	6/9	Please see Dr. Helmig's response here.		0.5
74			There are currently 5 sensors down. My guess would be that 3 could be attributed to the 11 pm storm but there are 2 that have been down since 6 pm yesterday, including Interchange 2 again. - both Wildgrass 1 and 2 sensors and Livingston 3 have been down since the 11 pm -midnight storm time frame - United 2 has been down since 6 pm yesterday - Interchange 2 came up for about 2 hours yesterday afternoon after being down for 48 hours but has been down again since 6 pm yesterday.	6/9	Jean Lim	6/9	After the manual power cycles and firmware updates, the network stabilized at about 2PM June 9th. If Wildgrass 01 continues to experience intermittency, Ajax will consider adding an antenna upgrade (intermittency at this sensor is caused by loss of cellular signal). The Apis factory in Ohio is still shut down (COVID related), so obtaining replacement parts continues to be a challenge.		0.5	Ajax, A.V.
75			Interchange 2 has been down since 3 pm on Saturday 6/6. Is Ajax aware of that? The downtime was not noted in the 6/7 Daily Update, but I know that you said not to expect that to be updated over the weekend. The Wildgrass 1 sensor has always flipped between online and offline a couple of times a day (see typical 24 hours from Sat night to Sun night), with downtime gaps of much more than any other sensor. Can we ask Ajax if they know what is wrong with that sensor?	6/8	Jean Lim	6/8	Please see the response from Ajax below - Interchange 02 needs a firmware update which is the reason for the power outages. The firmware will be updated by Wednesday. In the meantime the Broomfield team is working with Ajax to manually cycle the power. (power reset manually on 6/8 by Broomfield staff) As for Wildgrass 01 it looks like brief periods where it's not getting cell service and it could have been caused by the weather that came through this weekend. There is not much can we can do in this situation but if it does continue I can install an external antenna.	Will watch to determine next steps on Wildgrass 01	0.5
76			(Regarding the information in the FAQ regarding the Plumetracker) Have we not seen that data from the runs? Or does that represent the number of times it could possibly go out under contract? Does the data belong to CSU?	6/8	Jean Lim	6/8	CSU budgeted about 30 deployments for the year. As you know, those are not spaced equally; deployments are made based on operations and weather. We do sometimes go out fairly frequently (e.g., 5 times from 4/15-4/22 after flowback started), but reduce frequency when operations are limited and/or the weather is conducive to good dispersion of pollutants. (Staff has requested plumetracker data and will share it once available.) The information in the FAQ has been corrected. See Plumetracker data >>>		0.5	SI	All raw plumetracker data since 3/21/19 can be seen HERE.
77			Did the wind knock a few sensors out? Interchange 2 since 13:40 Wildgrass 1 since 13:40 United 2 since 15:30	6/4	Jean Lim	6/5	Ajax has dispatched a field tech to diagnose the issue, strong winds are a likely culprit. A manual power cycle may fix problem. Back online at 9:30 p.m. Wildgrass 01, and Interchange 02 were running but lost cell service. Both reset United 02 the wind had ripped the solar panel off the pole and launched it into to field. Luckily, no damage to panel. Fixed The solar panel at Livingston 02 was spun 90°. Fixed checked the wind speed. Livingston 02 weather meter showed wind speed almost 90mph (cat 1 hurricane is 74) that was some serious wind.		1
78			What is the followup to the May 25 Trigger Canister report? 1. The report did not state that Staff asked Extraction what the operator's log records show was going on at 4 a.m. on May 25 on the Livingston Pad. We need to get that answer sooner rather than later, due to Extraction's changing circumstances. 2. What were the Boulder AIR or CSU PTRMS readings at that time? I think the CAMLL was there also.	6/2	Jean Lim	6/2	1. During the site visit on May 25, staff asked Extraction if there were any unusual activities that morning. Extraction employees stated "Operations were normal during that time frame." 2. Ajax states that all other monitoring systems had readings at the low end of normal background levels at this time with nothing of interest to report. These results are not surprising considering wind direction during this event. They cannot speak to whether these could be considered dangerous levels or what Extraction may have been doing at the time. They stated they can confidently say that this plume did not likely go into the Anthem or Wildgrass neighborhoods and most likely dispersed quickly as its distance from the pad increased. See additional data from Boulder AIR. >>>		0.5		Data from Soaring Eagle Park (Boulder AIR) on morning of May 25th: Methane @ 4:25AM = 2,012 ppv (regional background = 1,910), Benzene @ 4:46AM = 0.05 ppb, i/n Pentane ratio @ 4:27AM = 1.53 (less than 1 may indicate O&G influence in air mix) CDPHE CAMML data is available HERE, flowback phase has now been added.
79			The Anthem Ranch 2 sensor triggered at 313 during our Friday 5/29 call at 10:39 am. It reached 336 on 5/31 (see link below) but the May 31 Daily Update was not marked with any triggered canister. Did Ajax again adjust the threshold?	6/1	Jean Lim	6/3	We did update the trigger threshold for a short time (from Friday to Monday), as the daily cycle is expanding with summer temperatures and the Ajax team was proactive about adjusting the thresholds. Brent had not communicated to the team about the new communication requirements around resetting thresholds until Monday. This mistaken trigger threshold change has been changed back to 300 and we will communicate prior to any further changes. With summer and higher temperatures approaching, we do expect to see all the sensors running higher baselines - and this potentially more triggered canisters. Ajax will not adjust trigger thresholds to account for this until trigger canisters are analyzed and can justify setting higher thresholds. All trigger threshold adjustments will be communicated in a timely manner.		2
80			The United 2 sensor continued to basically be down all weekend, continuing since 5/27. It doesn't matter now that Extraction is moving off the pad, but my objection remains that it was down during half of operations there. Also, the May 31 Daily Update is marked that all 14 sensors were operational when United 2 was not operational more than half the time.	6/1	Jean Lim	6/1	The United 02 sensor has been experiencing cellular connectivity issues since it was moved outside of Extraction's right-of way. Ajax is aware of the problem and is currently working to solve it. The sensor data in the daily snapshot is only updated on weekdays, on weekends the snapshot only updates: triggered canisters (if any), complaints filed (if any) and information from inspections & site visits. (Staff revised the form to make this more evident.) See additional follow up >>>		0.5		The United 02 station has been repositioned on the pole to gain a better cell connection and it appears it be more stable. If the issue continues to occur an external antenna will be installed to gain better coverage. 6-3-2020 update - The issue with United 02 cell connectivity has been resolved. We should see more stability at this site going forward.
81			MAY 2020 - Below
82			It is my understanding that AJAX offered to have their systems audited (or am I wrong? I could be), so does the price of the auditing fall on AJAX or us? Did I misunderstand this? I thought Helmig has his systems audited without charging us for it. Who does the auditing for Helmig?	5/28	Heidi Henkel	6/9	Neither Ajax or Boulder AIR are required to pay for a third party audit under their respective agreements. Here is a link to Dr. Helmig's proposal as a possibility for an audit (received 6/8/2020). It appears he would be doing some comparisons himself and that he wants to ask CDPHE to review once a year.		8
83			Is Ajax/CSU in compliance with the contract in terms of sensor up time requirements, canister trigger requirements, etc.?	5/28	Liz Law-Evans	5/28	The provisions from the Ajax agreement on sensor uptime are set out at the bottom of this email. Basically, what Broomfield agreed to in the Ajax agreement regarding how sensor uptime would be measured is a % measurement of the data recorded from the date each sensor went on line overtime. Please see linked document. To date for APIS sensors the numbers are: Sensor down (null) 13,980 6.62% Sensors up (non-null) 197,307 93.38% Total 5-Minute Readings 211,287 100.00% Here is the language regarding the standard from the Ajax agreement requiring 90% up time: We commit to 90% uptime for monitoring stations, calculated on a rolling 12 month basis. We calculate this SLA as the percentage of metric measurements recorded vs. the percentage of metric measurements possible in the prior 12 month period. Sensor system downtime events outside of our control, such a prolonged weather events that drain the solar/battery systems and cellular service outages are removed from the SLA calculation. For all service level availability, if 12 months of information is not available, then the rolling 12-month basis will be calculated using the information from the total number of months available.		0.5
84			What was the original stated intent of the Ajax/CSU system? Was it designed to be an early warning / immediate health warning system, akin to tornado sirens or an Amber Alert? I’d like to go back to the original “charging” documents to look in to this.	5/28	Liz Law-Evans	5/28	You are correct the sensor system is not an emergency response system. The Ajax agreement objectives are: o Qualify and quantify air contaminants in short-term acute and long-term chronic intervals o Provide insight regarding emissions sources o Provide data that compares to standardized chronic and acute health guidelines o Share information with citizens o Provide timely air quality information for Broomfield This information is from page 13 of 63 of the scope of work for the Ajax agreement here.		0.5
85			What is the cost of the “third party audit” and why is it necessary? I do remember one or two council members discussing this idea, but did council vote on it?	5/28	Liz Law-Evans	5/28	As indicated in the email to Council today, an independent audit of the system has been priced at $23,590. This email on the audit was sent to Council today. (see email here) The general purpose of the audit is to strengthen the measurement processes and overall program, by identifying vulnerabilities or weakness in the quality system or the defensibility of the data. Council did not vote on this audit agreement and the proposal was just received today.		0.5
86			At 2:30 pm, the Anthem 1 sensor went down and Anthem 2 did not trigger a canister at 207 (also not at 247 at 11 am). The Anthem 1 sensor is still down. Does Ajax know it is down and what are they doing to bring it back up? Any emissions from Livingston carried by winds flowing directly north from Livingston would either not be detected by an offline Anthem 1 or be ignored by a high threshold at Anthem 2.	5/27	Jean Lim	6/3	Anthem 01 came back online on 5/28 @ 3:20 PM. The trigger threshold is set at 300 for this sensor, so we wouldn't expect to see a trigger at 207 or 247. Ajax saw an error reading for about 8 hours on 6/1 (the sensor displayed 50 mV which is indicitave of a hardware issue). The data suggests that the issue self corrected as the sensor now seems to be reading normally, however out of an abundance of caution we are working with Apis to replace the PID sensor. In the meantime, Anthem 01 is still online and the trigger canister is active.		5		The United sensor was experiencing cellular connectivity issues. In the interest of the concerns around United operations, we have again juggled the sensors around in an attempt to resolve the issue. The unstable cellular system that was at United is now at Prospect Ridge. This move allows us to test whether the cellular issue is just this particular sensor at the United site. The hope is that both sensors are stable after this move. If the system is also having trouble connecting at Prospect Ridge, we’ll get in a new cellular modem and antenna and replace them.
87			Air emmissions from the extraction project (or the Davis leak?) seem to be running high. Any plans to address the issue?	5/27	Resident	5/28	Staff is working with the COGCC and its consultant on the mediation for the Davis 43-6 leak. Work has been delayed due to COVID, however we hope to have a detailed schedule of work soon.	update with schedule once known	1		From the COGCC Engineering Manager: The source of methane has been removed by plugging the well. Mike has stated on several occasions in written correspondence to you that there is no current health or safety hazard from the residual subsurface methane and that the in situ extraction or treatment process will not be rapid. If successful, the summer pilot test data may be used to design a full-scale system, which would likely require a formal bidding process. The bidding process normally takes three to four months before work starts in the field. If, based on the pilot test results, soil vapor extraction is not a desirable technology, then a feasibility study to evaluate other in-situ technologies may have to be considered. In my personal experience with in situ remediation technologies, including soil vapor extraction, full scale operation and monitoring typically takes months or years.
88			During the May 12 Council AQM presentations, all of Council heard about the huge unexplained May 12 1 am methane spike at Soaring Eagle that stumped both Dr. Collett and Dr. Helmig. Dr. Helmig's 5/22 preliminary analysis posted on the Oil and Gas Dashboard doesn't rule out that the spike came from the Davis 43-6 well (in remediation by COGCC) or Davis 42-6 well under the lake just NE in Anthem Highlands, based on light wind direction. Dr. Helmig concludes, "I would say that these suspected source areas are probably within the uncertainty window of this preliminary analysis." What are the next steps to find the source? There are indications that these late night spikes are reoccurring. 1) Winds were calm on May 17 around midnight but there were large ethane and propane spikes shown at Soaring Eagle Boulder Air. See attached. 2) There were also smaller but significant methane spikes at around midnight on May 22 and 23, with no winds. See attached. That showed up at the same time there were TVOC elevations at Livingston 3 sensor also. 3) There were trigger canisters due to high TVOC readings on May 25 at 4 am at Livingston 2 and 3 that Ajax thought might have come from Livingston. What is the next step? A few of us think we need the COGCC to take further action on the Davis 43-6 well, but here are some other possibilities I gathered from talking to a few people: 1) The retired atmospheric scientist from Anthem Ranch suggested Dr. Helmig might consider doing an isopleth analysis for May 12.	5/26	Jean Lim	5/27	Below are responses provided by Dr. Helmig: I don’t see a whole lot more that can be added to the analysis of this particular event. What we can do soon, though, is to take the full data set and do a footprint or heat map analysis. It averages over all available data and identifies the wind direction/sectors that are most often associated to elevated methane concentrations. So, if this wasn’t just a single event, then this sector should show up as a prominent methane source. Another thing worth doing would be to go out to the two suspected well sites for a very thorough leak inspection. Late night spikes - questions 1), 2), 3): It seems that most of the elevated methane spikes have been associated to transport from the north to east sector thus far. Next Steps 1) (Regarding the isopleth analysis) I am not sure what she/he means with that, but I’d be happy to have a conversation. What we usually do are analyses of the association of elevated concentrations with wind direction and wind speed. This is a fair amount of work to do, though, and would be hard to squeeze in right now as we are still very busy with finishing up loose ends at SE and working on the assembly of the VOCs system for the satellite site.		1
89			I read on the Trigger Matrix alert that Ajax thinks that the Prospect Ridge sensor got flooded. It is still reading at the same 3200+ level. Is Ajax thinking the sensor is ruined but they don't have another sensor to replace it?	5/25	Laurie Anderson	5/26	The manufacturer (Apis) believes this is a failed sampling pump, not the actual sensor. This part can be swapped out, Ajax is currently diagnosing the situation with Apis. Ajax response - In essence, yes, we suspect that either the PID sensor or the sampling pump at Prospect Ridge are faulty. We are investigating today and expect to be able to have parts overnighted for a field repair this week.		1
90			Yesterday's Daily Update stated that "the on-duty night inspector also captured a grab sample canister at the exit to the pad at 4:45 a.m." Was that our noise guard? Was there something the inspector saw or smelled that prompted him to take that sample at the entrance?	5/26	Jean Lim	5/26	The night staff have been trained to take a grab canister if an odor, air, or trigger event notification comes in while they are on duty. The night staff received the trigger event notification for the Livingston Pad (via email) and took the canister sample. That sample will be analyzed by CSU and the results will be shared.	Sample result data to the right.	0.5		Overall concentrations of methane, BTEX and other VOCs were very low, data can be viewed HERE. (McFannisn)
91			(In regards to the NMFRD response to the trigger event.) Was this a similar process by NMFRD where they used their 4 gas meter to check around the areas of the schools? And then would this be nothing of concern as it relates to something that could result in an explosion, but not necessarily from a health concern standpoint?	5/25	Laurie Anderson	5/25	Yes, this was a similar process. We will follow up with the analysis from CSU once received.	Trigger canister report linked at right. This was a sensor malfunction, not a air quality event.	0.5		This was a sensor malfunction, not a air quality event. Trigger canister report linked HERE.
92			A resident alerted me that there was a huge TVOC spike of 3294 at Prospect Ridge beginning at 17:40 pm that is still continuing at a level of 1633. Was there a canister triggered? If not, can you send someone to grab a canister sample? Is it safe in the area since it is staying elevated? If you know something to alleviate our concerns, please let me know.	5/24	Jean Lim	5/24	The trigger canister has been changed. Ajax is triggering another canister now. No other sensors triggered. We are checking PTR-MS data. A fire engine has been dispatched to check it out. NMFRD completed its inspection at Thunder Vista and Prospect Ridge tonight and there was nothing of concern. The NMFRD report can be viewed here.	Trigger canister report linked at right. This was a sensor malfunction, not a air quality event.	0.5		Trigger canister report linked HERE.
93			Has AJAX presented any solutions or are they able to fall back on the 90% downtime rate in their contract vs working to solve the issue? What action is the City prepared to take to keep Extraction from spudding the United pad, creating more health and noise issues, and ruining more land in Broomfield?	5/18	Broomfield resident	5/21	With regard to your statement about 90% downtime for sensors under the Ajax agreement, the agreement calls for 90% up time for the sensors over a rolling 12 month period. To date Ajax is running about an 84.84% up time with the sensors. [see SLA data HERE) All triggers and canister analysis can be viewed here: Trigger Matrix - DRAFT - Google Sheets Despite Extraction’s financial difficulties, it is currently complying with the law and the terms of its contract with Broomfield. Under that contract and the state issued well permits, Extraction is legally allowed to spud the wells on the United Pad. Our inspectors continue to inspect Extraction’s operations to ensure it complies with the terms of the Operator Agreement. The COGCC continues to perform its oversight duties regarding the Extraction operations as well. Any successor in interest to Extraction whether by restructuring, assignment or through bankruptcy will be required to comply with the terms of the Operator Agreement and to comply with State and local law. If Extraction is unsuccessful in restructuring its debt, then it may file for bankruptcy, if that happens Broomfield has retained bankruptcy counsel to represent it.		3
94			Yesterday's daily update stated that spudding was to start last night. With that in mind, I looked at the United 1 sensor and saw a very large spike at 2 am. At 2 am, it was 80, at 2:05 am it was 160, and at 2:10 am it was 86. Should that have set off a trigger? It was a large spike on the first night of spudding and it is hard to imagine it was caused by anything but Extraction operations at 2 am.	5/21	Jean Lim	5/26	160 Mv is still well within the normal ambient range for the Apis sensors, which is 80 Mv to 200Mv. An air quality event would be indicated by a sustained reading that was elevated 2x to 5x the normal range. We would not expect a trigger canister to be activated for this event. While this sort of very small spike could be considered an event, the scale suggests that it could be something as simple as a passing vehicle and unlikely to contain levels of pollutants that would warrant a trigger canister sample.		4
95			From Councilmember Lim: I appreciate that you shared your concern in order to protect data value for future purposes. However, we paid for an Ajax/CSU sensor and trigger canister system to detect short term spikes and then provide more complete analysis of trigger canisters when these spikes occur. Our residents know how to read graphs to see how often the Ajax sensors are down and how trigger canisters are not triggering at levels that they previously triggered at. If the sensors are not online or not triggering at the correct levels, we will not have any trigger canister analysis to support the goals you stated. How do you propose that we correct the system deficiencies and hold Ajax/CSU accountable? Today, 3 main sensors near our communities had readings above 200 for 4 hours (Soaring Eagle, Anthem 1, Thunder Vista, see May 20 graph). These sensors have triggered at 200 in the past but yet none triggered today. Yesterday, the Thunder Vista sensor did not trigger when it went up to 260. You can see from the 7 day graph that this was a large spike compared to the 7 previous days of the week. Soaring Eagle was up to 254 yesterday but did not trigger and it triggered at 220 on April 30. (See May 19 graph.) After over a year, there are still a lot of deficiencies in the sensor and trigger canister system from Ajax/CSU. They need to be held accountable for their contracted services which we had hoped would provide data to examine in conjunction with health impacts From Councilmember Shaff: I align with your stated goals of “using the information we are gathering to inform public policy at the state (COGCC & legislature) and local level and perhaps support legal action.” And while the combination of these 2 programs might compete for the “most sophisticated air monitoring program focused on oil and gas development in the state” that does not mean it is without deficit, fault, or weakness. Many of us following the battle between local communities and the industry for years, have seen studies, data, and information continually discounted. I would think that if our “most sophisticated...program” cannot hold up to Councilmembers and our Public questioning the information or calling out the faults and weaknesses, then it surely won’t hold up to the industry or in a scrutinized arena. So, I would propose that we continue to strive toward making this program the most sophisticated air monitoring program in the state (and country), ensure our contract is being adhered to by all parties, and the information/data continues to be scrutinized to that it will hold up for discussions for public policy and in the courts. The points made by Jean below and previously by affected residents and other Councilmembers if not made by them, will most certainly be eventually made across the table in a policy discussion or in court by people payed to find faults in the data. I would prefer we mitigate these faults now rather than be surprised down the road.	5/21	Jean Lim & Deven Shaff	5/21	Below is an email from Ajax in response to concerns about the sensors from Council Members Lim & Shaff. Please let me know if you would like additional follow-up on these responses. I would add that in response to Council Member Henkel's request, Broomfield has requested a proposal for an audit, from a firm with specific background in auditing air quality monitoring equipment, to conduct an audit of the sensor system. This firm does testing of the EPA's Clean Air Status and Trends Network, which includes audits of EPA's air quality monitoring testing stations https://www.epa.gov/castnet. The firm also provides audits for the National Atmospheric Deposition Program http://nadp.slh.wisc.edu/. I have shared information on our air quality monitoring program, the APIS sensors and other data with the company and should have more information on an audit proposal and cost this week. From Ajax: The Apis systems are working correctly and as expected. We did experience some downtime in the first few weeks of each sensor’s deployment – discussed during the sales cycle and in the contract as the stabilization period or field testing period. Most systems are stable now and all indications are that we are nearing the end of this stabilization period. We have responded to the baseline/trigger threshold question multiple times in the last few weeks, summarized below: Daily fluctuations in the daily baseline cycle are not air quality events that require trigger canisters. This baseline range is part of the nature of PID sensors. The move into summer-like temperatures are shifting the baseline ranges into higher voltage measurements. This is supported by PTRMS and BoulderAir GC measurements that are not showing a similar afternoon increases in VOCs. Trigger thresholds are currently set as a percentage change from baseline. Each system is currently set with a threshold of an approximately 200% increase over baseline. We have adjusted the thresholds one time thus far in the program and expect to adjust them regularly as we continue to build our understanding of the voltage/canister concentration relationship. We do not want to set the thresholds too low, as we do not want to risk triggering a canister on a non-VOC response, but rather keep the system armed and ready to trigger should a high VOC plume cross the site. As we collect more data, we do reserve the right to adjust the thresholds and triggering algorithms in order to improve the system. In order to address this trigger threshold concern, we can offer to lower the thresholds at some sites and trigger a few canisters at these lower baseline-range levels. This may help prove that VOC concentrations are not high in these airmasses, though this would come at the risk of missing out on real VOC events. Please let us know if this is something you would like to do. If you believe a sit down meeting could help resolve this ongoing concern, please let me know and I’ll be glad to join a discussion with all concerned parties.	Staff is scheduling a meeting	0.5	TY
96			The Livingston 2 sensor has been down since 11pm yesterday (May 18th). Do you know if Ajax is aware and working on a solution?	5/20	Resident	5/21	This sensor has been mostly stable since it was installed on Feb 16 with 96% service level availability (up-time). The sensors do still experience some intermittency due to electricity supply and cellular connectivity, but this is normal. From Apis data: 1,101 null records out of 27,538 total records - 5 minute intervals	reason for downtime	1	AV
97			The response to the resident's 5/19 question from the COGCC on the Davis 43-6 well does not seem to recognize the earlier COGCC pledge to "install a soil vapor extraction system (SVE) on the site in order to extract the methane vapors via vacuum." (See earlier March 20 email.) Are they just going to seal the pavement and not remediate further? Maybe that is a question for the Zoom site visit or should it be asked now?	5/19	Jean Lim	5/19	Meeting on Friday 5/22 with COGCC, and the contractor to discuss.	Transcript of meeting will be posted ASAP	0.5	T.Y & E.P.	Unfortunately the teleconference with Mike Hickey and the group did not go very well today because Mike was in the field and those of us on Google Meets could barley hear any of the discussion. Consequently, I don't have any details right now to report or use to answer questions. Mike says he is putting together information and a transcript from the meeting to send out to everyone. I have emailed him to make sure he includes us on the distribution list of this information.
98			It is absolutely puzzling to me with so much volatility in this sensor system how we are supposed to trust that the trigger canisters are going off when necessary to protect residents from short term spikes or to examine these short term spikes for health impacts later. The latest response from Ajax is that there is no set threshold across canisters and "any tangible increase in VOCs such as benzene will be represented by a shift of over 200% of the baseline voltage (we continue to assess this as we get more data)." Even if I accept that relative shift criteria, the "new" Thunder Vista sensor should have triggered. It went up to 258 yesterday and 260 today. You can see from this 7 day graph that these past 2 days show large spikes compared to how the "new" Thunder Vista sensor has been reading. What is the trigger set at? I have residents asking me if Ajax moves the trigger on the fly so the canister doesn't go off. Soaring Eagle is now up to 254 and it triggered at 220 on April 30. Do you see why residents claim the trigger levels are being conveniently reset?	5/19	Jean Lim	5/19	Please see 5/21 response. From Ajax: We will put together a report on trigger baseline methodology and timeline for changes and adjustments to the network. We can make this available to the public along with a tutorial or explanation of rationale. It is true that sensor thresholds have been reset (once so far in the program), we have been transparent about our method of starting with low thresholds, and increasing the thresholds as we gathered trigger canister data that inform when we should trigger the samples.		0.5
99			I read on the Dashboard that Ajax stated that the United 1 sensor cannot be replaced because the sensor factory is shut down and we just have to deal with the high readings. A resident who drove by 160th and Huron this morning told me the Ajax truck was there. The data shows that United 1 was offline for about 2 hours and is now running lower. Did Ajax switch the United 1 sensor with another one? That happened at Thunder Vista before. Thank you.	5/19	Jean Lim	5/19	Today, Ajax switched the Anthem 2 sensor and the United 1 sensor. Ajax makes the following comments on the current Anthem 2 sensor: Moving the sensor system accomplished the objective that we set out to validate (and which was communicated through email and during the council session: It confirmed that this particular sensor simply has a higher baseline reading, as the higher baseline reading is also experienced at United 1. These results also confirm that the Thunder Vista area was not simply experiencing a higher level of VOCs in the air (which was the stated concern). We do not believe that minor discrepancies between sensor baseline values are a problem. Each sensor is providing its value regardless of whether the baseline range is 50-100 millivolts, or has a baseline range between 150-200 millivolts. Based on our findings so far, any tangible increase in VOCs such as benzene will be represented by a shift of over 200% of the baseline voltage (we continue to assess this as we get more data). The actual voltage reading is immaterial from the perspective of the system operating effectively. I believe the core issue to be resolved here is that presenting line graphs of voltage is misleading users and causing undue concern, as most people will intrinsically believe that “lower is better” and “higher is worse”. I look forward to exploring new ways to present this information so that we can help users to intuit “normal” vs. “slightly elevated” vs. “high” readings in a consistent way across the network. The trick is in presenting this data in an intuitive way without losing transparency, nor giving the impression that we are hiding anything in our treatment of the data or in the method of presentation.		0.5
100			Regarding Davis 43-6. I was surprised to read that the COGCC is not going to mitigate the soil to eliminate the methane at this time. Since the oil and gas industry is considering essential, I think the regulation of it is equally essential. This is outdoor work and it seems like physical distancing could readily be done. I know the methane is underground, but it is odd that the air quality monitor near by keeps registering high methane levels. What is the COGCC's rationale for not doing this work? What can the city do to pursue it?	5/19	Resident	5/19	spoke Monday with the contractor who will be scoping the soil gas extraction for the residual gas on this site. We are preparing a site visit that will follow the physical distancing and "Safer at Home" protocol. The Orphaned Well Program has been doing all site visits remotely. Antea has a single individual who needs to see the site in person to adequately assess it. Everyone else will be allowed to attend a Zoom that I will host on site. I do not have a date for that meeting yet, but scheduling is under way. We also will be replacing pavement on site that was damaged during the plugging process. We have obtained a place on the list for asphalt and are awaiting scheduling. The contractor who will handle the paving and concrete work is currently working for us in Logan County. I contacted Broomfield on May 1 to update them on where those plans stand. We continue to provide an appropriate balance between compliance with "Safer at Home" and responsible regulation of the oil and gas industry in Colorado in a manner that protects public health, safety, and welfare, the environment and wildlife resources. Dr Helmig's assessment of a recent methane event can be viewed HERE.		0.5	TY	Meeting with COGCC and contractor scheduled for 5/22
101			In refernce to 5/18 reply and follow up: time sensitive question about getting a new sensor for United 1 instead of using the misaligned one from Thunder Vista. This is time sensitive since spudding will start on United on 5/20. The Daily Update from yesterday shows how out of whack this sensor is. It states, "United 01 274 mV @ 2:20 p.m., May 18, 2020 - above normal range, below trigger threshold" but also states, "(Normal range is between 80-200 mV)." Can Ajax get a new sensor for United 1?	5/19	Jean Lim	5/21	The Apis sensor factory has been shut down due to COVID so no new sensors are available at this time. It confirmed that this particular sensor simply has a higher baseline reading, as the higher baseline reading is also experienced at United 1. These results also confirm that the Thunder Vista area was not simply experiencing a higher level of VOCs in the air (which was the stated concern). There were no trigger notifications since thresholds are set as a percentage above baseline, and as each sensor has a different baseline, thresholds are set differently throughout the system. We do not believe that minor discrepancies between sensor baseline values are a problem. Each sensor is providing its value regardless of whether the baseline range is 50-100 millivolts, or has a baseline range between 150-200 millivolts. Based on our findings so far, any tangible increase in VOCs such as benzene will be represented by a shift of over 200% of the baseline voltage (we continue to assess this as we get more data). The actual voltage reading is immaterial from the perspective of the system operating effectively.		2	TY
102			The 5/18 Daily Data Snapshot sent out at 5 pm says that there were no triggers. Yet Thunder Vista was above 200 from about 2:45 pm to a peak of 258 at 4:30 pm and Soaring Eagle was above 200 by 4:30 pm also. I did notice that both high readings were marked on the Daily Data at 2:20 pm with a Thunder Vista reading of 197. So should I expect the 5/19 Daily Update to be marked with triggers from the 5/18 readings after 2:20 pm? Daily Update (Normal range is between 80-200 mV) https://drive.google.com/file/d/1JXfn1GzyaUaD-0DL6nWDdA_Agvuq53sr/view High readings onThunder Vista and Soaring Eagle 210	5/19	Jean Lim	5/21	It confirmed that this particular sensor simply has a higher baseline reading, as the higher baseline reading is also experienced at United 1. These results also confirm that the Thunder Vista area was not simply experiencing a higher level of VOCs in the air (which was the stated concern). There were no trigger notifications since thresholds are set as a percentage above baseline, and as each sensor has a different baseline, thresholds are set differently throughout the system. We do not believe that minor discrepancies between sensor baseline values are a problem. Each sensor is providing its value regardless of whether the baseline range is 50-100 millivolts, or has a baseline range between 150-200 millivolts. Based on our findings so far, any tangible increase in VOCs such as benzene will be represented by a shift of over 200% of the baseline voltage (we continue to assess this as we get more data). The actual voltage reading is immaterial from the perspective of the system operating effectively. As we move into summer, I expect that we will need to adjust our Normal range as we learn about the influence of much warmer temperatures on the sensors. Though we won’t be able to do that until we have enough data to develop statistically relevant observations. Regarding trigger samples. We did not reach trigger thresholds. And I don’t see anything that indicates an event outside of the sensors’ regular diurnal cycle.		2
103			3 Anthem Highland residents smelled sulphur dioxide about 8:10 pm. They also saw a H2S spike on Boulder Air and called NMFD. I drove to Soaring Eagle and walked toward the pad, getting intermittent whiffs of something (I don't think I am the best at detecting smells). Anyway, I saw the NMFD truck driving south on Lowell and started walking back north to the car at Soaring Eagle, figuring it was okay since NMFD had arrived to check. It took me about 10 minutes to get back to the car and then a few minutes to go south on Lowell and right on Sheridan. When I drove past the entrance to the pad, there was the NMFD truck sitting waiting at the gate with the XOG guard there. I thought what the heck, why isn't that fire truck allowed on the pad right away. Then when I circled back around to go north on Sheridan to see what was going on, a pickup truck that I couldn't id pulled alongside the fire truck. My immediate guess was that the XOG guard would not let the fire truck on the pad and the fire truck had to call the chief on duty to get the guard to let them on the pad. By the time I turned left on Lowell and circled back around past the entrance, neither the fire truck nor pickup were at the gate. The walls would block any view if they went inside. I hope there is nothing wrong at the pad, but I would like also like someone to investigate if the fire truck was made to wait at the gate by the guard. That should not happen.	5/16	Jean Lim	5/18	From first response team: I re-reviewed the report and spoke to the officer in charge, who is off-duty today. He stated that they responded non-emergent (no lights and sirens) to the reported outside odor investigation, which is our standard protocol for calls of this nature. He did notice a faint, transient smell on the way to the call but air monitoring did not pick up any H2S or explosive hydrocarbon readings. Upon arrival at the pad site they were met by security who called his XOG supervisor in to escort the Engine on to the pad site. Our officer estimated around a 10 minute response time for the supervisor to arrive. It should be noted that it is standard protocol for NMFRD (and all fire departments that I am aware of) to await for a supervisor or other SME to escort them on the padsite in most circumstances. Since the crew noted no odor and their air monitoring detected no hazards, the officer ascertained there was no immediate danger to life or health and appropriately waited for the site supervisor to arrive. Once onsite, they again monitored the air and found nothing. They were then escorted to the second site and found no hazards at that location.		2		From Dr Helmig: Yes, this spike in H2S certainly stood out of the instrument noise. 2 ppb, though, is pretty moderate. I don't think that anybody would have smelled that at BSE. The odor threshold for very sensitive people, as far as I have read, is listed all over the place. From as low as 0.5 ppb to around 40 ppb. https://www.atsdr.cdc.gov/toxguides/toxguide-114.pdf. e had a bit of elevated methane and VOCs around the same time, respectively a little bit later, so that may indicate that the area was subjected to oil and gas emission plumes. If you look at the wind direction graph you will see that winds during that time of the spike were pretty consistently from the East, and then around 10.30 p.m. turning north. I don't think we would have picked up emissions from the Livingston pad under those wind regimes at BSE. It would help to look at a map with the locations of the complaints be marked.	(After reviewing a map of the complaint locations.) Additional answer from Dr. Helmig. Yes, this spike in H2S certainly stood out of the instrument noise. 2 ppb, though, is pretty moderate. I don't think that anybody would have smelled that at BSE. The odor threshold for very sensitive people, as far as I have read, is listed all over the place. From as low as 0.5 ppb to around 40 ppb. https://www.atsdr.cdc.gov/toxguides/toxguide-114.pdf. e had a bit of elevated methane and VOCs around the same time, respectively a little bit later, so that may indicate that the area was subjected to oil and gas emission plumes. If you look at the wind direction graph you will see that winds during that time of the spike were pretty consistently from the East, and then around 10.30 p.m. turning north. I don't think we would have picked up emissions from the Livingston pad under those wind regimes at BSE.
104			In refernce to 5/18 question reply: Is Ajax's reply on the Oil and Gas Dashboard acceptable? The reason that the United 1 sensor is running high is because it is the actual sensor that Ajax swapped out of Thunder Vista that was running high and causing safety concerns there. How does this shifting of location of the misaligned sensor provide accurate information for citizens, which was stated as Ajax's objective last Tuesday? Can they get a new sensor for United 1?	5/18	Jean Lim	5/20	The Apis sensor factory has been shut down due to COVID so no new sensors are available at this time. Moving the sensor system accomplished the objective that we set out to validate (and which was communicated through email and during the council session: It confirmed that this particular sensor simply has a higher baseline reading, as the higher baseline reading is also experienced at United 1. These results also confirm that the Thunder Vista area was not simply experiencing a higher level of VOCs in the air (which was the stated concern). We do not believe that minor discrepancies between sensor baseline values are a problem. Each sensor is providing its value regardless of whether the baseline range is 50-100 millivolts, or has a baseline range between 150-200 millivolts. Based on our findings so far, any tangible increase in VOCs such as benzene will be represented by a shift of over 200% of the baseline voltage (we continue to assess this as we get more data). The actual voltage reading is immaterial from the perspective of the system operating effectively. I believe the core issue to be resolved here is that presenting line graphs of voltage is misleading users and causing undue concern, as most people will intrinsically believe that “lower is better” and “higher is worse”. I look forward to exploring new ways to present this information so that we can help users to intuit “normal” vs. “slightly elevated” vs. “high” readings in a consistent way across the network. The trick is in presenting this data in an intuitive way without losing transparency, nor giving the impression that we are hiding anything in our treatment of the data or in the method of presentation.		2	AV
105			The Wildgrass 1 sensor has been down all weekend, starting at 7 pm on Friday (see graphs below). There was at least one Wildgrass resident who reported health symptoms this weekend. Should we be able to look at the Wildgrass sensor to gauge emissions in our neighborhood? What is Ajax's approach to addressing this? Do they assume that since they can still meet their 90% threshold per the contract that they can just leave it go until Monday or later? If so, do you think we just have to accept some sensors will be down all weekend since there is nothing in the contract to make them move to fix it any sooner? Detail graph of when Wildgrass 1 first went down; Two day graph of Wildgrass 1	5/18	Jean Lim	5/19	The Wildgrass 1 sensor has been mostly stable since it was installed on Mar 31 with 91.5% service level availability (up-time). The sensors do still experience some intermittency due to electricity supply and cellular connectivity, but this is normal. From Apis data: 1,260 null records out of 14,982 total records - 5 minute intervals		1	TY
106			I have been observing the readings from the United 1 and 2 sensors before spudding begins on the United Pad and I am concerned that the United 1 sensor and its trigger are not set correctly to notify us of any upcoming emissions problems that might occur during spudding. We do not want to wait 3 weeks for Ajax to decide to swap out a malfunctioning sensor as they did at Thunder Vista. United 1 is immediately to the west of the United Pad and United 2 is immediately to the east of the United Pad, close to Huron Street. Yet United 1 always runs much higher than United 2. https://drive.google.com/file/d/1Qt0yS5pf0n0Iyb6Zzm2NyjWXJBtvy3UK/view The high ranges on the United 1 sensor have only been noted on the daily updates as a little above normal but there have been no triggers. Why? See data listed below. Normal range is supposed to be between 80-200 mV. Also, the United 1 readings which are close to 200 have been marked within normal range. However, they are consistently much higher than any other sensor in the system. Why? The United 1 sensor was: 233 on May 12 190 on May 13 218 on May 14 196 on May 15 184 on May 16 217 on May 17 Here is the 7 day graph of United 1 compared United 2 from May 8 - May 15:	5/18	Jean Lim	5/20	United 1 is a sensor that runs a higher baseline, as this was the sensor that was previously deployed at Thunder Vista. There have been no triggers because the sensor has not reached the trigger threshold for that sensor (which is set slightly higher in alignment with the higher sensor baseline for that system).		2	TY
107			Thank you for linking the 5/16 NMFD report from the 5/17 Daily Update. I am glad to know that NMFD did investigate both pads and Public Works is looking into the source further. Did you note the hydrogen sulfide spike at Boulder Air at the same time and share it with Public Works? For future possible pad problems, we need to know if the Extraction site supervisor at first told NMFD that they were not allowed on the pad. The report makes it sound like the Extraction site supervisor was dismissive of the possibility that anything could be coming from the pad. That report, in combination with my observations that the NMFD truck sat at the gate for 15 minutes, did not clear up my concern for the future: If a NMFD truck pulls up to the Extraction gate to investigate emissions, they should not have to wait to be allowed by Extraction to proceed onto the pad. Here is the pertinent section of the report: "E66 proceeded non-emergent to Livingston Pad and met with security and site supervisor. Site supervisor states that both this pad and the Interchange pad are in the production phase and only emit steam from blow off infrequently. This does not cause a rotten egg smell and they are not currently performing any operations that he knows would emit this smell. E66 proceeded down to site..." Thanks for the clarification on how NMFD can proceed when doing an investigation at the pad.	5/17	Jean Lim	5/18	from Chief Bybee of NMFRD is as follows: I re-reviewed the report and spoke to the officer in charge, who is off-duty today. He stated that they responded non-emergent (no lights and sirens) to the reported outside odor investigation, which is our standard protocol for calls of this nature. He did notice a faint, transient smell on the way to the call but air monitoring did not pick up any H2S or explosive hydrocarbon readings. Upon arrival at the pad site they were met by security who called his XOG supervisor in to escort the Engine on to the pad site. Our officer estimated around a 10 minute response time for the supervisor to arrive. It should be noted that it is standard protocol for NMFRD (and all fire departments that I am aware of) to await for a supervisor or other SME to escort them on the padsite in most circumstances. Since the crew noted no odor and their air monitoring detected no hazards, the officer ascertained there was no immediate danger to life or health and appropriately waited for the site supervisor to arrive. Once onsite, they again monitored the air and found nothing. They were then escorted to the second site and found no hazards at that location.		1
108			3 Anthem Highland residents smelled sulphur dioxide about 8:10 pm. They also saw a H2S spike on Boulder Air and called NMFD. I drove to Soaring Eagle and walked toward the pad, getting intermittent whiffs of something. I saw the NMFD truck driving south on Lowell and started walking back north to the car at Soaring Eagle, figuring it was okay since NMFD had arrived to check. I hope there is nothing wrong at the pad, but I would like also like someone to investigate if the fire truck was made to wait at the gate by the guard.	5/16	Jean Lim	5/17	The North Metro Fire Rescue District responded to a complaint of a rotten egg smell in Anthem and filed the attached report. This information has been relayed to Broomfield's utilities division also. Public Works staff investigated and had not received any calls regarding odor. They state that with the winds out of the east and northeast, the only large source is the Northglenn wastewater treatment located e/o I-25, a little north of St Hwy 7.		1	TY
109			Per Boulder Air 3-Day graph: https://bouldair.com/broomfield.htm H2S is tracking right around zero, but often dipping below. Can you please ask Dr. Helmig for an explanation of how H2S can be below zero.	5/14	Laurie Anderson	5/18	We have been playing close attention to his as well. H2S is analyzed with at Teledyne T101 analyzer. It is about the most sensitive commercial analyzer that is available on the market. It’s stated detection limit is around 0.4 ppb. Since we started operating the analyzer, we have seen a gradual drift in the baseline. That shows best in the 30-day graph linked to right. Overall, this drift has been about 1-2 ppb. And it slowly drifted into negative numbers. There are, of course, no negative concentrations, so what this is showing here is a slight negative offset of the analyzer output that it now seems to be settling on. This will be corrected in the final data, eventually, and we will also add a correction in the data that are output onto the website. But it makes most sense to do that once this offset has stabilized. This is not really that much an unusual behavior for a new analyzer that comes out of the box. Kind of like breaking in a new car. And these values are very low, near the detection limit of the analyzer. The odor threshold for H2S is highly variable among individuals, but ranges between 8-130 ppb. And an H2S 8-hour health threshold value is 330 ppb. So, what we are measuring here is ways smaller than that. But we are working on that and actually set up the H2S external calibration system just yesterday. Once we got those correction factors figured out and applied, the data should be mostly outside of the negative range.		3	TY	Link to graph: https://drive.google.com/file/d/1TWeWg558JMSluB8S8LIQOxff9ILDj5-O/view?usp=sharing
110			1) Thunder Vista hit over 200 this afternoon and is again higher than the other sensors. Since this is a new sensor that had been running lower since it was swapped on Friday, did Ajax reset it to trigger at 200 like the others? 2) Observation: Livingston 1 was down for 20 of the last 24 hours. Livingston 2 was down for 2 hours. Prospect Ridge down for about 5 hours today.	5/13	Jean Lim	5/14	The sensor was not 'reset', it was moved to United 01 to test the hypothesis that the sensor was calibrated from the factory at a higher baseline. Given that United 01 TVOC readings have been higher since the switch, this hypothesis was proven correct so we should expect higher baseline readings at this location going forward.	Question has been posed to Ajax	1	TY
111			At the May 12, 2020, Council meeting, Councilmember Anderson noted that she had not received an answer to the following question, asked on 5/3: Looks like Livingston 1 is down again right now. It has had outages for the past three days around the noon hour which is when detected emissions tend to be the highest. It is full sun right now so it doesn't make sense... you'd think the outages would be overnight when there's no sun to recharge the batteries. Do you know why the TVOC emission tend to be higher during the day? Is it due to the sun and atmospheric conditions? Or is it because of operations like emptying the sand traps? Just trying to make sense of the data.	5/12	Laurie Anderson	5/13	Please see the answer posted on May 5, 2020.		1	Strategic Initiatives
112			follow up on the huge May 12 methane spike just brought to our attention last night in the AQM presentations. Since the scientists seemed initially stumped, I'll throw out these two unusual ideas that didn't hit me quickly last night: 1) The Davis 43-6 p & a well was leaking methane and is to the northeast of Soaring Eagle in Anthem Highlands. The further followup testing of any Davis 43-6 leakage by the COGCC has been delayed since March 30 due to COVID. 2) There was a well near the Davis well under a catch basin that was never tested because it was too difficult to reach. Could this be a methane source?	5/13	Jean Lim	5/18	Conclusion from Dr Helmig: Based on these analysis, I think it is quite unlikely that emissions from the Livingston well pad site were the origin of this methane event. For further information, a map provided by Ed Pottorff is included as he brought up the question of a possible association with two suspected emission sources that are located to the north of BSE. The full report can be viewed HERE.	Question sent to Boulder AIR	4	TY & AV
113			In response to 5/9 email about the 5/8 8:30 pm huge spike at Thunder Vista, 5/11 response on the Oil and Gas Dashboard states that Ajax swapped out the Thunder Vista sensor on Friday 5/8 and that the "observed TVOC spike to 3296 is believed to be due to a power surge when the equipment was disconnected from the electricity supply." If Ajax put in a new sensor, then why did it go down again yesterday? The Thunder Vista sensor was down for 15 hours on May 10 from 4 am - 7 pm.	5/11	Jean Lim	5/13	There are sensors that are having downtime issues due to power and are going through a troubleshooting process. Currently, three systems (ThunderVista, Livingston 01, and Prospect Ridge) are having intermittent power outage issues and we are diligently working and running tests to identify root cause and solve the problem. Returning these systems to the manufacturer and getting replacements would be the preferred method of handling these issues, and is unfortunately not an option at this time as the manufacturer has been shut down per government mandate.Our team has been in the field multiple times, including over the last three weekends in order to continue work to find a resolution. A stabilization period is expected and has been communicated with every deployment since our first sensors were deployed in 2018.		3
114			The Thunder Vista sensor was down for 6 hours from 2 pm - 8 pm yesterday, then spiked to an alarming level of 3296 TVOCs at 8:30 pm, stayed at that level for 10 minutes, and has been offline since then. Did it trigger at 8:30 pm on Fri, May 8? Will it be offline until Monday? We had already been asking many questions about why the Thunder Vista sensor near the Adams 12 elementary school and thousands of Anthem Highlands residents had been running higher than the other sensors, but yesterday's downtime and likely triggering is very concerning. Why was yesterday's daily oil and gas update at 3 pm marked with all 13 sensors functioning? Thunder Vista had already been down from 12:30 pm - 1 pm before it went down for 6 hours starting at 2 pm.	5/9	Jean Lim	5/11	Ajax staff swapped out the sensor at Thunder Vista on Friday. This was to provide information regarding whether the Thunder Vista sensor is actually running at a higher baseline (which is Ajax's expectation), or whether the Thunder Vista site may actually be experiencing more VOCs than other monitoring sites. The observed TVOC spike to 3296 is believed to be due to a power surge when the equipment was disconnected from the electricity supply. As such, this did not trigger a canister sample. No other sensors in the system were elevated above baseline at this time.		1
115			1) Did the COGCC Antea group do the Davis 43-6 well P & A methane leak testing in March and what were the results? 2) A resident called attention that the Davis 43-6 well is very close to the Thunder Vista Apis sensor which is running so high and there could have been methane pockets from Davis migrating in the nearby subsoil. What can we do to either confirm or rule out that possibility?	5/7	Jean Lim	5/7	1)Due to the COVID-19 restrictions, this work has not been performed yet by COGCC. 2) Until COGCC's contractor (Antea) is able to get out and perform additional investigation, it would be difficult to determine whether the methane pockets have migrated. In the mean time, Broomfield relayed council's concerns about the Thunder Vista Apis sensor to Ajax and CSU. CSU informed Broomfield they are not seeing elevated methane in the weekly canister samples compared to weekly samples from last year, and the methane concentration was really low in the recent triggered canister sample. CSU has indicated they keep a close watch on the Thunder Vista weekly canister data to see if anything shows up.		0.5
116			In response to 5/4 question and partial response: Thunder Vista previously triggered at 2:19 on 4/19 and it reached 242 on 5/3 and did not trigger. Why? https://drive.google.com/file/d/1Qq1sxtTbF39c1MzZ2qWa337su4UWjQ7I/view	5/5	Jean Lim	5/5	Ajax adjusts the trigger thresholds across all sensor systems after a few week’s of operation. Ajax may also continue to adjust the thresholds as CSU and Ajax learn more about the relationships between the TVOC Indicator and VOC levels as canister results come back from the lab or as we identify and test new methods and patterns of air quality event detection.		0.5
117			At the May 5 Council meeting, a resident asked about a tutorial or training for the Ajax website.	5/5	Resident	5/20	Ajax is working on a "How to Document" for the public, on its website. Interested residents are asked to submit specific questions so Ajax knows which areas to focus on. Please send questions to oilandgas@broomfield.org.		12
118			In reference to 5/3 question and response: The Livingston 1 sensor went down again on 5/4 from about 12:30 pm to 2:30 pm and down again today from 8 am - 8:30 am. Read the Ajax theories as to why the TVOCs are much higher during the day and the fact that they cannnot come to any conclusion is not reassuring. If the sensors cannot operate under daytime heating accurately, then that is a sensor malfunction and I would like that marked as needing follow-up. (also see Follow Up section on 5/3 questions)	5/5	Jean Lim	5/5	Downtime is an expected factor with any system. Generally, higher cost systems include redundancies that minimize downtime. If downtime has become a concern, it is possible to adjust our Service Level Availability agreement to ensure more constant uptime. We have had customers engage us with a 95% sensor uptime SLA calculated on a monthly basis, though that level of uptime guarantee comes at significant cost. To add some context to the naturally occurring phenomena of baseline variability: Every radio signal in use today (cell phones, wifi, Bluetooth, FM, etc.) has a natural variability to the signal, we just don’t see it. Our communication devices simply work within that natural variability in order to accomplish the goal of transmitting information. As another example, nobody worries about the exact operating temperature of your vehicle’s engine under normal conditions; one wants to be sure that the temperature sensor lets you know when the temperature is approaching levels that can be dangerous. That is the purpose of the Apis PID sensors: to constantly monitor for increases in VOC levels that could represent dangerous levels for short-term, acute exposure. When such levels, well above the normal baseline variability occur, a canister is triggered to provide reference grade documentation of the concentrations of benzene and many other VOCs in the detected plume.		0.5		The PTR-MS, for example, has a very stable baseline, relative to the Apis PID sensors. For that reason, the PTR-MS can quantify benzene concentrations at 1 min time resolution in the 0.1 ppbv range. Auto-GC systems typically have similar sensitivity at somewhat lower time resolution (e.g., 1 hr). There is no need to continuously monitor benzene concentration changes of 0.1 ppbv across Broomfield and to deploy climate-controlled shelters with expensive GCs or PTR-MS systems at numerous sites is cost prohibitive. There is, however, a need to detect elevated VOC concentrations that can occur over very short periods. The diurnal variability in the baseline response of the PID sensors does not compromise their ability to detect such events. This has been clearly demonstrated already in Broomfield.
119			In reference to 5/4 response: "The sensor at Thunder Vista runs a baseline range from 100 to 200, which is slightly higher than the normal baseline range at other sites. 242 didn’t meet the threshold that is set for that site. Each sensor has a threshold set based upon its normal baseline range." 1) What is the scientific basis for the baseline at Thunder Vista being set higher? Why would Ajax assume that there are more pollutants at Thunder Vista in the baseline? 2) Thunder Vista previously triggered at 219 on 4/19 and it reached 242 on 5/3 and did not trigger. Why? https://drive.google.com/file/d/1Qq1sxtTbF39c1MzZ2qWa337su4UWjQ7I/view 3) Are all of the monitors undergoing routine maintenance at the beginning of the month?	5/4	Jean Lim	5/6	All scientific instruments show some variability in baseline response. The amount of variability often depends on the ability to control the environmental conditions where the instrument operates. For air quality measurements of VOCs, reduced baseline noise is typically found in expensive instruments housed in climate-controlled shelters. When deploying lower cost sensors outdoors, one expects an increase in baseline variability. Whether the increased variability is acceptable, depends on the needs associated with the monitoring. In Broomfield’s AQM, a variety of complementary techniques, with varying cost and sensitivity, are deployed to provide good coverage in space and time and at varying time resolutions.		2	Strategic Initiatives	Our monitoring activity to date has shown that elevated concentrations of hazardous air pollutants are not occurring during small changes in the normal baseline variability of the sensors, rather, significant hazardous pollution events are occurring when the sensor systems measure spikes or elevated levels many times higher than the baseline range. The normal and expected daily variability in the TVOC sensor systems does not impact the value of the systems in recording the large changes that indicate a significant event.
120			In reference to 5/1 question: "Clarifying question regardng Be in the Loop trigger report- missing the Trigger event at Thunder Vista on 4/14/20." 5/4 reply is: "There was no trigger on the 14th, it was the trigger report from the 19th incorrectly identified as the 14th." The attached trigger canister notifications seem to identify two different events. Please explain what I am missing.	5/4	Jean Lim	5/5	There was no trigger event for 4/14. It was the wrong date & wrong data. From Ajax sent on Sunday April 26th @ 8PM: I discovered a few issues with these summary reports as I'm reviewing them to send them in. We are fixing them up and sending new reports shortly. It could be the CSV, I could have copy and pasted the wrong row when combining the files into one. Staff will make sure QC before posting anything.		1	Strategic Initiatives
121			Requested update on emailed question on 4/27: Will there be any follow-up on the April 17 trigger canister analysis? It says that the short benzene spike was caused by oil and gas activity and there were 4 wells in flowback. Any speculation what would cause that?	5/4	Jean Lim	5/4	All detail has been given on this event, HGVs were within thresholds.		0.5	Strategic Initiatives
122			Why can't we access the old canister reports?	5/4	Jean Lim	5/4	Trigger Matrix Trackling link has been added to the dashboard.		0.5	Communications
123			Why did the trigger canister not go off at Thunder Vista on May 3 when it was 242 mV? Was it reset higher by Ajax without providing any explanation of why it always runs higher?	5/4	Jean Lim	5/4	The sensor at Thunder Vista runs a baseline range from 100 to 200, which is slightly higher than the normal baseline range at other sites. 242 didn’t meet the threshold that is set for that site. Each sensor has a threshold set based upon its normal baseline range.		0.5	Strategic Initiatives
124			Will Item 11a AQM Program Update have public comment and if so, when will it be? Did you plan to have Ajax/CSU and Dr. Helmig available to answer questions on the call or not?	5/2	Jean Lim	5/3	Yes, there will be public comment on this item. Consultants will not be participating on Tuesday, but will be participating on 5/12.		1	Strategic Initiatives
125			Looks like Livingston 1 is down again right now. It has had outages for the past three days around the noon hour which is when detected emissions tend to be the highest. It is full sun right now so it doesn't make sense... you'd think the outages would be overnight when there's no sun to recharge the batteries.	5/3	Laurie Anderson	5/4	The LIvingston 1 sensor did come back on line after this comment. Ajax is aware and working to identify the root cause of these downtime intervals on some sensors. They don’t yet know exactly why the sensors are showing a daily baseline variability, they have a few working theories that more data and more time will help them narrow down on probable cause. This daily variance could have a combination of causes, and we may never nail down exactly why we see it. Working Theories for Daily Variance (in no particular order and with none more probable than another) There could be an actual increase in the suite of VOCs seen by the sensor. Possibly an increase in VOCs emitted by increased human activity (traffic, industry, and other sources) during the day and/or VOC’s coming off of plants that are more active during the day. Higher temperatures during the day may be influencing the sensor millivolt reading. Temperature is a known influencer of most small sensors and outdoor electronics. In fact, most of Apis’ engineering is focused on managing the temperature of the sensors and the computing equipment inside the machine. It is possible that there is another influencer that we haven’t identified that is active during the day. As long as the normal baseline remains within a consistent and predictable range for each sensor, Ajax remain capable of differentiating the bigger spikes that correspond to impacts by plumes from strong local emission sources. Ajax also recognize that sensors need to remain online, which they are troubleshooting and improving as issues with some sensors pop up. Ajax indicates that with any new system or network deployment, there is a period of issue resolution to be expected.		1	Strategic Initiatives	All scientific instruments show some variability in baseline response. The amount of variability often depends on the ability to control the environmental conditions where the instrument operates. For air quality measurements of VOCs, reduced baseline noise is typically found in expensive instruments housed in climate-controlled shelters. When deploying lower cost sensors outdoors, one expects an increase in baseline variability. Whether the increased variability is acceptable, depends on the needs associated with the monitoring. In Broomfield’s AQM, a variety of complementary techniques, with varying cost and sensitivity, are deployed to provide good coverage in space and time and at varying time resolutions.	Ajax stated at the 5/12 Council meeting that the manufacturing plant in Ohio, has been shut down due to COVID. This is causing Ajax to trouble-shoot sensor systems, rather than returning and replacing equipment. They have determined a possible firmware issue with the sensors, which may be causing some of the downtime. They are working with the manufacturer's firmware team (who are working from home) and hope to be able to clear up some of the issues.
126			Do you know why the TVOC emission tend to be higher during the day? Is it due to the sun and atmospheric conditions? Or is it because of operations like emptying the sand traps?	5/3	Laurie Anderson	5/6	Dr. Collett of CSU would encourage people not to focus too intensely on the typical daily variability in sensor baselines in the 50-200 mV range. These appear to be within a range of normal baseline variability and do not necessarily mean that local emissions are changing. We don’t see this regular afternoon peak in BTEX levels monitored by the PTR-MS at Soaring Eagle. It may be important to remember that we are mainly looking with the Apis sensors for bigger spikes that correspond to impacts by plumes from strong local emission sources, as shown in this longer sensor timeline.	Request for further follow up	3	Strategic Initiatives	Our monitoring activity to date has shown that elevated concentrations of hazardous air pollutants are not occurring during small changes in the normal baseline variability of the sensors, rather, significant hazardous pollution events are occurring when the sensor systems measure spikes or elevated levels many times higher than the baseline range. The normal and expected daily variability in the TVOC sensor systems does not impact the value of the systems in recording the large changes that indicate a significant event.	The PTR-MS, for example, has a very stable baseline, relative to the Apis PID sensors. For that reason, the PTR-MS can quantify benzene concentrations at 1 min time resolution in the 0.1 ppbv range. Auto-GC systems typically have similar sensitivity at somewhat lower time resolution (e.g., 1 hr). There is no need to continuously monitor benzene concentration changes of 0.1 ppbv across Broomfield and to deploy climate-controlled shelters with expensive GCs or PTR-MS systems at numerous sites is cost prohibitive. There is, however, a need to detect elevated VOC concentrations that can occur over very short periods. The diurnal variability in the baseline response of the PID sensors does not compromise their ability to detect such events. This has been clearly demonstrated already in Broomfield.
127			Would it be possible to mark on the Oil and Gas Dashboard when we know the trigger sensors are offline?	5/1	Jean Lim	5/4	This isn't technically feasbile, it would require 24/7 monitoring of the Apis network and updating the dashboard on a minute-by-minute basis. The best way to see the sensor status is to check the Apis site at the link to the right.		1	Strategic Initiatives	https://charts.apis-aq.com/broomfieldajax/d/NO95kw2Wk/city-of-broomfield-ajax-air-monitoring-metrics?orgId=1&var-site_id=CCOB_WILDGRASS_01_IMPACT&var-site_id=CCOB_WILDGRASS_02_IMPACT&var-site_id=CCOB_LIVINGSTON_01_OG&var-site_id=CCOB_LIVINGSTON_02_OG&var-site_id=CCOB_LIVINGSTON_03_OG&var-site_id=CCOB_INTERCHANGE_01_OG&var-site_id=CCOB_INTERCHANGE_02_OG&var-site_id=CCOB_ANTHEM_01_IMPACT&var-site_id=CCOB_ANTHEM_02_IMPACT&var-site_id=CCOB_THUNDERVISTA_01_IMPACT&var-site_id=CCOB_PROSPECTRIDGE_01_IMPACT&var-site_id=CCOB_SOARING_EAGLE_01_IMPACT&var-site_id=CCOB_UNITED_01_OG&var-site_id=CCOB_UNITED_02_OG&var-site_id=Livingston_Eval&var-time_avg=5m&var-metric=TVOC&var-windroseSite=CCOB_WILDGRASS_01_IMPACT&var-windroseMetric=NO&var-uid=PQhb9oKWk
128			Clarifying question regardng B in the Loop trigger report- missing the Trigger event at Thunder Vista on 4/14/20.	5/1	Jean Lim	5/4	There was no trigger on the 14th, it was the trigger report from the 19th incorrectly identified as the 14th. See further follow up in the Follow Up 1 section.		1	Strategic Initiatives	5/5 - There was no trigger event for 4/14. It was the wrong date & wrong data. From Ajax sent on Sunday April 26th @ 8PM: I discovered a few issues with these summary reports as I'm reviewing them to send them in. We are fixing them up and sending new reports shortly. It could be the CSV, I could have copy and pasted the wrong row when combining the files into one. Staff will make sure QC before posting anything.
129			Can we get an update from Ajax on why the sensor systems appear to have gone offline over the past 24 hours?	5/1	Jean Lim	5/1	Reply from Ajax: Issues in the few weeks of a system deployment are expected. We did our best early during the program to set this expectation, though I completely understand this message isn’t helpful when you see downtime during a concerning time like this. We are aware of these down-time gaps and are working diligently on identifying and resolving the root cause. We have been monitoring and troubleshooting the short-term (2-3 minute) data gaps, as well as longer-running (multi-hour) downtime issues with certain systems. Early on, we suspected cell signals for short gaps and had clearly defined issues with wiring connections to explain the longer downtimes. Our current working theory is that there is an issue in the solar power chain – likely in some of the solar power controllers (which manage the power stream from solar to battery). Theoretically, we should have 4-5 days’ of uptime even without a solar panel. To test the root cause, we have been replacing the solar power controllers in systems that are going down. If this modification doesn’t solve the problem, then we will adjust our working theory and explore other components in the power system. Apis engineers are helping us with this troubleshooting process. (see update) We are avoiding pulling any systems from the field, which limits our ability to dig in and setup various test scenarios on the different components.		0.5	Strategic Initiatives	Ajax update 5/1: that the power interruption at ThunderVista was due to an unplugged cable that appeared to be pulled on and it was missed last night because it was too dark to see. Also, the Livingston 01 station is reporting data and had a communication issue with the cell towers.
130			APRIL 2020 below
131			Trigger Notification https://drive.google.com/file/d/15PL2Tmy4thaBpmZ1C2U-8gJ-uouXgcsr/view	4/30		4/30	FYI - will follow up with report once received	Report	0.5	Strategic Initiatives
132			On the Daily Update, why is Anthem Ranch marked with the highest TVOC reading when it looks like Thunder Vista would have been higher?	4/20	Jean Lim	4/30	Today I reported the higher of the readings in the neighborhoods, as Wildgrass 02 and Anthem 02 had higher max values than the 01 stations. This was to give an upper limit snapshot to the report. While the high TVOC values may still be in normal range, you can see a general rise in those values as more wells come online to where it is approaching out of normal range. Why are today's high values noted for Wildgrass 02 and Anthem 02 instead of Wildgrass 01 and Anthem 01 as have previously been reported?		9	Strategic Initiatives	On 4/20 the question was asked by Councilmember Lim: While the high TVOC values may still be in normal range, you can see a general rise in those values as more wells come online to where it is approaching out of normal range. Why are today's high values noted for Wildgrass 02 and Anthem 02 instead of Wildgrass 01 and Anthem 01 as have previously been reported?
133			Please provide additional information on whether the night staff will be trained to change the trigger canisters.	4/27	Jean Lim	4/28	After review of the process, and detailed chain of custody requirements, staff determined it was best to continue with Ajax changing the trigger canisters. The night staff has been trained on grab canisters, and can respond to odor complaints when they are on duty in the neighborhood. In addition, we have just developed a process under which the night guards are receiving email notices at night of any trigger canister events, and follow-up by documenting anything they see visually from the pad, the wind direction, and take a canister sample at the nearest neighborhood site downwind.		1	Strategic Initiatives
134			Can we ask Ajax why the Wildgrass 1 sensor has been intermittently going out over the last 12 hours? At least the graph makes it appear that way, and none of the other main sensors look like that.	4/26	Jean Lim	4/26	The answer from Ajax is that all systems experience this occasionally. We believe that this happens when the system does not get a stable connection to cellular service and is not able to submit the measurements. Other times, it can be an indication of a flagging solar/battery system. Ajax will check the battery levels and look at the solar panel this week to rule that out. This behavior is one reason that Ajax cannot commit to 100% uptime on these sensors - some factors, like cell service stability and solar power, are outside of our control. Mitigating these challenges is possible, though building in redundancy would make the solution incredibly expensive. (Ajax calculates uptime for Service Level Availability as part of each Quarterly Report. This SLA number is a percentage calculated as the number of recorded measurements divided by the number of expected measurements (per the SLA defined in the agreement). Ajax could certainly provide more real-time reports on uptime, though it is currently outside the scope of the service. In the meantime, we’ll add a feature request to our software backlog for real-time visibility into uptime SLA metrics.)		0.5	Strategic Initiatives	The Apis systems have had 86.8% system uptime from deployment of each site through the end of Q1. Typically, the lowest uptime on a sensor is in the first months after deployment, so we expect this number to climb quickly as systems stabilize.
135			Can the FLIR camera be used to check on emissions coming from the sand cans when they are emptied?	4/21	Jean Lim	4/22	The Infrared (IR) camera can be and has been used to detect emission leaks from the fittings and valving of the sand cans at the wellhead and to see if there are any leaks directly from the wellhead. Leak detection is how we primarily use the IR camera here in Broomfield. When the sand cans get full they are emptied into the sand tank on location, and then the sand in the tank is emptied as necessary with a hydrovac truck which hauls the sand off site for proper disposal. At the Interchange B Pad we have used the IR camera to look at the sand tank when the cans were being emptied and did observe some minor and brief emissions from the tank. There are a couple of challenges that we are faced with when using the IR camera in this manner: 1) the camera can also see water vapor which can be confused with gas emissions, and 2) the camera does not identify what specific gas is being emitted and it does not quantify the concentration or volume of gas. Broomfield's air quality monitoring system is a much more robust tool for evaluating air emissions from the Livingston Pad.		1	Strategic Initiatives
136			Is there a way to tell if the CO2 is attributed to the oil and gas activity, like they can with Benzene (chemical signature)? At what levels does the city start to worry about these levels and how they can impact citizen health?	4/21	Resident Question from Council	4/21	Link to email response		0.5	Strategic Initiatives
137			Why was the potential for the greater impact of vegetation on the TVOC reading than that that of well site VOCs not brought up in the Council discussions when we were discussing the APIS sensors?	4/21	Laurie Anderson	4/21	Link to email response		0.5	Strategic Initiatives
138			We were able to focus all of the AQM monitoring equipment near Livingston because other sites were not in development. When will there be additional Ajax sensors available to place around the United Pad soon? Any other AQM adjustments?	4/17	Jean Lim	4/23	Link to email response		5	Strategic Initiatives	Ajax will be installing two systems at the United 01 and 02 monitoring sites. The poles are already in place at the preexisting sites and I will be attaching an Apis system, solar panel, and battery. A map of these locations is linked in the next cell.	Link to follow up
139			The CSU plume tracker did visit in the last 24 hours as it was seen in Wildgrass and Silverleaf. Will those readings be shared with Council or are they just being kept by CSU? If I missed a link, I apologize.	4/16	Jean Lim	4/16	Of course, all data will be shared with Council and the public. Dr. Benedict does indicate it was really windy and they didn’t really see any changes in methane. She believes that the cans she took will come back pretty clean based on how windy it was and based on what the PID sensors were showing yesterday to today. (First batch of plumetrack results are expected the week of 5/4)		0.5	Strategic Initiatives
140			What amount of hydrocarbon fluid is getting released in the purging process? Would that explain the spike in emissions this morning from about 7 am to 8:30 am at Ajax's Livingston 1 sensor? Did Ajax's Livingston 1 sensor trigger around 8:30 am?	4/14	Jean Lim	4/14	Livingston did not trigger this morning, as TVOC did not reach a triggering threshold. NO and NO2 sensors will have a wider band of “normal signal” - especially at low ambient concentrations. The change over time that Jean points out could be sensor noise, as the sensor is not indicating exceptionally high concentrations.		0.5	Strategic Initiatives
141			What measures are in place to protect our residents from VOCs and fugitive emissions?	4/7	Guyleen Castriotta	4/7	Link to email response		0.5	Strategic Initiatives
142			Has the Livingston 2 sensor been relocated so that it can be changed without going into the Extraction facility?	4/7	Jean Lim	4/7	The Livingston 2 system is currently in a good location for monitoring air quality and will likely not be relocated, for now. While access is a little more challenging without being able to enter the location of Extraction former well facility, there is still available access to the Livingston 2 sysem.		0.5	Strategic Initiatives
143			Have our CCOB paid night guards been trained to replace the trigger canisters when they go off?	4/7	Jean Lim	4/7	Ajax is testing an online documentation process now and will be creating a video training to guide helpers through changing canisters.	see 4/27 question	0.5	Strategic Initiatives	See updated response on 4/27
144			Is Ajax/CSU ready to meet the demands of increased canister analysis given reduced workforces and social distancing everywhere?	4/7	Jean Lim	4/7	Ajax has local resources in place within Broomfield to help with changing canisters on a timely basis. CSU’s lab has been granted an exception to CSU’s campus closure in order to keep processing canister samples. While we have put remote work and employee distancing policies in place, most of our work is outside and independent. We do not anticipate any interruptions to our ability to execute, barring any major changes to government guidelines.		0.5	Strategic Initiatives
145			Beyond the 3 Apis sensors Laurie questioned, are the next 4 trigger canisters still on track to be installed on 4/11?	4/7	Jean Lim	4/7	Yes, we are still on track to deploy 4 more sensor systems around Livingston and in the nearby communities on 4/11. (all deployed as scheduled)		0.5	Strategic Initiatives
146			When will staff release the trigger canister plan discussed on 4/3?	4/7	Jean Lim	4/7	Link to email response		0.5	Strategic Initiatives
147			Is the CAMML in place northwest of Livingston and collecting continuous real-time data already?	4/6	Laurie Anderson	4/7	Yes the CAMML is in place.		1	Strategic Initiatives
148			Is Ajax/CSU ready to go? Is the Wildgrass Apis Sensor with triggered canister ready? (In addition to the Livingston 2 and Anthem Ranch sensors.) Is the Plume Tracker on standby with a plan to capture the initial few days of flowback? *Is the CSU Stationary Proton Transfer Reaction Mass Spectrometer up and running at the Soaring Eagle Trailer?	4/6	Laurie Anderson	4/7	The Wildgrass site is online, submitting data, and is trigger ready (as are Livingston 2 and Anthem Ranch 1). The plume tracker is operational and has special clearance from CSU to continue operating during the campus closure. The plume tracker schedule is not fixed, though will be deployed during flowback operations. *The PTRMS is installed and going through final setup and testing now.		1	Strategic Initiatives
149			What is the status of the Boulder Air equipment? My understanding is the satellite Trailer collocated with the CAMML is still weeks away from being ready. My understanding is that the critical VOC measuring equipment may not be ready by April 10, but other components are (or will be) in place by then such as ozone. We also need to ensure that they understand that even if Extraction is moving forward ahead of schedule and we are not 100% ready for the exact start, we need to continue to press forward and get up and running as fast as possible.	4/6	Laurie Anderson	4/7	The Soaring Eagle trailer is currently monitoring ozone, methane, carbon dioxide, hydrogen sulfide, nitrogen oxides and meterological data. The GC/MS installation has been finished, but the VOCs system still needs the prefocusing/inlet component. Boulder AIR is currently waiting for delayed parts that should arrive sometimes this week. The trailer and electrical are in place. Dr. Helmig satellite trailer will be the priority after the trailer at Soaring Eagle is fully set up. Currently it is expected that setup of the trailer and met system will begin later this week. It will probably be another week after VOCs at Soaring Eagle are up. This is understood by AJAX/CSU and Boulder AIR and Broomfield will continue to push on this.		1	Strategic Initiatives
150			Do we have answers to the technical questions regarding shutting down operations if we detect concerning levels of air toxins, or if our health department determines that health is being impacted? Specifically, if flowback begins and then wells need to be shut in to protect public health, would the situation be equivalent to having paused flowback, more dangerous, or less dangerous?	4/6	Laurie Anderson	4/7	Following is the response from Mike Leonard at COGCC: Safety is a concern if flowback were to be delayed if there were a failure of one of the valves or the wellhead equipment. There is concern about damage to the wellbore itself if flowback does not occur in reasonable amount of time. Stopping flowback in the process would raise the same issues. To my knowledge no company has delayed flowback.		1	Strategic Initiatives
151			Do we know what type of air quality monitoring was done during the beginning of flowback at the other sites using the Next Generation flowback equipment, if any?	4/2	Laurie Anderson	4/3	Staff checked with CSU, COGCC and CDPHE. The only site mentioned that anyone knew had air monitoring that may be public is Raindance. CDPHE has deployed a PID near Raindance site, though that report is not finalized and CDPHE said that the results were pretty inconclusive (even for a PID monitoring). There will be a public report from CPDHE on this, which we will track, but they are not releasing data at this point.		1	Strategic Initiatives
152			MARCH 2020 - Below
153			Can we obtain the manufacturer's documentation of emission destructure rate for the ECD?	3/31	Council Meeting	4/2	In response to your latest set of comments below, Broomfield will be enforcing the 98% hydrocarbon destruction efficiency provided in Exhibit B, Section 25 of the Operator Agreement. Also, we will be enforcing the requirement in the Comprehensive Drilling Plan that Extraction provide certification and documentation that onsite equipment is continuously operated within its design parameters. We would reiterate that the Extraction facility is fully automated. If the pilot goes out on the ECD, flow will be shut off, as in the gas flow will stop. With the automation, the facility will shut down and the wells will shut in as the appropriate shutdown parameters are met.		3	Strategic Initiatives
154			What is the VOC destruction efficiency GUARANTEE for the ECD from the manufacturer? Please provide a copy, including ALL operating conditions AND assumptions. a. What is the operating temperature of the ECD needed to achieve the 99.9% destruction efficiency claimed by Extraction? b. Did the manufacturer of the ECD provide operating conditions under which the 99.9% efficiency can be achieved? i. If so, please provide a copy. ii. Will Extraction operate the ECD according to the manufacture’s specifications? iii. If these specifications cannot be achieved on a CONTINUOUS basis, will the flow-back operations be shut down? iv. What records will be kept to demonstrate that the specifications are being met? 1. How long will the records be kept? 2. Will these records be available to Broomfield for review? 3. Will Broomfield be notified if the ECD is not operated according to specifications 4. How soon will Brookfield be notified? c. Will the ECD be brought up to FULL operating temperature BEFORE flow-back gases are introduced into the incinerator? d. Will Extraction operate the ECD on a continuous basis during the flow-back process? i. Or, will the ECD only be started up when back flow starts to the ECD, which would result in the lower destruction efficiency?	3/25	Darrell/Laurie	3/30	Read email response here		4	Strategic Initiatives
155			As of 3/26, the trigger canisters have gone off after business hours and overnight for the past 2 evenings. Do the inspectors have any insights what Extraction is doing at night that they aren't doing during the day?	3/26	Jean Lim	3/26	With regard to your questions on the trigger canisters, those will be best answered when we have CSU's analysis. (report received 4/1/20) The sensors that trigger the canisters can be influenced by a variety of different volatile organic compounds and probably by weather conditions. When our inspectors and consultants were on Livingston Tuesday night at around 7:30 pm, there was a slight breeze from the east-northeast from the direction of the Livingston 02 monitoring station toward the Livingston Pad. There was a canister trigger at the Livingston 02 station that same night at about 8:40 pm. Upon reviewing the trigger information that Ajax sent us, the wind rose showed that the wind (slight breeze) had shifted from west to east from which is the opposite direction from when they were on site a little more than an hour earlier. Until we receive the canister sample result, it is possible to surmise that exhaust from the coiled tubing unit caused the canister trigger because the coiled unit was working on one of the wells that is very close to the Livingston 02 monitoring station and there is no sound wall along this part of the pad because it is the entrance and exit to the pad, so there is nothing to block the path of the exhaust from the coiled unit to the monitoring station. This is as much detail as we can provide, at this time, regarding this incident.		0.5	Strategic Initiatives
156			Can we get more information on when the residents will be notified of the trigger canister information?	3/23	Jean Lim	3/24	link to email response		1		A mailer went out in early April to approx. 2,500 Anthem and Wildgrass residents	https://drive.google.com/file/d/1MQAfivu_Oznyc71sbJr1CVh2ZwlSUju9/view?usp=sharing
157			There is still concern that residents will not be told fast enough if there is a spike or release of some kind. Now that people are home all day and weather is changing, there is a good chance parents and children will be outside. Some people will want to bring kids and/or animals in right away, is there a way to facilitate this?	3/23	Lizzie Lario	3/23	Sensors are not intended as the primary emergency response indicator and it does take CSU 5 to 10 days to process trigger canister results. If there is a problem at the well pad Extraction has a duty to report. Our inspectors are going on site at least two time daily to inspect operations and report any concerns. COGCC also has indicated their intention to inspect routinely during flowback operations. Citizen who observe smoke or other issues of concern that they believe are health threatening are encouraged to call 911. The only sensor that has triggered during testing has been the one closest to the Livingston Pad and we have not seen any associated triggers in the neigborhood. Of course we use the trigger information to take appropriate action to determine the source of any heightened emissions and take appropriate steps.		0.5	Strategic Initiatives
158			Are we certain all APIS monitors will be installed, and tested and working, prior to flowback (vs just installed but not online/fully functional)?	3/23	Lizzie Lario	3/23	The latest information I have is that we will have 3 additional sensors delivered to Ajax by Friday this week. Assuming that interstate shipping runs smoothly and the systems pass bench testing over the weekend, we anticipate deploying the three new systems on Tuesday next week (3/31). The systems are fully tested and calibrated prior to shipping, are bench tested upon arrival, and will be fully functional on deployment day. The Interchange 1 system will be moved to the Wildgrass site this week. The priority for upcoming system deployments will be: Wildgrass 1 (moving from Interchange) Livingston 1 (new) Thunder Vista (new) Prospect Ridge (new) We are making our best efforts to have sensors installed and functioning as soon as those become available. Our goal is to have sensors with trigger canisters in place and functioning at those stations surrounding the LIivingston Pad prior to flowback. (systems were installed before flowback bagan)		0.5	Strategic Initiatives
159			So did the trigger canister trigger too soon and later missed the TVOC spike which was almost 20 times greater. We don't have the canister sample that we really needed. What does Ajax have to say about that? Did the inspectors have any insights after being on the pad today?	3/18	jean Lim	3/18	Link to email response		0.5	Strategic Initiatives
160			Livingston 2 triggered at 8 pm but then had higher readings at 10 pm and 1 am, but AJAX could not get a canister grab because it had already been triggered?	3/18	Jean Lim	3/19	We believe this is the case. We are working with Ajax and APIS to determine the best course of action moving forward for the trigger canister process. Once more canisters are in place, staff will go over options to swap the canisters with the consultant and will discuss the procedure with Council.		1	Strategic Initiatives
161			Please ask Ajax and/or CSU what their impacts are with the virus and how their ability to work with us will be impacted?	3/18	Jean Lim	3/18	link to email response		1	Strategic Initiatives
162			Please follow up with Ajax/CSU to get readings this evening as smoke was reported.	3/17	Jean Lim	3/18	link to email response		1	Strategic Initiatives
163			Can we get updates on the status of the Boulder AIR Station program?	3/17	Laurie Anderson	3/18	link to email response	update if changes to locations are made	1	Strategic Initiatives
164			How quickly will we be notified about an emission spike from the trigger canisters?	3/17	Jean Lim	3/17	We will have a procedure in place once all trigger canisters are in place, and will inform Council of the procedure. We will continue to rely on the Emergency Procedures currently in place for emergent events. The new monitoring trailers may be able to provide near real time data, however, the triggered canisters require several days to complete the laboratory analysis.		0.5	Strategic Initiatives
165			When will all the Livingston area APIS monitors be installed?	3/17	Jean Lim and Laurie Anderson	3/17	We anticipate all the APIS monitors around the Livingston pad, and in Wildgrass to be installed in the next two weeks, prior to flowback starting.		0.5	Strategic Initiatives
166			Can we provide guidance on an air purifier or filter for residential use during flowback?	3/17	Jean Lim	3/17	Staff is unable to endorse any name brands, but here is an email from the CDPHE regarding the type system or filter they recommend.		0.5
167			Residents reported seeing faint black smoke coming off the Livingston pad late afternoon and evening on 3/13. NMFD responded and found that it was diesel engine. Tami is following up for additional information.	3/14	Jean Lim	3/14	Tami reported that NMFRD Engine 66 responded that there is no smoke visible from the street so E66 proceeded to the well site. There was some black exhaust coming for a water pump, but no smoke was found. E66 contacted the site manager to confirm everything was operating as normal. The site manager said the water pump will emit black exhaust when it shifts gears. No problems reported with the pump and everything on the site is operating as expected. Staff also contacted Ajax to get a report on the readings from 3/13 as well. Ajax reported no noticeable readings. A link to their email response is linked here.		0.5	Strategic Initiatives
168			Do we know the results of the benzene level testing near our schools in North Broomfield?	3/11	Guyleen Castriotta	3/11	Requested information from Ajax/CSU on 3/11. Here is a link to their response.		0.5	Strategic Initiatives
169			What is Detlev's progress on having his monitors ready?	3/4	Jean Lim	3/5	The contract deadline is March 31, 2020. Detlev plans to meet that deadline.		1	Strategic Initiatives
170			When will all of the APIS Sensors be installed?	3/4	Jean Lim	3/5	Equipment is still not shipping from China. Ajax is looking for different vendors. As of 3/11/20, the estimate is 3-4 weeks. (all systems were installed before flowback began)		1	Strategic Initiatives
171			Will there ever be real time air monitoring so that if there is a spike residents can get a code red and leave?	3/4		3/5	We will continue to rely on the Emergency Procedures currently in place for CodeRed events. The new monitoring trailers may be able to provide near real time data, however, the triggered canisters require several days to completed the laboratory analysis.		1	Strategic Initiatives
172			Do we have to proactively run the mass spectrometer on canisters to look for other surprising compounds?	3/4	Jean Lim	3/11	Link to answer		3	Strategic Initiatives	CSU 2/25: Let us take a look at a couple samples over the next week and get back to you with an idea of how useful this might be in terms of turning up additional compounds, keeping in mind that these may also be in ambient air from sources other than O&G. Click here to view the full answer.")
173			Do we have the final results from CSU on the tetrachloroethylene?	3/4	Jean Lim	3/11	Link to answer		6	Strategic Initiatives
174			Ongoing Review of Air Canister Sampling Procedures.	3/4	Jean Lim	n/a	Due to the delay in equipment delivery, the training has been delayed until the sensors are installed. Once training has been completed, a procedure will be finalized and shared. (see 4/27)		20	Strategic Initiatives
175			Wildgrass reported very strong odor in the afternoon. Ms. Lario would like to know if this is related to recent air quality issues and if there is any information she can pass along.	2/26	Elizabeth Lario	2/28	No additional odor complaints were received and no concerns were noted from the air quality system.		2	Strategic Initiatives
176			Are the 17 banned fracking fluid chemicals (OA) included in the 900 Apis trigger chemicals and the 40 which are in canister testing?	2/25	Jean Lim	2/26	Link to answer		1	Strategic Initiatives
177			Would it be possible (cost and time) for Ajax to analyze at least two canisters for all chemicals with a full mass spectrometer test? At least we would have an idea about whether some key chemicals are being missed, and they could be factored into future analyses. If 900 isn't reasonable to test for, certainly more than 45 should be analyzed. Maybe anything that is carcinogenic?	2/25	Jean Lim	2/26	Link to answer		1	Strategic Initiatives
178			Trigger Canister draft procedure for alerting who, when	2/24	neighborhood meeting	2/25	Staff is working on a procedure for the trigger events. Once Ajax has all the monitors in place, the procedures will be finalized and released. Process reviewed with residents and Council on 4/27. Staff is working on new webpage to include trigger information.	webpage update week of 4/27	1	Strategic Initiatives
179			It appears the Apis PID was not up and running on Feb 1, 2020 so I am wondering how the canister was triggered to get the data presented on Feb 18. Are canisters being triggered today that we have to wait to see in the next quarterly report? Time is critical (dose times duration). At what concentration does the trigger occur? Is it 400ppb? Is this too high?	2/23	Kathy Swan Bogard	2/25	link to answer		2	Strategic Initiatives
180			I am hoping to get methane reading levels from Davis to updated in this format, through February.	2/22	Cristen Logan	2/22	link to answer		0.5	Strategic Initiatives
181			Can anyone provide the methane levels recorded in the soil samples collected from July - February? Also, we have never seen the final list of all of the soil testing across Broomfield and on Extraction property. Can these please be posted publicly? I imagine every well that could be tested in Broomfield has been tested at this point? AJAX indicated that the emissions recorded were less than a traditional flowback operation. Is it possible to have them plot on a graph what the emissions looks like from the closed loop system compared to what they look like from a traditional flowback operation?	2/20	Cristen Logan	2/21	link to answer	Once results are return regarding CSU plotting flowback emissions and soil sample results - send to CL once received	1	Strategic Initiatives
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1	Status	Complete?	question	date rec'd Newest to Oldest	submitted by	date of response	answer Staff: If you link to an answer, please confirm the sharing settings are "anyone with the link can view"	outstanding issues/timeline for answer	#	who is responsible	Follow up 1	Follow up 2	Follow up 3	Follow up 4	Follow up 5

2			Staff could investigate what the submission of this means for Broomfield, as far as timetable for the application and Extraction's operations schedule moving forward. The resubmitted application lists an intended drilling schedule of 2Q 2020 (# 6), obviously leftover from the original application. Can we find out from the COGCC if Extraction should be required to update the drilling schedule in resubmitting the application? On a further note, under COGCC rules operators are allowed to move forward with drilling and completions operations before having secured all the mineral interests, but the operator risks a lawsuit by mineral owners if the products are actually taken before securing the mineral rights.	4/5	Jean Lim		Staff has reached out to COGCC.
3			Information has been circulating in the community regarding a Form 42 that was filed by Crestone Peak Resources for a notice of well liquids unloading with a start date of 01/28/2021 and not estimated to last longer than one day per the form below. It is unclear if the well liquids unloading would occur on 01/28/2021, or if that is the earliest date it could occur. This is for the Waste Connections Site near Vista Ridge and Vista Pointe in Erie, which is just over a mile from residents of Anthem. Is this notice of well liquids unloading considered routine maintenance? Or could this be a result of some ongoing issues? And is it possible that some of the spikes in emissions we have picked up at BSE could potentially be from this site, if it was not operating as it should? During the well liquids unloading, what type of emissions are anticipated? I am hoping Dan has some experience with this operation, and look forward to any concerns we should be aware of.	1/26	Laurie A.		Q: It is unclear if the well liquids unloading would occur on 01/28/2021, or if that is the earliest date it could occur. A: Typically there is some lattitude on the exact date - Usually any time after the listed date within reason. Q: Is this notice of well liquids unloading considered routine maintenance? A: Gas well liquid unloading is a well maintenance production procedure, implemented periodically, where liquids that have accumulated in a gas well are removed to surface equipment. The liquids accumulation can include oil, condensate, and water, and may be due to a variety of causes, including decreases in gas velocity in the well, decreases in reservoir pressure, or changing gas to liquid ratios. As liquids accumulate, well production can decline and an operator may choose to unload the liquids from the well to restore gas production. Q: Or could this be a result of some ongoing issues? A: This is a common procedure related to the individual accumulations of liquid inherent in a natural geologic system where each well and formation has variability and produces differently. Q: And is it possible that some of the spikes in emissions we have picked up at BSE could potentially be from this site, if it was not operating as it should? A: In the most recent national inventory of greenhouse gas emissions (for calendar year 2012, released in 2014, referred to as the EPA 2012 GHG NEI), the EPA estimates that 60,810 natural gas wells, out of an estimated 470,913 natural gas wells in the United States (not including oil wells with associated gas production), had liquid unloadings that result in methane emissions. The temporal patterns of emissions can vary among wells. Some wells release unloading emissions several times per day while others may release unloading emissions only once per year or once during the well’s decades long production life cycle. Wells may only release unloading emissions for a portion of their production lifetime, leading to some dependence of unloading emissions on well age. At this time we do not have specific information of the pattern of uploading at BSE to drawn a definitive conclusion. Q: During the well liquids unloading, what type of emissions are anticipated? A: Typically methane along with other light hydrocarbons can be emmitted due to uploading.
4			Dr. Collett's statement points to the lack of access to Extraction's log as the problem which prohibits them from moving forward. The statement in the minutes is: "In these cases, we have a clear oil and gas signature, but wind data isn’t definitive as to source. Therefore we have to accept that these plumes could have originated elsewhere, though that seems unlikely. Due to a lack of information regarding the exact operational activities at these sites at precisely the moment the trigger canisters were activated, it is difficult to determine whether there is an operational link here. Both Livingston and Interchange Pads are in production-mode, with similar equipment, so it would be expected to see some of the same releases during routine operations." Since these emissions are during production at both pads which will last 20-30 years, can we ask the COGCC to send their inspector in to look at the logs at the triggered canister times on both of the pads?	1/25	Jean Lim		From CDPHE: Our inspection team has indicated that they will request to review records of activities and emissions/throughput on the days in question as well as the few days before and after. We'll get back to you once we have more information.
5			Do you have any update on the soil gas testing by Olson Engineering in Anthem Ranch to confirm the location of their plugged and abandoned wells? Residents are requesting an update as they said they have not received one since November when the work was announced as occurring in late November or early December.	1/21	Jean Lim	1/21	All the plugged and abandoned wellheads in Anthem Highlands and Anthem Ranch, for which we had permission to locate, have been located by a survey of Olsen Engineering. Ten well heads were located and there was one additional well that we did not have the property owners permission to locate. Broomfield’s environmental consultant, ERO, who does Broomfield's soil gas testing, is currently comparing the surveyed locations by Olsen to the 2020 ERO soil gas testing locations, which were based on COGCC data and use of a magnetometer. ERO will adjust 2021 testing sites for these wells, if necessary, based upon the surveyed map. Below is a map of the wellheads that were surveyed by Olsen. This answer will be posted to the dashboard.
6			Has the well casing been fully repaired such that nothing is leaking out from within the well any longer? And how do we know (i.e., COGCC pressure test) that the well has been successfully repaired? Also, future soil gas testing will be done routinely (annually?). Comments made at last week's meeting that the Davis 43-6 well is still leaking, which a couple of constituents were listening to, raised concerns. Is there reason to suspect that the Davis 43-6 well is still leaking? Or was the comment by the Mayor referring to methane leaking from subsurface methane pockets to other pockets and/or the surface? Levels of methane measurements in underground pockets decreased, but then increased again; How will we know when the methane pockets have been fully dissipated? Extent of the underground methane, and how the perimeter of the leak was determined. (How do we know the methane pocket is confined to that specific area?) Could the methane pocket move uphill towards Thunder Vista over time? Or is the location stable over time? AQM station on Grahams Peak Way is being done by a third party for experimental purposes, and not being conducted by the City or COGCC; To date, we have not had access to this data; Can we get access to it. and do we know it is reliable? Do we anticipate detectable levels of methane and other chemicals with current venting? And do we anticipate this to increase with the trenching such that it could pose a concern to residents nearby (or dissipate to the community)? If trenching remains in place after dissipation, would this have any impact on future soil gas measurements near Davis 43-6 (e.g., if a subsequent leak were to form in the casing, would the trenching allow the methane to dissipate to the atmosphere such that it would not be detected in the soil, but would be emitting to the community?) Residents were contacted (summer/fall 2019?) for methane measurements in basements; Is this monitoring ongoing for nearby homes? What steps to ensure safety would be undertaken before building permits are issued (which I know is an ongoing conversation)? Building permits are currently on hold for homes on Graham's Peak Way; Approximately how long will methane dissipation take (with no guarantees); Have all wells in Anthem Highlands been successfully located with the magnetometer? And have all wells had soil gas measurements taken with non-detects (except for Davis 43-6)?	1/20	City Council	1/20	Responses to these questions are in this document.
7			November 2020 Below
8			Per Section 20(B), "At least once per year, the Operator shall notify the City five (5) business days prior to an LDAR inspection of its facilities to provide the City the opportunity to observe the inspection." Did Extraction provide the opportunity for our inspectors to observe the LDAR inspection? And if yes, did we send someone out?	11/5	Laurie Anderson	11/6	Staff will follow up with Extraction to make sure they are following all ozone protocols per the agreements and ask for written reports on ozone action days. We have done multiple LDAR inspections each year. See inspector report summaries below, the inspections folder for 2020 can be viewed here. 5/28/2019 (Q2) Report: To satisfy BMP #20 of the operator agreement conducted a LDAR inspection of the rig and associated equipment - No leaks were detected. 8/192019 (Q3) Email This will be the Q3 LDAR with Broomfield for all operations (vertical and new well locations). We will start at the location designated from the Sept 24th end of day on Sept 25th, 2019. Please forward this invite to any other individuals affected by these inspections. The above inspections fulfills and exceeds the requirements for BMP 20(B) in 2019. For 2020: 9/15/2020 (Q3) Quarterly Inspections All legacy and new facilities inspected using Broomfield's ICI infrared camera. Extraction accompanied Broomfield's inspector and conducted their own LDAR inspection of new facilities with their FLIR camera.		1
9			1) The posted response said that the inspector "took note of the ECD operating" but "there was no smoke or visible emission at the time the ECD was operating." I am curious how that was observed - gauges? heard a noise? 2) The posted response stated, "Our draft regs require all flaring to be reported to the City." So does that mean that Extraction would have been required to give the City advance notice, just based on the possibility that any routine pipeline maintenance might require flaring? I was trying to look at the local draft regs 17-54-090 I Air Quality to see how we could get to a point where the regs increase the frequency of advance notice over after-the-fact notice.	11/5	Jean Lim	11/5	1) Extraction's contractor USA GasCompression was onsite performing the maintenance work on the pipeline, and the CCOB inspector observed with the IR camera a heat signature was visible from the ECD. Much like a furnace, the ECD has a pilot light, and when activated the main burners activate within the stack, visible from a porthole on the side. The main burners also emit a noise when activated, which was observed that day. 2) We will consider and report back on this issue as we prepare the next draft of the regulations.		0.5
10			I have a few follow-up questions regarding Extraction's flaring yesterday during routine pipeline maintenance, as reported in the Oil and Gas Update: 1) For this flaring event, could you have Dr. Helmig check if Boulder Air - Broomfield detected any abnormalities? 2) It seems that this was based on chance observation by the inspectors who were on the pad and was not something that Extraction brought to the inspectors' attention. Is that correct? I understand the OA does not require notification but I wanted to clarify the circumstances. 3) Would proposed COGCC 900 series draft rules have required Extraction to give us notification of this? Would our local drafted regulations have required Extraction to give us notification of this?	11/3	Jean Lim	11/4	1) Boulder AIR and Ajax reviewed AQM data for this timeframe and didn't see anything that would indicate that one of the sensors picked up the event. 2) You are correct, this was not a planned occurrence. The inspector was onsite performing the 4th quarter inspections and took note of the ECD operating. The inspector stated that there was no smoke or visible emission at the time the ECD was operating. 3) Operators must provide prior notice of planned flaring allowed by COGCC Rule 903 to local governments. Flaring, as defined in R. 903, is “combustion of natural gas during upstream oil and gas operations.” The COGCC plans to issue guidance to provide specific examples of flaring. Based on this definition it’s a little unclear as to whether flaring during pigging would be covered. I would expect it would be provided the pigging occurs on a COGCC regulated flowline that is located “upstream”—so at a production site, but not at a midstream facility. Yes. Our draft regs require all flaring to be reported to the City.		1
11			The response on the Dashboard (below) does not seem to understand the question. The question was if the methane reading at a well testing site can increase once it has decreased. The answer from the data is yes. Since there has been no explanation of this phenomena that clearly contradicts that the COGCC said that there would be slow, gradual dissipation, how can we feel confident such a spike won't happen again during construction, putting workers or nearby residents at risk?	11/2	Jean Lim		Staff continues to investiage this with the COGCC and Fremont Environmental.		20
12			OCTOBER 2020 Below
13			I went back and looked at the historical methane readings at Davis 43-6 on Graham Peak Way because I vaguely remembered something in relation to Mayor Quinn's question if methane readings can go back up. So in looking at the data (see attached), you can see where in 22 of 28 wells that the methane readings went back up at some point between readings. It seems possible that a few might be due to measurement precision, but below are a few examples with larger increases. I hope that we can find an expert who can explain this and give us some insight into what might happen in the future. COGCC-2 18' 1/21/2020 95.8 1/27/2020 95.6 2/3/2020 97.2 8/3/2020 1.2 8/11/2020 23.2 10/15/2020 0.1 COGCC-7 9' 1/21/2020 0.0 1/27/2020 0.0 2/3/2020 0.0 8/3/2020 1.0 8/11/2020 4.1 10/15/2020 0.0	10/29	Jean Lim	10/29	It does appear that there was some fluctuation in some of the August readings. Below is a timeline of events after those readings: On September 9, 2020, the COGCC informed Broomfield that the additional sampling and vapor extraction pilot testing is complete. The COGCC indicates that the results of the testing indicate that the residual subsurface methane is naturally attenuating. Further, COGCC reported that the tests at the Davis 43-6 in Graham Peak Way showed fairly poor results for the use of the vapor extraction process. However, the methane levels had dropped significantly, by simply leaving the monitoring points open to vent to the atmosphere. The amount of gas released at any one time is not measurable at the surface. The COGCC stated that they will check the methane levels again in the spring, but the COGCC has determined that additional excavation is not appropriate. The October 15, 2020 follow-up testing results by the COGCC are linked here. These COGCC test results indicate the dissipation of the methane with the much lower subsurface methane levels. This new data seems to confirm what the COGCC had previously indicated to Broomfield that from this data it was concluded that the methane levels had dropped significantly, by simply leaving the monitoring point open to vent to the atmosphere. The amount of gas released at any one time from the monitoring points is not measurable, and the levels are dropping. Also, the Broomfield Utilities division checked the manholes in the immediate area of the well and found no subsurface methane readings of concern. Mike Hickey from the COGCC stated...the Davis 43-6 location is known to have some residual methane in the soil around the well. COGCC soil sampling has indicated the levels are decreasing through natural degradation. It is impossible to predict how long it will take for concentrations to reach a de minimis level, but we expect to know more once we have the results of recently obtained samples. Broomfield will request the results of the recently obtained samples and release them when received.		0.5
14			SEPTEMBER 2020 Below
15			What is the inspection procedure after Extraction plugs and abandons a well under the OA? Do our inspectors check it immediately? How soon would it have a follow up inspection?	9/21	Jean Lim	9/21	There isn't an inspection procedure outlined in the operator agreement for inspection of Plugged and Abandoned wells. Inspection processes are developed by Broomfield's inspection team and below is the procedure that Broomfield developed and is implementing: During the plugging and abandonment process, Broomfield inspectors frequently visit the well and facility location to make observations and document the procedures and progress. Once the well plugging is complete, Broomfield inspectors conduct a plugging and abandonment inspection that includes a pre-cut and cap procedure (described below) developed to inspect Extraction's plugging and abandoning of wells to make sure that the well was properly plugged and is not leaking gases. Pre-Cut and Cap Procedure - Operator will Rig Down Move Off (RDMO) off the plugged and abandoned well once all pressure and gas flow is stopped at appropriate depths downhole - Operator will monitor the wellbore for a minimum of 5 days at the surface to ensure there is no flow or pressure to surface utilizing pressure readings and inspecting for bubbles. If necessary other gas detecting technologies such as a Sniffer or IR Camera may be used. - Once confirmed, Operator contacts Broomfield with a date/time for Broomfield to view the well to verify the flows were properly stopped downhole, with no pressure or flow at the surface as demonstrated by pressure readings and inspecting for bubbles. Other gas detecting technologies such as a Sniffer or IR Camera may be used. - After Broomfield independently verifies the P&A, Operator can move forward with the cut & cap process and continue to reclaim the location under normal procedure. - After the Operator has performed the cut & cap process, provide Broomfield with photo documentation showing the cap welded in place with the API information. - If any soil contamination is identified during removal of the tanks and other facility equipment, Broomfield inspectors will monitor the remediation work, as approved by the Colorado Oil and Gas Conservation Commission, by frequently conducting site visits to make observations and document the procedures and progress. Plugged and abandoned wells are added to Broomfield's soil gas testing list, which test plugged and abandoned well sites two times a year, subject to continued appropriation of funds for this purpose.		0.5	E.P.
16			A resident suggested that Extraction might suddenly be putting infrastructure on the NW pad just in case the COGCC implements a new rule that says operators must have a certain setback between infrastructure and homes/schools. Also, the resident asked: If Extraction wants to state that the NW Pad is still in the drilling phase, then should Extraction be told by CCOB that they cannot proceed unless the walls are up? This is what I found that would back that up: OA 28. Lighting: During the Drilling and Completion Phases, consistent with applicable law, Operator will construct a minimum 32 foot wall around as much of the perimeter of the well pads as operations allow to reduce light escaping from the site, unless shorter walls are mutually agreed to by City and Operator on a site-specific basis. OA 31. Noise Mitigation: During the Drilling and Completion Phases, the operator shall construct a perimeter wall and/or use hay bales to mitigate noise as appropriate on a case-by-case or modeled basis. CDP: 2.2 Lighting for Northwest A & B Pads The Northwest A Pad is designed to accommodate 8 horizontal wells and Northwest B Pad is designed to accommodate 8 horizontal wells. The production equipment associated with the horizontal wells from both pads will be located on the Northwest B Pad. A 32-foot perimeter wall will be utilized during the drilling and completions phases after which the perimeter wall will be removed for the production phase.	9/11	Resident via Jean Lim	9/11	The COGCC has made it clear that any setback will apply to unpermitted wells and well sites not sites that have already been permitted. There are not any lights on the Northwest Pads. The flowline work on Northwest A would be performed during daylight hours Monday through Friday. There is a noise monitor at the location shown on the map here.		0.5
17			In response to our current questions if Extraction could be using the ECD resulting in the unexplained August spikes, you told us that in the past that Extraction told you ahead of time before using the ECD, so we should trust they would do it again. The OA does state that Extraction should give 48 hours notice of any maintenance activity that requires venting. (Section 4.4.1) However, when Council was first informed about this venting on 4/15, the ECD was already in operation. Did Extraction tell you 48 hours ahead of time that they were going to use the ECD? I heard you state that they did. Then my expectation would have been that Council and the public would have been informed of the planned usage of the ECD as soon as you had been informed of Extraction's plan. I would just like to know that this communication to the public and Council will be done going forward, with either planned usage or emergency venting of the ECD.	9/3	Jean Lim	9/3	We understand that you would like the notice process around flaring going forward to include: Staff to continue to remind Extraction of the 48 hour advance and the within 24 hour emergency notice of flaring as required under the Operator Agreement. As soon as a notice of flaring is received, we will provide notice to City Council, our air quality contractors, and the public. *We will follow-up with a formal notice and analysis of the event to Council and the public of any emissions events during flarin Let me know if there is anything you would like to add or change to the process outlined above. My apologies if the notice was not sufficient the one time Extraction has given notice of flaring. We will correct this in the future.		0.5	TY
18			The response posted on the Dashboard is not clear to me. I understand that Extraction warned you that they would be using the ECD during flowback startup maintenance activity on Livingston. Do we know if/when they actually used it on Livingston? If we have a good idea of the day/time, would CSU scientists be willing to go back to the data to see if there were any similar chemical signatures compared to what we are looking at now with the unexplained spikes? Also, please let me know if you informed Council in mid April that Extraction was going to use the ECD at that time and it's just that my memory is failing me. I have not spoken about this to Laurie, but I would have expected to be informed that this was planned to happen. If Extraction or another operator planned to emit in the future, would you tell Council?	8/31	Jean Lim	9/1	We did notify City Council at the time of the flaring in the enclosed combustion device (ECD) and here is a link to that email. As to what the air quality monitoring showed on the date of the flaring in the ECD, Ajax states there was a little rise in VOCs in the area on the 15th, though it could have equally been temperature influence on the PID sensor. We saw much more VOC activity in the area on April 17th and 18th, though sensors only reached trigger-levels once on 4/17.		1
19			During the 8/26 Oil and Gas meeting, I thought I heard you state that Extraction had flared at the beginning of flowback and had given Staff notice. When was that? Was Council notified of that?	8/28	Jean Lim	8/28	On April 8, 2020 Broomfield Oil and Gas inspectors conducted a pre-flowback tour/walk through of the Livingston Pad facility. This tour/walkthrough was scheduled in advance with Extraction OIl and Gas staff so that the appropriate Extraction personnel could be on site to identify all of the equipment, describe how it operates, and to answer any questions. During this tour/walk through, Extraction staff indicated that the emission control device (ECD) would be used during maintenance activities that would be performed during the startup of flowback. Flowback then began on April 15, 2020 which is approximately 7 days after the tour/walk through was completed. The ECD was also used for maintenance activities during the startup of flowback from the wells at Interchange B, and the Broomfield inspectors were made aware of this during the pre-flowback tour/walkthrough similar to that which occurred at Livingston.		0.5	E.P.
20			In response to Deven's question, the Dashboard states, "Any flaring at night through the emission control device (ECD) on site would most likely be visible without the aid of the infrared camera." I cannot find any source that states that there would be any visible flame coming out of an ECD. Sources state that any smoke coming out of an ECD indicates something is wrong and it would be dark smoke which you would not see at night. Extraction is only required to notify CCOB during production if they are combusting/flaring, according to the OA Section 4.4.1. So Extraction is not going to feel compelled to tell us now when they claim that Livingston is not in production. I would like to request that these unexplained spikes be discussed further.	8/24	Jean Lim	8/29	The scientists from CSU and Boulder AIR continue to investigate these spikes. As we receive more information, we will share it with Council. What we know so far: - The series of August events have been observed between 8PM and 7AM. - The source of the August spikes is likely within Broomfield, and not likely related to the fires. The influence of the wildfires is primarily on PM2.5 and O3 and some select VOCs and produces broader, more slowly changing peaks because of their distance from Broomfield. The wind data is inconclusive in pinpointing a source location due to complex local air flows, although locations to the south and to the north appear important. - ECD flaring/combustion (of natural gas) would limit the amount of methane and other VOCs in detected plumes. Observations of high methane concentrations in the largest Aug. 11 benzene spike suggest the emissions did not go through a combustor or flare. - Canister data from May 25th (@ Livingston) and Aug 18th (@ BSE, which was highest benzene event) showed strong, but not perfect, correlation, suggestinmg a similar O&G-related source. - There are at least 2 different types of events: acetylene rich and non-acetylene rich. Both present with benzene. The non-acetylene rich look more like direct emissions (non-combustion) and are more likely to be O&G related. - We will try to discern a pattern to try and catch an event with the plumetracker and are reviewing past plumetracker drives to identify potential acetylene hotspots in Broomfield.	add'l info	3	SI
21			Thank you for requesting the information on the wildfire risk for the Livingston and Interchange Pad sites, prompted by the Aug 12 wildfire west of Anthem Ranch. It is helpful to know it is low risk for those pads and please pass along my appreciation to Deputy Chief Bybee of NMFRD for the report. Would the same analysis apply to the risk near the legacy wells in Broomfield and Boulder Counties? The NMFRD analysis was based on several factors which would vary for those sites: pad construction, topography and fuel loads.	8/24	Jean Lim	8/24	From North Metro Fire District: We will include legacy wells in the district wide Wildland Urban Interface survey we will be conducting if they are located in areas determined to be at moderate risk or above for wildfires. This will be a macro view of the district with areas rated based on overall wildland fire risk. Also, during quarterly inspections, Broomfield's inspection staff looks for weeds and plant growth on and immediately adjacent to the legacy sites. If any are noted, they ask the operator to control these if they think they could cause a fire hazard.		0.5	Chief Bybee
22			Could you further explain the “hazards” presented by nighttime use of the LDAR camera? Also, since we are experiencing events and spikes at night, have regular night time inspections been happening In the last few months?	8/20	Deven Shaff	8/21	All of the infrared camera inspections so far have been performed during daylight hours and with a safety escort from the operator to help make us aware of any potential hazards. Broomfield's infrared camera is not intrinsically safe in hazardous atmospheres, but having an operator escort present who is knowledgeable about the current state of operations on the sites has helped to inform Broomfield inspectors of any potential hazards. This has allowed the Broomfield inspectors to focus their attention on the inspections. The Broomfield inspectors have not used the infrared camera at night to detect leaks, releases, or flaring, and our training on the infrared camera has been for the detection of emission leaks from equipment. The camera is unable to identify what specific gas is being emitted and it does not quantify the concentration or volume of gas. Broomfield's air quality monitoring system is a robust tool for identifying releases. Any flaring at night through the emission control device (ECD) on site would most likely be visible without the aid of the infrared camera. Per Section I of the Comprehensive Drilling Plan (Air Quality Impact Mitigation Plan), no routine venting or flaring is allowed, and any emergency flaring would be through the ECD with a 98% hydrocarbon destruction efficiency. The stationary GC stations or sensors may pick up any VOCs off of the ECD at night, even though the ECD has a 98% VOC destruction rate. As noted previously, Extraction is required to give Broomfield 24 hour advance notice of maintenance flaring and cannot do routine flaring. The purpose of these notices is so Broomfield can inspect the process. Broomfield inspectors use the infrared camera near and on the pad sites and have been doing this from the beginning of the inspection program here in Broomfield. Below is a summary of how the camera has been used: - For the new Extraction Pads, quarterly inspections with the infrared camera began during the second quarter of 2019 when drilling was occurring on Interchange B. - After this initial inspection, the following quarterly infrared camera inspections of the new pads were performed during hydraulic fracturing, flowback, and production operations. - These new pad inspections included looking at all of the equipment and piping to see if there were any leaks. - Broomfield inspectors have also used the infrared camera extensively for the existing/legacy sites started in 2015 when the inspection program first began. These inspections have identified a number of leaks that were all repaired, most on the same day as the inspection. - Finally, we have used the infrared camera to look at all of the recently plugged and abandoned wells after the casings have been cemented to see if there are any leaks.		1
23			1) Do you have any data from Extraction indicating the dates/times that the sand cans have been emptied at each of the four wells that they indicate are still in Flowback? 2) Is the frequency of emptying the sand cans much less frequent indicating that they are nearing the end of flowback, or are these still being emptied on a daily basis? 3) Has Extraction indicated an estimated date for the end of flowback? Despite these wells perhaps being deeper, it does seem that these wells have been in flowback for an exceedingly long time now.	8/19	Laurie Anderson	8/19	1) No, Extraction has not provided Broomfield with the dates/times that the sand cans have been emptied. 2) Extraction has not indicated to Broomfield the current frequency of emptying the sand cans. 3) No, Extraction has not provided an estimated date for the end of flowback. We do frequently ask Extraction when flowback for the last four wells will end. They indicate that 3 of the last four wells are to the Codell formation and all four are still producing sediment. As soon as we have information as to when the last four wells are in production that will be shared.		0.5
24			As an additional question, are we allowed to use the LDAR camera near or at the pad sites? I am curious if our inspectors have used this at night to detect leaks, releases, or flaring?	8/19	Deven Shaff	8/20	Broomfield inspectors have only conducted infrared camera inspections during daytime hours. Nighttime inspections could present additional hazards for the inspectors. Flaring would be visible without the use of an Infrared camera. Regarding LDAR testing - Extraction is required to conduct quarterly LDAR inspections of the new wells and facilities with an IR camera per the Operator Agreement, but they are only required to provide Broomfield inspectors the opportunity to observe their LDAR inspections once per year. During Broomfield's quarterly inspections of the new wells and facilities, Extraction always sends a representative to answer questions and make repairs or arrange for repairs, if needed. On some occassions, Extraction was conducting their own LDAR inspections at the same time Broomfield conducted theirs.		1
25			I am curious. For several weeks now you have stated that the Livingston Pad has 14 wells in production, and 4 still in flowback. Why is it taking so long for Extraction to get the remaining 4 wells into production? Have they run out of funds? Is there a problem, beyond the fact that they are bankrupt?	8/17	Resident	8/17	As answered below: - It is the operator's call as to whether a well is in flowback or production. As of August 16, there are still 4 wells in flowback. - Extraction currently does not have a schedule as to when the final wells will be in production. Extraction is continuing to monitor the flow from the 4 wells that remain in the flowback phase on the Livingston Pad. We discuss the status of these 4 wells weekly and Extraction has not provided an estimated or specific date yet as to when flowback will be complete in the 4 other wells. The composition of the rock formations is generally the biggest driver of flowback phase time. In general, the Codell Formation has more sand than the Niobrara Formation. 3 of the 4 wells that are still in flowback are at the depth of the Codell Formation. Other driving factors can include: degree of cementation, erosion from production, decreased pore pressure, viscous formation fluids, and increased pressure. As soon as we have more definitive information as to when these 4 wells will go into flowback, we will post that information.		0.5
26			It appears that the spacing unit for the ACME site was approved at the last COGCC Hearing. See the map below for 1N68W Sections 19, 30, and 31. These sections are just north of Hwy 7 and west of Bonanza Drive. Crestone’s Acme location is the only pending location in these sections. Docket: 180400323 Cause/Order: 407-2449 Jurisdiction: Erie I appreciate that Broomfield has submitted comments concerning the ACME site in the past, and want to raise awareness about this recent approval of this spacing unit. The ACME site falls under several of the Director's Objective criteria, and would also fall under SB-181 which therefore requires the development must be protective of PHSWE. With the previously proposed location of the ACME site just north of Anthem Ranch residents, near the airport landing pattern, increased heavy truck traffic on Hwy 7, and more, I do not see how this location can be approved as protective of PHSWE under SB-181. Is there some procedure by which Broomfield can weigh in at this time to raise our concerns and/or objection? Can we reach out to the COGCC to see if Crestone is proposing a new location instead of the ACME site?	8/14	Laurie Anderson	8/14	The spacing unit order for the Acme Pad was approved in April of 2018. The COGCC did not act on the spacing unit for the Acme Pad at its last meeting or at all, since 2018. Staff checks all COGCC agendas in advance.We received a notice in error from the COGCC yesterday that indicated the COGCC approved the spacing unit at its last meeting. We confirmed with Mimi Larsen the head of the COGCC hearings unit that no additional action has been taken on this spacing unit since 2018. We asked her to check into why the COGCC sent a notice in error. As you know, the Forms 2A for the well pad and Form 2s for the wells on ACME Pad are still in delayed status and Broomfield comments are on record, per Mike Leonard at the COGCC. Determination of delay is available HERE.		0.5
27			A letter was received from Anthem Ranch HOA requesting further investigation & location of P&A's wells in their neighborhood. Original letter can be seen here.	8/14	Anthem Ranch HOA	8/14	SI staff has requested ERO (consultant) to provide a scope of work to locate the wells using ground penetrating radar (GPR) or Electrical Resistivity Imaging which can have a higher resolution than the locates using the standard magnetometer. Updates from ERO on cost and timeframe will be posted here. Follow up from ERO is posted to the right, a letter will be prepared for the Anthem Ranch HOA laying out the options for how to proceed. The response letter to the Anthem Ranch HOA was sent on August 24, 2020.		0.5	T.Y., A.V & E.P	ERO has 7 locations that require sampling to finish up the first round of sampling. Those wells are: -Schneider 31-6 (private property access must be confirmed) -Machebeuf MD 12-16 -Mapz MD 13-8 -Tihen MA 18-5 (private property access must be confirmed) -Tihen 1-18 -Vehr 1-18 -Vehr MA 18-11 The current plan is to complete the sampling during the week of August 24 and have all the results recorded in the Google Sheets file by the end of August. This assumes access to private land. As previously discussed, the second round of sampling is tentatively planned to start in October, but ERO needs additional guidance regarding CCOB’s interest in the long-term use of these wells. If the wells will continue to be used, ERO recommends a professional survey in order to precisely locate the soil vapor wells as well as magnetometer-confirmed locations. If the wells are no longer expected to be used, ERO can abandon the wells in conjunction with the second round of follow-up sampling with no additional cost or time to CCOB. If wells are abandoned at a date after the second round of sampling, ERO can prepare a cost estimate. Additionally, there are several wells that have not been installed. Does CCOB have any interest in serving as the liaison between ERO and the landowners to install the wells? Finally, Hutton 1-30 was unable to be relocated. Several attempts were made to relocate SV wells, but were unsuccessful. The area is mowed frequently and residences are located adjoining the parcel with the wells. The potential tampering is possible, but unknown. Does CCOB want to reinstall those wells? With respect to the Anthem Ranch letter, the answers are listed below by corresponding paragraph number in the letter. All wells in Anthem Ranch have been resampled, except the remaining Schneider 31-6 wells located on private property. Of the 11 wells in Anthem Ranch, 4 wells were likely located with relatively high certainty and one well was located with moderate certainty. It is important to note that a magnetometer is not a precision instrument so locations cannot be known with complete certainty. The remaining 6 locations were unable to be located with a magnetometer. Ground Penetrating Radar and Electrical Resistivity Imaging were provided in previous correspondence between ERO and CCOB as examples of technologies that may be utilized to located plugged and abandoned oil and gas wells precisely. However, ERO does not offer or specialize in these services. After talking internally at ERO, we can offer the following information: ERO is aware of two firms in the local area that conduct abandoned oil and gas well surveys: i. Olson Engineering, 12401 W 49th Avenue, Wheat Ridge, CO 80033, (303) 423-1212, POC: Trever Ensele or Nicole Pedrigh ii. International Geophysical Services, LLC, 9302 West Kentucky Place, Lakewood, CO 80226, (720) 220-3596, POC: Ronald Bell After some additional research, electromagnetic surveys are likely the best option for CCOB for several reasons: i. The ground surface assessed during the survey is typically uneven and/or vegetated and GPR needs a relatively flat/smooth surface; ii. Thick clays and silts found in the northern metro area are more conducive to electromagnetic surveys than GPR; and iii. The electricomagnetic signal from the vertical steel well is also more conducive to electromagnetic surveys than GPR. The best means of obtaining a cost estimate for electromagnetic abandoned oil and gas well surveys would be to solicit a quote from each firm based on the potential volume of work. Costs are expected to be around $3,600 per well based on a one-well job.
28			"Going through the information, it looks like the final (COGCC) inspection took place on May 6, 2020, (attached). That inspection shows all 18 Livingston wells are now in production. Why does the weekly update still say that four wells are in flowback?"	8/7	Resident	8/9	We received clarification from the Colorado Oil and Gas Conservation Commission (COGCC) regarding flowback and production. Below is a summary: - It is the operator's call as to whether a well is in flowback or production. As of August 6, Extraction states that there are still 4 wells in flowback. - It does not really matter to COGCC whether a well is in flowback or production, but what does matter is that all oil and gas that is produced from a well during flowback and production is reported to them. Consequently, a well can technically be in flowback and production at the same time. - In order for the COGCC to post production numbers on their website, their software requires that the well status be listed at "Producing (PR)". - Operators have 45 days after the end of the month to submit their production numbers (Form 7) to COGCC. - COGCC has 30 days after receipt of the production number to post them to their website.		2
29			Is Extraction just going to prolong taking off the sand traps to avoid production phase obligations?	8/6	Jean Lim	8/6	This is unknown, as of 11:08 AM on 8/6, Extraction does not have a time schedule for the final 4 wells going into production.		0.5	A.V., E.P., T.Y.
30			1. Does CCOB have surety bonds or letters of credit with operators? 2. Blanket or by each well? 3. What is the effective length of time for the financial assurance?	8/4	Susan Noble (Councilmember from Commerce City)	8/4	Strategic Initiatives are not aware of bonding or letter of credit requirements in the Operator Agreement with Extraction. We did greatly increase the insurance requirements in the operator agreement, which are attached. Please view the Financial Assurance Requirements we are considering for Broomfield's 2020 local oil and gas regulations update.		0.5
31			Why does the 7/24 Oil and Gas Dashboard reply to my Livingston reclamation question state that, "The Comprehensive Drilling Plan does not require additional berming on the south side of the Livingston Pad. That does not preclude us from requesting additional berming from Extraction." On page 70 of Section V of the CDP, the Livingston row of the chart states that there will be "15’ berms & native grasses" during the production phase. So I do not understand why it is not clear that Extraction is required to do at least 15' berming on the south side. We do not need to make a special request when it is so clearly spelled out in the CDP.	8/3	Jean Lim	8/3	Please see this picture of the berm along the south side of the Livingston pad standing on the pad. It is at least 15 feet tall. The berm has been in place around the pad throughout operations at this height or greater.		0.5
32			Further questions about these 4 wells that Extraction has designated as in flowback: 1) Are these wells on hold or are they flowing now, through sand traps? Would we know if Extraction had actually shut these 4 down, since we now know they have the ability to shut all the wells down in mid August for their purposes? 2) Are there still sand traps onsite? 3) Should we expect spikes in emissions again later when these 4 wells “finish flowback” and go into "full production”?	8/3	Jean Lim	8/4	1) These wells are not on hold and are currently flowing through the sand traps based on routine observations made during the site visits by Broomfield Inspectors. Inspectors will be able to determine if the 4 wells are shut down based on observations of the equipment made during the site visits. Some of the typical observations that the inspectors look for to confirm this include: - The sand traps are connected to the 4 wells and the valves on the sand trap piping are open. - The valves on the flowlines from the wells to the separators are open. - The separator equipment (valves and controllers) are observed and heard to be operating as the fluids move through the separators. 2) Yes, there are 4 separate sand traps onsite connected to 4 separate wells. 3) Site operations and equipment for production are essentially the same as they are for flowback, except that the sand traps are removed, so we do not anticipate emission spikes when the wells go into production.		1
33			July 2020 - Below
34			Extraction Oil and Gas has submitted Form 2As for an additional 12 wells at Coyote Trails. This is a concern for the residents living nearby, including Broomfield residents living in the Village at Palisade Park. By a quick measurement, it appears that the Coyote Trails site is about 3500 feet from Broomfield residents. (Erie's Vista Ridge residents are about 1200 feet away.) A resident would like consideration given to possibly relocating an air quality monitoring station in the vicinity of the Coyote Trails site, if/when these new wells are drilled and completed.	7/28	Resident via Laurie Anderson	7/29	The closest Broomfield residence to the south of the Coyote Trails Well Pad is approximately 3,850 feet (see map). Once Palisade Park is built out there may be homes at approximately 2,000 feet from the Coyote Pad. The Form 2A (Site Location Assessment) permit was approved by the COGCC for Coyote Trails back on 11/20/2017 and to date, 27 wells have been drilled and put into production at this pad. These 12 Form 2 permits were then rejected by COGCC on June 10, 2020 and then reposted on June 26, 2020. Staff will discuss the possibility of relocating a sensor with Ajax.		1
35			Re: update on work will begin on July 28 at the spill from the produced water storage tank at the Alaux/Sears Facility. Do you know if it is Crestone's plan to replace the produced water tank after the remediation of the soil is complete? Is it still needed at the site?	7/24	Jean Lim	7/27	Crestone's respose: More than likely the equipment will be reassembled with a new fiberglass tank. However, that will be up to our engineering department. Another note, we will only be sampling tomorrow once the tank is out. We plan on doing a rushed turn around time for the analytics and will get the results on Wednesday. Due to the amount of other active lines in the area and depending on the analytical results any further excavation will likely take place on Thursday.		1
36			Regarding the soil vapor testing: The ERO findings document does show that they only used the magnetometer on 11 wells, yet some of the wells that they did not use it on were not found. Why did they not try to use the magnetometer to find all the wells?	7/24	Jean Lim	7/24	Per the SOW between CCOB and ERO, the magnetometer is used at every single site in an attempt to locate the well. If the well depth is too great, the magnetometer will not detect the wellhead. As outlined in previous emails, the depth of each wellhead may depend on the depth at which the well owner cut off the wellhead during abandonment or if additional soil was imported to the site during pre-development earthwork. Local lithology also impacts the detection depth, but 15ft is a reasonable planning factor based on manufacture recommendations. In the spreadsheet, the column entitled “Magnetometer Detection ( Y or N)” outlines which well locations did and did not have magnetometer readings. A response of N (No) in that column means that ERO used a magnetometer, but did not detect any subsurface ferromagnetic material.		0.5
37			I have a few questions regarding the produced water spill at the Crestone Peak Alaux/Sears Facility in northeast Broomfield: 1) Are there any residences nearby that need to be notified? I can only find this 2010 Council report that says the closest residence "at 1701 W. I-25 Frontage Road [is] located approximately 1,000 feet west of the proposed wells, on the west side of I-25." 2) I think the CCOB oil and gas page says the facility was just inspected in March 2020. Is that correct? Would there have been anything in the inspection that would have been an early indication of this problem? 3) Please add this to our list of historical problems with Crestone if we ever are forced to use such a list.	7/17	Jean Lim	7/17	1) Currently the nearest residence appears to be approximately 1,450 feet to the north-northeast in Weld County and the nearest potentially occupied building associated with a business is approximately 1,350 feet to the north-northest in Weld County. Operators are required to notify Broomfield of any spills at oil and gas sites per Chapter 17-54-100 of the Broomfield Municipal Code, but there currently are no requirements for notification to residences. 2) Yes, the facility was inspected on March 26, 2020 and again most recently on June 24, 2020. No evidence of leaks or spill or any other issues were noted during these inspections that could have provided an early indication that there was a problem. (See also inspection photos taken by the COGCC during its inspection in 2018.) 3) This spill has been added to a list of concern/issues for Crestone Peak Resources.		0.5
38			A resident reported that Extraction is taking down the Livingston walls around the circumference of the pad. I thought we were told that Extraction would only be taking down the extra sound wall and leaving up the circumference walls, with Extraction stating that the reason was that 4 wells were still in flowback. I checked that yesterday's Daily Oil and Gas Communication still stated the last 4 wells were still in flowback.	7/14	Jean Lim	7/15	We see this as an opportunity to possibly address the low frequency noise issue. From Extraction Oil and Gas: The BMPs in the Operator Agreement articulated that the purpose of the sound walls was to mitigate effects of light and sound that would occur during the Drilling and Completions Phases. As we are currently wrapping up next generation flowback on 4 of the wells at Livingston for a short while longer, the lighting and noise generated from our equipment are consistent with that of the permanent production phase. Any light or sound generated on the pad at this point is not from completion operations, but from production operations. Therefore, we believe it is in the best interest of all parties to remove the sound walls now in order to effectively transition to permanent mitigation strategies around noise. The sound walls, by their nature, are temporary and can have the effect of channeling noise from permanent production facilities in an unnatural way. We believe this could interrupt our ability to get accurate data that will dictate any needed permanent mitigation. In short, we have satisfied the purpose of the sound walls as it relates to the operator agreement, we are listening to your concerns around noise, and we are taking steps to accurately measure and permanently mitigate any identified causes of those concerns. Extraction has also received consistent feedback that some citizens of Broomfield find the sound walls to be an eyesore and there has been recent clamoring to remove sound walls around the pad sites as quickly as possible. We believe this is the right course to best address each of those important considerations.		1
39			1) Can we find out what the cost of contracting for use of Ground Penetrating Radar or Electrical Resistivity Imaging would be to locate the remaining wells that cannot be located? 2) Can we appeal to the COGCC to pay for the use of this technology to find them, given our experience with the Davis 43-6 well and the density of the Anthem neighborhood? 3) If the COGCC won't cover all of the costs, could a cost sharing arrangement with CCOB be worked out?	7/10	Jean Lim	7/13	1) The two technologies referenced by the councilmember were examples I had provided in a previous email. The technologies and other geophysics applications are beyond the capabilities of ERO so we have worked with International Geophysical Services, LLC to locate wells. As far as technology-specific details, applicability, and cost, a geophysics firm would be better equipped to answer those questions. Based on the most recent survey that ERO coordinated with International Geophysical Services, LLC, the cost was $3,500 to precisely locate one plugged and abandoned well. Staff is investigation questions 2 & 3 with the COGCC.	Q's 2&3	1
40			I watched a tanker truck leave the Livingston Site today at 3:45 pm which looks like a truck that would likely be hauling oil. Just curious if there were liquid materials on site that they needed to remove or if this was product that should have gone down the pipeline per the OA.	7/9	Laurie Anderson	7/10	Extraction reports that it was doing some routine safety valve testing and the truck was used for that. Extraction indicates there isn’t a way for them to haul oil out of the site via truck.		1
41			I have been asked many times over the past two weeks about the four wells still in flowback. Do we have any information from the workers at the Livingston Pad as to when they think those four wells will go into production?	7/9	Resident	7/9	You are correct, of the 18 wells on the Livingston Pad, 14 are currently in production and 4 remain in the flowback stage as sand continues to be part of the flowback from these 4 wells. Extraction is continuing to monitor the flow from the 4 wells that remain in the flowback phase on the Livingston Pad. We discuss the status of these 4 wells weekly and Extraction has not provided an estimated or specific date yet as to when flowback will be complete in the 4 other wells. The composition of the rock formations is generally the biggest driver of flowback phase time. In general, the Codell Formation has more sand than the Niobrara Formation. 3 of the 4 wells that are still in flowback are at the depth of the Codell Formation. Other driving factors can include: degree of cementation, erosion from production, decreased pore pressure, viscous formation fluids, and increased pressure. As soon as we have more definitive information as to when these 4 wells will go into flowback, we will post that information.		0.5
42			Regarding the Davis 43-6 repairs: 1) Is the plan to perform the soil gas testing and then get a better understanding of the necessary remediation? I would like to learn more about where the methane goes as it is extracted from the ground. 2) It is noted that the single groundwater sample conducted to date near the well was 29.8 micrograms/liter where the COGCC Table 910-1 limit is 5 micrograms/liter. Is this groundwater being used in any way at this point in time such that precautions should be taken? 3) It says the "timeline to complete this schedule is 120 days from work approval" but "Groundwater collection following the initial collection will continue for these parameters on a quarterly basis for at least four consecutive quarters after which frequency can be reassessed for the remainder of the remediation; four consecutive quarterly samples will be needed for completion of the project." (p. 6 and p. 5). Will the housing permits need to be held up at least 1 1/3 years beyond the start of the work (120 days plus 4 quarters)? 4) Any details about the level of noise that residents can expect during the pilot tests would be helpful.	7/6	Jean Lim and Laurie Anderson	7/9	1) - see Public Notice. 2) - If you are asking whether the groundwater is being used as a drinking water source or for some other beneficial use, all of the residents in Antham Highlands are likely on city water and not groundwater. If there are any older water wells still in existence in the area, they would probably be completed in an aquifer that is much deeper than the shallow groundwater encountered in the monitoring well installed near the Davis 43-6. 3) Mike Hickey of the COGCC Orphan Well Program has indicated that he recently issued a Notice to Proceed to their contractor for the Davis 43-6 project. They are planning to use solar powered units for the pilot tests, which will be significantly quieter than a generator powered unit. Mike indicated the solar units are not available until the end of July, but it looks very likely that this work should begin just before Colorado Day, which is August 1st. Mike says they have significantly reduced the process from what was outlined in the Antea work plan and felt that the SVE feasibility study (i.e., pilot tests) should be performed without the additional sample points (PMW-1, PMW-2, and PMW-3) that were outlined in the work plan. Broomfield would have the final say in how long the building permits are held up and would require a meeting upon receiving any permit applications, with the builder/developer, COGCC, Broomfield's soil gas consultant, and staff, to discuss if an how any excavation and building should be done. COGCC's consultant would need to have continued access to the locations for monitoring and testing. 4) Yes, Broomfield will be issuing a public notice with regard to the testing by COGCC. As mentioned above, COGCC has indicated recently that the monitoring system they have selected is solar powered and will be significantly quieter than a generator powered unit.	Q2	3
43			1) There were two P&A wells at Anthem Ranch that ERO had difficulty locating and took extra soil samples because of it. They are Nordstrom MA6-6 and Nordstrom 6-5. It is not clear if the chart is stating that these two wells have been more accurately located now with the magnetometer and they are in good shape. 2) One of the reasons given for not expanding the ERO search area for wells that cannot be located by the magnetometer is that readings may not be accurate because of signs, light poles, stormwater infrastructure, manhole covers, fire hydrants, landscaping, rebar in concrete, and nearby cars. If that's the case, why does the COGCC use it for location? (Follow up questions from 6/30 response)	7/6	Jean Lim	7/7	From Broomfield's consultant ERO: 1) ERO has not collected any soil samples for this project; we have only screened soil vapor for methane. No soil vapor samples have been collected or analyzed at a lab (except Davis 43-6). In communication with CCOB, the term “sampled” has been used colloquially in place of screened. Nordstrom MA 6-6 should be screened in the next 2 weeks once private property access is confirmed. Nordstrom MA 6-5 was screened, but two wells were filled with water and the lithology surrounding the two other wells was not conducive to soil vapor flow. No wellhead was detected using the magnetometer, but as previously discussed, ERO is confident in the process of using historical records to locate the wells. Nordstrom MA 6-5 is located in the southern portion of a wetland area. The magnetometer likely did not detect the well due to the wellhead depth. Aerial photographs show the area above and around the well were subject to heavy pre-development grading. Since COGCC records indicate the well was cut 8ft below ground surface during abandonment, 7 feet of soil imported to the site would potentially render the well undetectable using the magnetometer. Grading plans would help confirm this. If absolute certainty of the well location is a concern to CCOB, then the next step would be contracting with a geophysics firm to utilize advanced technologies to penetrate deeper into the ground. Ground Penetrating Radar and Electrical Resistivity Imaging may reach depths greater than 15ft depending on the lithology. ERO can perform GPR but does not have an ERI capability. 2) COGCC, utility locators, and other firms use magnetometers to screen an area. The technology provides decent “visibility” of underground objects but is not a precision instrument. Rather, magnetometers are quick, cheap, and highly portable. They serve as the first line of detection. Just like a metal detector at the airport, the initial detection can signal the need for further investigation. The same principles that enable magnetometers to work for underground objects make them susceptible to interference from surface objects as listed in the question. If CCOB is concerned about the degree of certainty regarding well locations, a geophysics firm could be considered. It is important to note that the cost to narrow the search down by 10 feet or less will be relatively high for such technologies. Davis 43-6 provides an example of the process employed by ERO. Using COGCC data, aerial photographs, plat maps, and a magnetometer screening (at that time done by Mike Hickey), the well was located to within a few inches.		1
44			JUNE 2020 - Below
45			1) For the COGCC Davis well, it states. "The proposed work plan and schedule are outlined below." Did the COGCC share further details about the work plan with you beyond what you outlined? If so, is that work plan available? 2) It is surprising that only 1/2 of the wells in Anthem Ranch and Anthem Highlands have been found with the magnetometer so far. Do you think ERO Resources needs to check farther out for the wells they didn’t find? 3) For the well that the magnetometer located 30 feet away from where ERO originally sampled, should they sample in the new location where the magnetometer is now indicating it would be?	6/26	Jean Lim	6/30	1) Attached is the proposal that COGCC procured to do sampling and one soil vapor extraction point at the Davis 43-6 well. The process is estimated to take 120 days, once work approval is given. 2) Well locations are well known based on ERO’s historical file review process. Using COGCC data, plat maps, and aerial photographs, ERO is generally confident in the well locations. The additional step of using a magnetometer is only beneficial when the wellhead is located within approximately 15 feet or less from the ground surface. For many wells in Anthem Ranch and Anthem Highlands, the wells were cut several feet below ground with subsequent pre-development grading. As such some wells are simply too deep to be detected. Expanding the search area is unlikely to yield any additional benefits for several reasons: 1) Historical records provide well locations to within tens of feet, 2) current search areas are already fairly large ranging from 30ft to 80ft, and 3) many wells will experience interference from objects in the surrounding area (i.e. signs, light poles, stormwater infrastructure, manhole covers, fire hydrants, landscaping, rebar in concrete, and nearby cars). Given these reasons, expanding the search area is not recommended. If CCOB has grading plans for the developments, this may help validate the wellhead depth. 3) Historical records place Davis 13-5 in or adjacent to the west portion of Pikes Peak Drive near the intersection with Grizzly Peak Drive. One well was located on the east side of Pikes Peak Drive and was able to be sampled. Three wells were installed on the west side of Pikes Peak Drive, but were destroyed by residential construction activities and covered by landscaping. The magnetometer-confirmed well location would have been less than 10ft of the wells west of Pikes Peak Drive. If new wells were installed, they would be generally in the same locations: 3 on the west side of Pikes Peak Drive and 1 on the east side of Pikes Peak Drive, all in the ROW. Given that no methane readings have been reported for the wells, new/additional wells are not recommended.		2
46			1) Why have 4 Livingston wells remained in flowback for almost a month after the other 14 were designated as production (on June 4)? 2) Extraction used the removal of the sand trap as the change in status designation, but did we have visual evidence that there was no longer sand coming out of the 14 wells and there still is coming out of the 4 in flowback? 3) Is there any other reason during bankruptcy that Extraction would want to leave 4 wells marked in flowback? 4) Can Extraction avoid the expense of taking down the Livingston walls as long as there are wells in flowback?	6/26	Jean Lim	6/30	1) The composition of the rock formations is generally the biggest driver of flowback phase time. In general, the Coddell Formation has more sand than the Niobrara Formation. 3 of the 4 wells that are still in flowback are Coddell Formation. Other driving factors can include: degree of cementation, erosion from production, decreased pore pressure, viscous formation fluids, and increased pressure. 2) Sand from the wells flow into the traps through piping and cannot be visually observed or metered. The only way to monitor how much sand is produced by each well would require that the inspector be on site every time the traps are emptied to the sand tank. Consequently, Broomfield does not have visual evidence of how much sand is coming out of the wells. 3) Not to Broomfield's knowledge. We understand that the 4 wells remain in flowback for operational reasons. 4) It is our understanding that Extraction rents the sound walls from a contractor so it would probably be a cost benefit for the sound walls to be removed sooner rather than later. Extraction has said it will remove beams and walls from NW A & B Pads and the United Pad, starting next week. They then will take down the walls near the road to the LIvingston Pad and then they will make a determination on the remaining soundwalls around the Livingston Pad.		2
47			1) Was there any work being done at Livingston or another site yesterday morning (June 23)? 2) When were the sand cans removed from the 14 wells (day/time)?	6/24	Laurie Anderson	6/24	1) There are 14 wells in production and 4 wells in flowback on Livingston. The Interchange B wells are in production. No other site activity was observed at any of the wellpads on June 23rd. 2) The morning (by 10 a.m.) of Thursday 6/4, 3 sand cans were removed. By the afternoon (4 p.m.) of the same day, 11 more sand cans were removed - for a total of 14 removed throughout the course of that day.		0.5
48			1. How can the operator shut in a well for 2+ years without compromising the integrity of the well? 2. If the pressure is depleted, what procedure would the operator need to undertake to bring the well back into production? And for what type of volume? 3. What are the circumstances under which the COGCC requires an operator to plug and abandon a well?	6/19	Laurie Anderson	6/22	1. Wells are designed and constructed to maintain integrity no matter the status of the well. 2. All wells deplete over time, they can be brought back into production depending on the well's unique circumstance & characteristics. 3. At present COGCC does not require a well to be plugged unless it fails a mechanical integrity test and cannot be repaired. There is a Rule that states the Director may require a well that is not used or useful to be plugged. The term “used or useful” can be construed many ways and to my knowledge never has it been cited.		1
49			1) Is Carlson's 1-24 well plug and abandonment contigent on drilling of western most 318Ae Horizontal Well? a) If so, where and when was this stated and approved? b) Has 318Ae been drilled or was this the well that Extraction decided not to pursue? 2) Has there been any indication on when Extraction plans on plugging and abandoning Carlson 1-24?	6/12	Resident	6/12	1) Extraction recently confirmed that the Carlson 1-24 well is holding the mineral lease for the Livingston S19-25-1N well. a) This contingency was stated on the map referenced in the email (linked here), staff does not see mention of this lease in the OA or CDP. A mineral lease is something that is negotiated between an operator and the mineral owner(s). b) The Livingston S19-25-1N well has not been permitted by the Colorado Oil and Gas Conservation Commission (COGCC) and consequently has not been drilled. It is possible Extraction could still pursue the permitting and drilling of this well. 2) Previosly, Extraction had indicted to Broomfield on their plugging and abandonment schedule (linked here) that the Carlson 1-24 plugging and abandonment was planned for the 3rd quarter of 2020. The latest P&A schedule from Extraction does not indicate a date for the P&A of Carlson 1-24.		0.5
50			(Regarding the Carlson 1-24 well repair) 1. I realize that after the 11/12/19 failed Mechanical Integrity Test that this well work is under COGCC downhole authority, but could we have an update from our CCOB inspectors who were supposed to be observing? 2. Do our inspectors have the knowledge and access for observations to confidently state that work that was originally scheduled for 3 -4 weeks and will likely take less than 2 weeks is being completed correctly? 3. Can we get some assurances on this before the workover rig goes offsite?	6/8	Jean Lim	6/9	1. Broomfield inspectors have been and continue to be on site daily, including over the weekend, since this work began last week. Currently the work is focused on the repair of the well casing that failed the integrity test. The statement made in the 6/5 public update was based on comments made by the contractor performing the casing repairs and probably did not reflect the additional time needed to conduct a new mechanical intergrity test that will be performed once the repair work is complete. We apologize for any confusion this statement may have caused, but please know that field activites such as this cannot be predicted exactly to the day, so operators tend to make time estimates base on past experience with an allowance for potential unforseen circumstances. 2. Broomfield inspectors do have access to the location and are in frequent communication with the site contractor and Extraction regarding the progress of the repair work and mechanical integrity testing. While the inspectors do not have specific training in mechanical integrity testing, they do have a general undstanding of the process. Partnering with the COGCC and using the tools we have like the infrared camera help us to check that work like this is performed correctly. 3. Broomfield intends to discuss the results of the repairs and testing with the operator when the testing is complete and observe the well head with an infrared camera before the rig leaves the site.		1
51			(Regarding the Davis 43-6 well) 1. What can CCOB do to speed up the COGCC remediation process? 2. What additional data is needed? 3. What is "tighter control data?" Is there a chance that the report will come back and the COGCC will decide not to go forward with the remediation?	6/8	Jean Lim	6/15	1) What can CCOB do to speed up the COGCC remediation process? Broomfield will work with the CIty Attorney to determine if we can do anything to speed up the process. The report makes it sound like it could be another year until it is complete. 2) What additional data is needed? It is our understanding that if Antea Group determines that additional data is needed, it would consist of more information regarding the depth and areal extent of the methane, and the properties of the soils and shallow bedrock in where the methane exists. 3) What is "tighter control data?" Broomfield has not been in direct communication with Antea Group, but tighter control data may consist of additional borings to measure methane levels, determine depth to groundwater, and to collect samples of the soil and bedrock to determine their physical properties. All of this information would feed into the design of an effective methane recovery system. Is there a chance that the report will come back and the COGCC will decide not to go forward with the remediation? At this time the COGCC has not indicated to Broomfield that they would not go forward with the remediation. Broomfield will continue to encourage the COGCC to take all necessary steps to complete the remediation in a timely manner.		5		From the COGCC Engineering Manager: The source of methane has been removed by plugging the well. Mike has stated on several occasions in written correspondence to you that there is no current health or safety hazard from the residual subsurface methane and that the in situ extraction or treatment process will not be rapid. If successful, the summer pilot test data may be used to design a full-scale system, which would likely require a formal bidding process. The bidding process normally takes three to four months before work starts in the field. If, based on the pilot test results, soil vapor extraction is not a desirable technology, then a feasibility study to evaluate other in-situ technologies may have to be considered. In my personal experience with in situ remediation technologies, including soil vapor extraction, full scale operation and monitoring typically takes months or years.
52			(Regarding 14 wells in production and 4 wells in flowback.) 1. Has Extraction indicated to Staff an estimated date they will state that the 4 other wells are in production? 2. Has Extraction told the COGCC that the 14 Livingston wells are in production? 3. What is the phase status of the entire Livingston Pad when some of its wells are in production and some wells in flowback? 4. What will be the remaining equipment needed for EACH well when the well is in production: compressor, combustor, temporary tank?	6/8	Jean Lim	6/11	1. No, it is our understanding that Extraction is continuing to monitor the flow from the well and we do not have a specific date yet as to when flowback will be complete in the 4 other wells. 2. The COGCC does not have a specific notification requirement for when the operator deems flowback to be complete and when production begins in a well. Operators are required to submit the Operator's Monthly Report of Operations (Form 7) which indicates whether any oil or gas was produced or sold. The Form 7 is due 45 days following the end of the month that is being reported. With the Next Gen flowback that Extraction is conducting at the Broomfield pads, some gas and oil is being produced during the flowback process. When this production is reported to the COGCC, the COGCC will designate the wells to be producing even though the operator considers the wells to be in flowback. 3. While phase would normally be determined on a well by well basis, there may need to be some interpretation made on a case by case basis for how 'phase" is applied to the requirements of the Operator Agreement. Broomfield will work with the City Attorney on these interpretations. - The CDP's visual mitigation plan (Section V) for the Livingston Pad states that the walls will come down and other visual mitigations will be installed during the Production Phase. If noise is a problem during flowback, we could require the walls to remain. If the noise in flowback is not any louder than during production, we can ask Extraction to remove the sound walls. Eric Christ has stated that Extraction intends to remove the sound walls once production begins. - OA BMP 31 states that Extraction can remove noise meters at the beginning of the Production Phase. The City has its own sound meters which it is relying on to measure the sound at the pad. We do not rely on Extraction's sound meters. We can keep the sound meters in place as long as we want to do so. - OA BMP 56 states that "All New Wells will have a SSV installed prior to the commencement of the Production Phase." Extraction has a Surface Safety Valves (SSV) installed on its wells and has had since they began flowback. - The following OA BMPs all have some reference to when the Production Phase starts to set the clock for future required Extraction actions: 26.C. water sampling, This requires post-stimulation sampling of available water sources "approximately one (1) year after commencement of the Production Phase" (and 3 years and 6 years after). Since the Production Phase has begun at Livingston, I think we begin to measure the time now. 36.5 soil gas testing of previously abandoned wells. BMP 36 addresses assessing the integrity of Plugged and Decommissioned Wells. This requires that XOG perform a soil gas survey prior to production from the New Well (I believe they have) and again one year after production begins. This time could be measured from the beginning of production of any well on the pad or be based on each individual well's production date. The clock has already begun to run on most of the Livingston wells. Extraction has performed all of the pre-production soil gas testing. 4. At this time, no additional equipment will be needed for production and in fact, there well be a reduction in equipment needs from flowback in the immediate future. As examples, the sand separator is removed when a well goes into production and the sand tank that the sand separtors are emptied into will be removed from the pad once all wells are in production.		3
53			Regarding the quarterly legacy well inspections... 1) What is Extraction required to do for those inspections? LDAR testing? Soil Gas testing? Then I had other questions when looking at the OA requirements for their new wells: OA 20 B. "Leak Detection and Repair. Operator shall develop and maintain an acceptable leak detection and repair ("LDAR") program as required by CDPHE using modern leak detection technologies such as infra-red cameras for equipment used on the Well Sites. For the five (5) year period beginning with the start of the Drilling Phase at the first Well Site, Operator shall conduct quarterly IR camera monitoring of all equipment at the Well Sites. When an IR camera is used, Operator must retain an infrared image or video of all leaking components before and after repair. Such records must be maintained for two years and must be made available to the City upon request. Except when an emergency circumstance would necessitate an immediate repair, Operator must repair leaks as quickly as practicable. If more than 48-hours repair time is needed after a leak is discovered, an explanation of why more time is required must be submitted to the City. Operator shall conduct continuous pressure monitoring to detect leaks. At least once per year, the Operator shall notify the City five (5) business days prior to an LDAR inspection of its facilities to provide the City the opportunity to observe the inspection." 2) Have they been completing this quarterly? 3) Did CCOB observe these inspections? 4) Does CCOB have the IR camera images from these inspections? 5) Will Extraction be required to conduct these inspections no matter what their financial status is going forward?	6/5	Jean Lim	6/11	1) Extraction does not have any requirements for the legacy well quarterly inspections but they always sends a representative with Broomfield inspectors to unlock gates, answer questions, and make repairs or arrange for repairs as findings or potential issues are identified. LDAR testing? Extraction is required to conduct quarterly LDAR inspections of the new wells and facilities with an IR camera per the Operator Agreement, but they are only required to provide Broomfield inspectors the opportunity to observe their LDAR inspections once per year. During Broomfield's quarterly inspections of the new wells and facilities, Extraction always sends a representative to answer questions and make repairs or arrange for repairs, if needed. On some occassions, Extraction was conducting their own LDAR inspections at the same time Broomfield conducted theirs. Soil Gas testing? Extraction is using the standard procedures for soil gas testing that was established through discussions between Extraction, Broomfield, ERO, and the COGCC. These procedures were established prior to the beginning of any soil gas testing by Extraction or ERO. 2) Yes, we recently confirmed this with Extraction and they certified compliance with Best Management Practice 20.B of the Operator Agreement in their annual report for 2019 which was recently received and is currently being reviewed by Broomfield. 3) Broomfield inspectors did not observe all of Extraction's LDAR inspections but they did observed at least one in 2019 and will do the same in 2020. 4) There would only be Infrared camera images or videos if leaks were observed. Extraction has verified that no leaking components have been observed by Extraction during their LDAR inspections of the new wells and facilities. Broomfield inspectors also have not observed any leaks at the new wells and facilities. 5) Yes, that is Broomfield's understanding; however, we will confirm this with the City Attorney.		4
54			I am concerned about the possible risk of leakage or other well problems that could have ensued since Carlson 1-23 failed its Mechanical Integrity Test (MIT) on November 12. These are my further questions: 1) What has been the risk of leakage or other well problems next to Aspen Creek Elementary since the failed Carlson 1-23 MIT test on Nov. 12? I have attached the COGCC MIT Nov.12 failure report which clearly states that the well did not hold pressure during the test. 2) Staff's response stated that the results of the Nov. 12 failed MIT were tracked by the COGCC since it occurred over a weekend on Nov. 12. When did Staff find out from the COGCC that Carlson 1-23 had failed the MIT? Was there any information given to Council that it failed? I can't find any public notice. 3) COGCC Rule 326.f.(1) states that the operator "will have six months from the date of the unsuccessful test to make repairs or plug and abandon the well." Six months from Nov. 12 is May 12. Did Extraction apply in writing for an extension from the COGCC? Did CCOB know about that extension application or need to approve it?	6/1	Jean Lim	6/2	1) What has been the risk of leakage or other well problems next to Aspen Creek Elementary since the failed Carlson 1-23 MIT test on Nov. 12? This is a very good question so we reached out to the COGCC who indicated the risk of leakage or other well problems since the failed Carlson 1-24 MIT, is considered to be low. Per COGCC's explanation, "There are 2 bridge plugs down deep in the well and the last test indicated that there is no Bradenhead pressure. The casing did not hold pressure, but the hydrocarbons have been isolated from that casing with the bridge plugs. There should be no flow up the casing." The depths of the bridge plugs and the perforted depth interval of the well are all indicated on the Failed Mechanical Integrity Test Form 21. 2) Staff's response actually said "the results of the MIT were tracked through the COGCC." When did Staff find out from the COGCC that Carlson 1-23 had failed the MIT? Staff did not actually find out about the failed MIT until after the Mechanical Integrity Test Form 21 had been posted on COGCC's website on about 12/4/2019. There are no local government notification requirements in COGCC's regulation for failed MITs. Also, since this is a legacy well it would not fall under the notification requirements of the operator agreement for the new wells. No public notice was issued for the failed MIT. 3) According to the COGCC, "Extraction did timely request an extension to the six month requirement to plug or repair the well and has been in communication with COGCC about the plans for repairing the well. The extension is for July 12, 2020. The last communication indicated that they were going to start working on the well June 1." It is Broomfield's understanding that Extraction had been working with Aspen Creek Elementary to schedule the work while school was not in session. Broomfield was aware that Extraction had been working with Aspen Creek Elementary to schedule the work while school was not in session, and consequently had requested an extension from the COGCC. Since this is a legacy well it does not fall under the notification requirements of the operator agreement and the work does not require an engineering permit, so Extraction was not required to receive an extension from Broomfield.		1
55			MAY 2020 - Below
56			As described in the Daily Update, do we have any idea why Extraction is doing maintenance on Carlson 1-24 well next to Aspen Creek Elementary once again? They just did maintenance in November 2019. There is no information in today's public notice to tell us what Extraction is working on. Has anyone asked Extraction? Can our inspectors observe? Since Extraction as it now exists may be exiting, we need to have a handle on what they are leaving behind. Additional questions below: 1. Whose response is this? 2. Did we know that the MIT failed in November? 3. My other previous question was if our inspectors will be allowed to observe the maintenance. 4. Will we know the outcome of the maintenance if our inspectors are not observing?	5/28	Jean Lim	5/29	The planned maintenance in June is to make repairs following the failed mechanical integrity test (MIT) in November of 2019. The MIT was for the maintenances performed in November that Councilmember Lim references. It is our understanding that the November MIT occurred over a three day weekend when school was not in session, at the request of Aspen Creek Elementary. Because the repairs required more time and equipment, Extraction worked with Aspen Creek to schedule this work when they would have sufficient time when school was not in session. 1. This response is from Broomfield staff. 2. Yes, we did know the MIT was being performed in November over the Verteran's Day weekend and sent out the notice linked here, and had learned that it had failed. Oil and Gas staff does observe and document this type of maintenance information in addition to the other inspection duties. However, since this work was performed on a holiday weekend when oil and gas staff were not working, the results of the MIT were tracked through the COGCC. 3. Yes, oil and gas staff is planning to observe the upcoming maintenance activities. 4. If for some reason the maintenance is performed outside normal working hours, oil and gas staff will request documentation of the results from COGCC and Extraction.		1
57			With regard to elevated methane levels seen in early May: 2) Maybe the emissions are coming from the legacy wells directly to the east. (Brozowich & Davis wells.) Did Extraction do soil gas testing on them before Livingston fracking? 3) Are there any plans to do follow-up soil gas testing to make sure none of these legacy wells were damaged by fracking and now leaking? Many of the new Extraction wellbores are very close to these legacy wells to the east. I am aware that there was a retired AR oil and gas expert who recommended about a year ago that all the wells near the wellbores be soil gas tested soon after fracking. Has that been done?	5/26	Jean Lim	5/28	Staff has requested additional information from our consultant regarding the Davis 43-6 well. Here is a link to the soil gas tests previously performed by Extraction.	Consultant info on Davis 43-6	2	E.P. & A.V.
58			What is the reason why Extraction's Nordstrom 1-9 near 156th and Huron is not yet p & a? Will it be shortly, before Extraction completes spudding at United?	5/18	Jean Lim	5/20	This well is holding the minerals lease for the United pad. Until United is in production, Extraction is not required to plug this well. Jean mentions from the operator agreement that "they have 60 days following the commencement of production from a new well in each of the drilling and spacing units." Considering that the production phase from United will be later, they are not out of compliance with the Operator Agreement for not P&Aing this well.		2
59			This is lower priority, but wondering if you have received any updates for the June 5, 2019 spill located in Ward 5 that is still listed as "active" as listed on the COGCC site: https://cogcc.state.co.us/weblink/results.aspx?id=465583 Ground water was impacted with readings of BTEX exceeding established limits. And I think they needed to do follow up ground water testing. This is the original newsflash from June 19, 2019: https://drive.google.com/file/d/1e0BZ65ZXHkf3q5miDR2QchJaIUZwPz9a/view	5/15	Laurie Anderson	5/19	Extraction has submitted a Form 27 Supplemental Report with a current status, which is currently in review by Kari Oakman, the EPS covering the area while Chris is out for his knee surgery and recovery. Once Kari completes the review and approves the Form 27 we'll let you know that it is available. As a point of note, Extraction reported the discovery of non-highway diesel in one of the monitoring wells. Since non-highway diesel is not an E&P Exempt Waste, COGCC is coordinating with CDPHE for responsible oversight of Extraction's work regarding this project. Extraction is working to identify the extent and origin of diesel related impacts. We'll keep you posted about how this progresses.		2	Strategic Initiatives - E.P. & A.V.	Summary from APEX Consulting (company performing the monitoring and remedial investigation) The groundwater plume has been delineated in the cross- gradient directions of groundwater flow; however, when the monitoring wells were installed, groundwater flow direction was inferred to flow east from the source well (BH08). Once the wells were installed, depth to groundwater measurements could more accurately define groundwater to be flowing north-east from well BH08 towards well BH04. The benzene exceedance at well BH04 necessitates an additional well be installed northeast of well BH04 to track the downgradient extent of the impact plume and natural attenuation (see Figure 6). Additionally, refined RCRA waste was discovered as LNAPL in well BH03. This refined product is a separate impact from the unrefined E&P waste being remediated under the COGCC Remediation Project. The RCRA impact plume is located within the defined boundary of the E&P waste impact plume. Additional monitoring wells are necessary to delineate the extents of RCRA impacts from the E&P impacts, and a separate project will need to be initiated with the CDPHE to remediate the RCRA waste separate from the E&P waste. The COGCC has indicated that they will not close out the E&P waste remediation (Form 27) until four quarters of clean groundwater samples have been collected. However, the E&P waste remediation closure will not occur until the RCRA waste is cleaned up. The RCRA waste cleanup should occur under the CDPHE with potential help from the Colorado Division of Oil and Public Safety. Full documents linked HERE.
60			With Extraction indicating that they are discontinuing operations everywhere due to financial conditions, have they completed all their required p & a of wells in Broomfield? I wanted to make sure that the timing of their seemingly unregulated decision to mark the Livingston wells out of flowback and into production doesn't leave us hanging with wells they should have plugged & abandoned. Thanks. Operator Agreement "The plugging and abandoning of a particular P&A Well shall commence within sixty (60) days following the commencement of production from a New Well located in each of the drilling and spacing units encompassing the leasehold originally drilled by such P&A Well."	5/14	Jean Lim	5/18 & follow up 5/19	Exhibit C from the Operator Agreement showing the status of the proposed Plugged and Abandoned wells. The columns in light green have been added to the Exhibit. The Exhibit shows that of the 41 wells to be Plugged and Abandoned, 25 are located within Broomfield County. Of these 25 wells in Broomfield, 23 have been Plugged and Abandoned to date. In the previous schedule linked here, the Nordstrom 1-9 was scheduled to be P&A'd in the 4th quarter of 2020. We have not received any information from Extraction as to any changes in that schedule.		3		Here is link for the previous P&A list from the Oil and Gas web page which shows that the Nordstrom 1-9 is scheduled to be P&A'd in the 4th quarter of 2020. If you compare the schedule to the updated list sent in the previous response, Extraction appears to be ahead of their initial schedule. There are 6 remaining wells to be plugged and abandoned and only 2 are in Broomfield. The Nordstrom 1-9 and Carlson 1-24 are holding minerals until replaced by new production.
61			5) Today's COGCC FAQ: “Are shut-in wells dangerous?” "● No. COGCC rules require operators to construct oil and gas wells so that the wells can be reliably "shut-in" with valves that safely stop the flow of product at the well. COGCC rules require operators to construct oil and gas wells such that the wells can be reliably "shut in" with valves that stop the flow of product at the well." This statement was made by COGCC Staff throughout today's presentation. We should keep this in mind if conditions arise as flowback continues.	5/11	Jean Lim	5/14	CCOB staff will keep this in mind if conditions arise as flowback continues		3
62			3) How will we know if Extraction shut-in Interchange B or Livingston wells? Will our CCOB inspectors observe this if it were to happen? Otherwise, it could be a few months until the COGCC even knows. The COGCC presentation stated that an operator must report the production or status, including a “shut-in” status, of each well monthly on a Form 7. Form 7s are due 45 days from the end of the month being reported. During the hearing, Commissioner Boigan confirmed news reports with what he is hearing from operators, that operators may be forced to shut down recently drilled horizontal wells by midstream pipeline companies.	5/11	Jean Lim	5/14	Operators do not have to notify the COGCC when they are planning to shut-in a well. Wells are regularly shut-in for any number of reasons including maintenance. If the wells are shut-in for an extended period, additional equipment may be required in order to get the wells back into production. Therefore, operators prefer not to shut-in newer wells. Most operators would prefer to shut-in vertical wells or older horizontal wells that may not be producing as much and have lower formation pressures. While the operator is not required to notify CCOB, Broomfield’s inspectors will monitor which wells are shut-in during routine inspections.		3
63			2) Tami wrote in response to my question last week that further work on the Davis 43-6 well p & a methane leak scheduled for March by the COGCC was delayed due to COVID-19. I am concerned about how long that will be delayed. The COGCC cannot indefinitely delay this project and at the same time make this White Paper statement, "Regardless of the economic conditions and in the face of a workplace pandemic, the COGCC is poised to continue its responsible regulation of the oil and gas industry in Colorado in a manner that protects public health, safety, and welfare, the environment and wildlife resources."	5/11	Jean Lim	5/14	COGCC has indicated that the Davis 43-6 plugged and abandoned well does not pose an imminent threat, as the source has been sealed. COGCC’s contractor is using its best judgement to determine when they can safely perform the work within the Governor’s safe distancing orders for COVID-19. A site visit, with Broomfield, COGCC, and the contractor is planned in the near future. CCOB staff will provide updates on when this work is anticipated to begin. Dr Helmig's assessment of a recent methane event can be viewed HERE.		3
64			1) The hearing discussed COGCC oversight of drilled but not perforated/stimulated wells (DUCs). What oversight will the COGCC have on the United Pad wells which will just be spudded? Today's COGCC white paper states that "wells can remain in either condition [DUC or shut-in] provided the operator performs a mechanical integrity test within two years of setting the casing."	5/11	Jean Lim	5/13	The COGCC will conduct an inspection during the United Pad spudding. They will inspect, and will continue with regular follow-up inspections while the wells are shut-in. These inspections will include review of stormwater mitigation and watching for any degradation of the well pad. If any wells are not drilled within 2 years, a Mechanical Integrity Test (MIT) will be required.		2
65			Is someone from Staff planning on attending this hastily called COGCC meeting on Monday to discuss if "the COGCC has the necessary resources and regulatory framework for the current oil and gas industry downturn?"	5/8	Jean Lim	5/11	SI Staff did attend, summary report can be viewed here: https://docs.google.com/document/d/17GIcYqKnzvODHmEIbekaKd99EoC_An07gWsjt_lJFLE/edit?usp=sharing		1
66			Could you please ask our experts (Barbara, Mike Leonard) to explain this difference: Occidental Petroleum just decided to shut in its CO wells to wait for the price of oil to go up until probably mid-June, yet our experts stated it was risky for Extraction to wait to start flowback. [cited] "Occidental is the first to outline plans that include such a large number of shut-ins in Colorado. The 15,000 barrels of crude per day cut from production locally amounts to just over 12% of the 121,000 barrels of crude oil the company reported averaging daily in the Rockies during first quarter." [cited] "It [Occidental] forecasts running no drilling rigs in the Denver-Julesburg Basin for the rest of the year."	5/6	Jean Lim	5/7	Response from Barb Ganong, petroleum engineer: Difference between OXY shutting in wells in a low price environment and recommendation to commence flow back and production of newly completed Extraction wells. With extremely low oil prices many operators choose to shut-in wells, reducing expenses, and wait till oil prices justify bringing the wells back on production. This has happened many times historically and is somewhat a routine industry response to low commodity price environments. Generally, operators will start by shutting in the lowest production wells first, which tend to be the least economic wells. If the lease terms require that production must be realized each month, as in a held by production clause in the lease, then wells may be shut in for much of the month and produced for a day or two to hold the lease active. It is common practice to leave the newest and most productive wells producing. Occidental is operating many wells, most of which are not newly completed. In the Denver-Julesburg Basin, new wells are generally those that have been hydraulically fracture stimulated just as those operated by Extraction at the Livingston Pad. In most instances, immediately after a hydraulic fracture stimulation, the pressure on the well is the highest. Once the well begins flow back, the pressure declines and continues to do so throughout its productive life. The many wells being shut in by Occidental and other operators around the world have been producing for some time and the pressure is much reduced compared to a newly completed well that has been hydraulically fracture stimulated. All other criteria being the same, it is safer to shut in a low pressure well than to shut in a high pressure well. For this reason, it is safer to flow back and produce a recently stimulated well, reducing the pressure on the well, than to leave it shut in with high pressure indefinitely. Response from Mike Leonard, COGCC: OXY is not fracking wells they have drilled that is not the subject of the article. It's pretty clear in the article that the older lower producing wells will be shut in first. Nowhere does is say all wells will be shut in, in fact it says they will shut in hundreds of wells and the have over 5000 in the basin.		1
67			APRIL 2020 - Below
68			Per April 17 email - Broomfield would like to once again request an updated operations schedule for all the pads and a certification from Extraction that all of the equipment at the Well sites continues to operate within the design parameters.	4/30	Tami	5/1	I can confirm that, other than this setting of surface casing at United and production at Interchange and Livingston, Extraction does not currently have any plans for any development operations in Broomfield for the remainder of 2020. This of course remains subject to change in the future, but at this point Extraction has established its schedule for the remainder of the year.		1	Strategic Initatives
69			Since Extraction has provided notice to spud on United, will Broomfield be holding them to the OA requirement to submit a new schedule?	4/29	Lizzie Lario	4/29	This is the most current schedule we have from Extraction, which was last updated by Extraction in January (see link in follow up section). We have asked for an updated schedule of activities from Extraction two times, since receiving their notice on spudding of the United Pad, which could begin as soon as May 18th. We are pursuing an updated schedule further with Extraction. The contract does require Extraction to update this schedule as necessary.		0.5	Strategic Initatives	https://www.broomfield.org/DocumentCenter/View/29674/Current-Broomfield-Project-Schedule---10-31-19?bidId=
70			While the high TVOC values may still be in normal range, you can see a general rise in those values as more wells come online to where it is approaching out of normal range. Why are today's high values noted for Wildgrass 02 and Anthem 02 instead of Wildgrass 01 and Anthem 01 as have previously been reported?	4/29	Resident	4/29	We have some flexibility here so if there's a different approach you would like us to take, please let us know.		0.5
71			Now we really are going to face the nightmarish alternative truck route that was just approved on Tuesday with the Extraction agreement for the turn lane at 160th and Huron. Is Extraction going to pay for the police to monitor the left turns onto 160th and Sheridan, as they had stated to Staff? Do we have extra police officers for this during the pandemic?	4/17	Jean Lim	4/20	Extraction's agreement calls for all class 7 (semis & tanker trucks) and above are not allowed to operate on public roadways during the peak hours of 7-9 am and 3-6 pm. We also reserve the right to modify or direct changes to traffic control devices at any time due to safety concerns for the general public. Broomfield's Traffic Engineer reports that during spudding operations 15-20 truck trips per day is an insignificant amount of volume even for large trucks, Also, the anticipated 70 truck trips per day for the mobilization and demobilization should not create a traffic problem. The spudding operations are only anticipated to last three weeks. To compare, Extraction has completed the spudding operations at the Livingston site without any major traffic conflicts occurring at the intersection of Sheridan and Lowell. We would anticipate the same for this site as well. We would expect any traffic control needs at the access to the site on 160th Avenue, and the intersection of 160th Avenue and Sheridan Parkway would be performed by Extraction contractors. We have forwarded these concerns to Broomfield's Traffic Engineer.		1	Strategic Initiatives
72			Do we have any way to verify that Extraction is really serious about going forward with these drilling plans and not just throwing a head fake?	4/17	Jean Lim	4/20	You have all the information we have on Extraction operations and the soonest they could start spudding at United is May 18th.		1	Strategic Initiatives
73			Were we given any specifications for the height of the compressor sound wall in the CDP or anywhere else?	4/16	Jean Lim	4/16	We are not aware of any specfications for the compressor sound walls in the CDP or Operator Agreement. We are taking the heights and the location of the production equipment and having a site rendering completed to determine what will be seen with the berming, once the temporary sound walls are removed.	Pending site rendering to be delivered by consultant	0.5	Strategic Initiatives
74			In an Extraction photo simulation that gave some indication of planned relative sizes, it shows the ECD about 5 times as tall as the compressor wall, and the ECD is less than 30 feet as far as I know. You stated the current compressor wall is 20 feet.	4/16	Jean Lim	4/16	The ECD is currently 40 feet tall. The ECD may be shortened in future years as the well production declines. Based on discussions with Extraction and on site observations, the compressor sound walls will be 20 feet tall.		0.5	Strategic Initiatives
75			Is the permanent compressor wall taller than Extraction planned because they are trying to avoid any more noise violations?	4/16	Jean Lim	4/16	We do not know what Extraction originally planned for the compressor sound wall height, or even if these sound walls would be installed since they were not specifically called out in the text of the CDP or Operator Agreement.		0.5	Strategic Initiatives
76			That is fine for now when it is behind the 32 foot sound wall, but as Laurie said it will be an unexpected permanent eyesore in the neighborhoods. Can we ask an expert if they anticipate that a 20 foot compressor wall will be needed during production?	4/16	Jean Lim	4/16	We can discuss this with our sound expert, but it may come down to a choice of additional noise mitigation versus a visual eyesore. If the need for the compressors declines over time as the well production declines, it may be possible to revisit this issue with Extraction to determine if the walls can be reduced in height or removed.		0.5	Strategic Initiatives
77			Can you provide more information about the Livingston on-site "compressor station" since I was under the impression that the compressor station was outside of Broomfield in Weld County. The compressor station south of the new Chase data processing center that is now out of commission was loud. Is this a similar station?	4/14	Laurie Anderson	4/14	The compressor station on the Livingston pad is used to push gas from the well into the pipeline similar to the one near the Chase data processing center. The difference is that the Livingston compressor station is operated by electrical power and will be much quieter than the one near the processing center which the inspector believes operates off of gasoline or diesel fuel. Also, smaller sound walls are being installed around the compressors at Livingston as additional sound mitigation.		0.5	Strategic Initiatives
78			Or is this compressor station just a temporary one to deal with the high surge of early natural gas? And then will it be removed in a few months?	4/14	Laurie Anderson	4/14	The compressor station at the Livinston Pad will be there for the life of the wells.		0.5	Strategic Initiatives
79			Also, what powers the turbines? Are they electric, diesel, or other?	4/14	Laurie Anderson	4/14	The compressors are electric and are similar to those on Interchange.		0.5	Strategic Initiatives
80			Is the risk of a situation that would require an emergency shelter-in-place or evacuation greater during the first day or first few days of when the well is first brought on line? Or is the risk constant during the entire 3-6 month period of flowback?	4/13	Laurie Anderson	4/14	There is likely to be more activity the first few days a well in brought on as the all of the equipment is being adjusted and maintenance activities are performed, but according to the COGCC and Broomfield's contract technical expert, the processes being used in Broomfield lowers risks because there are a number of safety protocols and shutdown equipment in place and no fluids are being stored or exposed on location.		1	Strategic Initiatives
81			Assuming the risk is higher when wells are first brought on line: Are the wells starting flowback in groups of 4 similar to Interchange B? Or one at a time?	4/13	Laurie Anderson	4/14	The wells will be brought on into flowback one at a time as was the case at the Interchange B Pad. At Interchange B, it took approximately 3 days for the first 10 wells to be in flowback. It is our understands from discussions with site personnel during our inspections that Extraction will base the rate at which wells are brought into flowback on the performance of each well.		1	Strategic Initiatives
82			Based upon the schedule of the wells being brought online, and anticipating that higher emissions will occur when the sandtraps are emptied, is it anticipated that the sand coming back up will be heaviest during the first few days of each well? Or will sand continue to come back up and a steady rate for the entirety of 3-6 months.	4/13	Laurie Anderson	4/14	According to the COGCC, they expect there will be more sand produced in the earlier part of flowback and then it will taper off. Broomfield's contract technical expert also indicates that sand returns may be heaviest during the first few days of flowback for each well. During Broomfield's discussions with Extraction when the Interchange B wells were in flowback last year, they implied that the sand volumes were not significantly more during the first few days of flowback and that was because of the process they are using to bring the wells into flowback. It is difficult to say at this time whether the Livingston wells will behave similarly to those on Interchange B.		1	Strategic Initiatives
83			Is there any requirement for Extraction to tell us when flowback begins? If so, do you intend to post a public notice?	4/9	Jean Lim	4/10	Extraction has not shared their schedule with us probably because they anticipate that their original schedule could change as the operations progress based on the performance monitoring that will be conducted for each well as it is put into flowback.		1	Strategic Initiatives
84			COGCC had pledged onsite oversight during flowback. Is that COGCC field expert ready to start and is communication in place between CCOB and COGCC?	4/7	Jean Lim	4/7	COGCC has indicated they will have staff on Livingston from time to time during flowback operations.		0.5	Stategic Initiatives
85			Are there safety concerns if the Livingston Pad operations were to be stopped, for weeks or months, in its current state before flowback is started? What are those concerns and have you seen that happen before at well pads?	4/3	Jean Lim	4/6	From the COGCC - Safety is a concern if flowback were to be delayed if there were a failure of one of the valves or the wellhead equipment. There is concern about damage to the wellbore itself if flowback does not occur in reasonable amount of time. Stopping flowback in the process would raise the same issues. To my knowledge no company has delayed flowback.		1	Strategic Initiatives
86			What is our responsibility as a city and county to ensure wells properly plugged and abandoned and what does that look like 10+ years down the road? Are we letting residents know about future leak tests, etc.? Can you let us know the costs and who pays?	4/3	Heidi Henkel	4/4	See email response		1	Strategic Initiatives
87			MARCH 2020 - Below
88			Can we find out how many other wellpads have used the Next Generation flowback equipment that Extraction is using?	3/31	Council Meeting	4/2	The COGCC indicates that Great western has and is using this system. They have used it at the Stillroven, and Raindance Pads and will be using it at the Brant Pad. Crestone used it at the Cosselt and other pads.		2	Strategic Initiatives
89			Can we provide a list of the issues prevented due to Broomfield inspection staff being onsite regularly?	3/31	Deven (Council meeting)	4/2	Read email response here.		2	Strategic Initiatives
90			Has Extraction provided detailed operating instructions to Broomfield about how they plan to operate the ECD? *Have operators been trained? Does the ECD have an automatic control system that will shut down the flow of flow-back gases to the ECE if the temperature of the destruction zone drops below the design level for 99.9% destruction? At some point will XOG provide updated details in regards to the ECD and other operations in a public record?	3/31	Darrell/Council	4/2	In response to your latest set of comments below, Broomfield will be enforcing the 98% hydrocarbon destruction efficiency provided in Exhibit B, Section 25 of the Operator Agreement. Also, we will be enforcing the requirement in the Comprehensive Drilling Plan that Extraction provide certification and documentation that onsite equipment is continuously operated within its design parameters. We would reiterate that the Extraction facility is fully automated. If the pilot goes out on the ECD, flow will be shut off, as in the gas flow will stop. With the automation, the facility will shut down and the wells will shut in as the appropriate shutdown parameters are met.		2	Strategic Iniatives
91			Will Extraction shutdown the back-flow operation if: a.The ECD does not operate at the temperature necessary to achieve a 99.9% destruction efficiency? i. If so, is the temperature continuously recorded? ii.Will flow-back operations stop if the correct operating temperature of the ECD is not maintained? b.The maximum design flow rate of VOC is exceeded? i. If so, how is the flow rate monitored? ii.Is the shutdown automatic or operator dependent?	3/25	Darrell/Laurie	3/30	Read email response here.		3	Strategic Initiatives
92			Tami indicated 3/24 that XOG operations were 7am-7pm. XOG is obviously working until at least 11:30 pm and starting by about 5:30 am? How will it impact how soon flowback can start?	3/28	Jean Lim	3/30	Per the comment about operation from 7am to 7pm, those were the hours that the work over rig (production tubing installation) and production facility construction crews were working. The reason the workover rig was limiting hours was because they had caught up with the coiled tubing rig. Since the coiled tubing rig was moved off site yesterday afternoon/evening, it is no longer in the way of the workover rig and they are working longer hours.		2	Strategic Initiatives
93			Will operations at the other pads (NW and Interchange A and B) also be suspended until social distancing is removed?	3/25	Kathy Swan Bogard	3/25	Response from Jean Lim: I think this might address your question. Here is a statement from the 3/20 Oil and Gas Update on "Air Quality Monitoring Program": "This week, Extraction confirmed that they do not intend to engage in additional operations at five of the well pads in Broomfield (NW A&B, United & Interchange A&B) in 2020."		0.5
94			The consultants were going to review flowback operations on 3/23 prior to actually being on the pad. Did they have any immediate recommendations?	3/24	Jean Lim	3/24	No immediate recommendations were made by the consultants.		0.5	Strategic Initiatives
95			Do these pipes go straight down 2-3 miles at the Livingston pad and then make a 90 degree turn? Or do they go on a gradual slant to get down 2-3 miles?	3/23	Lizzie Lario	3/23	The wellbores and pipes are vertical (not slanted) to a depth of between approximately 1300 to 1500 feet. Below this depth the wellbore and pipes are slightly angled or slanted down to a depth of between approximately 7000 and 8000 feet. Below this depth the angle or slant of the wellbore and pipe starts increasing more significantly until they become horizontal at a depth between approximately 7500 to 8000 feet below gound surface.		0.5	Strategic Initiatives
96			Please provide an update to Extraction's schedule as far as: - completion of tubing - completion of milling - installation of equipment needed for flowback - completion of the closed loop pipeline - anything else needed before flowback starts	3/23	Jean Lim	3/23	Link to Newsflash posted 3-23-2020		0.5	Strategic Initiatives
97			Providing Extraction's 2020 Emergency Managment Plan with changes for COVID-19.	3/20	Tami Yellico	3/20	Link to email		0.5	Strategic Initiatives
98			While Broomfield is shutting down, will the oil and gas team be able to devote full attention to the ongoing work to protect health and safety from the existing operations?	3/15	Laurie Anderson	3/16	link to email		1	Strategic Initiatives
99			Concerns about black smoke at the Livingston Pad received on 3/13.	3/13	Jean Lim	3/13	Staff was contacted regarding black smoke, contacted NMFRD to request a check at the Livingston Pad and also contacted our inspectors. Our inspectors were onsite in the afternoon and confirmed there were no issues at the pad. All concluded that the black smoke was from an engine starting up or shifting gears. There were no notices of canisters triggered at the sensors near Livingston Pad. The NMFRD's report from Engine 66 that was dispatched to the Livingston Pad is attached and the notes read as follows: E66 was toned to above address on black smoke rising from the Livingston Oil Well Pad. E66 responded code 3 from Lowell and Anthem Ranch and arrived in the area to investigate. No smoke was visible from the street, so E66 proceeded to the well site. On arrival to the well, there was some black exhaust coming from a water pump, but no other smoke was found. E66 contacted the site manager to confirm everything was operating as normal. The site manager said the water pump will emit black exhaust every time it shifts gears. The site manager confirmed there was no problem with the pump and everything on the site is operating as expected. With no problem found, E66 cleared without further incident.		0.5	Strategic Initiatives
100			COGCC stated it typically only takes a day or two to run tubing in a well. Is that sequential per well, meaning 18-36 days for tubing at Livingston after coiling is complete?	3/10	Jean Lim	3/12	You are correct in that this operation is sequential after coiling is complete. At the Interchange Pad two rigs were used to install the production tubing, so we assume that if the equipment is available, Extraction will also use two rigs at Livingston which will reduce the number of days to between 9 and 18.		2
101			In regards to Mike Leonard's response to Jennifer on 3/9, Why does he indicate uncertainty on whether Extraction is using 2 rigs taking 6 weeks or 1 1/2 rigs taking 8 weeks for coiling?	3/10	Jean Lim	3/12	COGCC responded indicating that while they receive and provide oversight of operations they do not have daily or weekly activity logs that would indicate the specificity of the daily usage of the rigs. Meaning, they can't ascertain whether it will be a 6 or 8 week process. COGCC has assured us that the oversight includes the quiet rig remaining in place until the completion of that phase and that maximum of 2 rigs will be used during day and only 1 will be used at night.		2	CMO
102			In regards to Mike Leonard's response to Jennifer on 3/9, how long will tubing take place at the Livingston pad, following the coiling? Mike indicated a day or two for tubing in a well, which would be 18-36 days for tubing at Livingston.	3/10	Jean Lim	3/12	Milling operations of the remaining wells continues with the two coiled tubing units. Production tubing installation requires 1 to 2 days per well and two workover rigs are used to install the production tubing. All of the production facility is built by the time production tubing installation is complete, and after production tubing is installed, it will take between 7 to 10 days to finish installing and testing the flowlines from the wells to the production facility. Please keep in mind that this estimate is approximate and we will revise it if any of our assumptions change.		2	CMO
103			Has Extraction drilled 3 mile laterals at Livingston?	3/6	Jean Lim	3/10	Staff reviewed the planned directional data files for the Livingston Pad wells that are on the COGCC website, and the length of the laterals (the horizontal section of the wellbores) are less than 3 miles. Extraction is not drilling 3-mile laterals on Livingston based on the directional data.		2	SI
104			Has Extraction provided the required documentation per Section (R) Risk Management?	3/5	Laurie Anderson	3/17	See email response		8	Strategic Initiatives
105			There is concern about flowback and why should we believe their Closed Loop systems will keep us safe from breathing harmful VOC's?	3/5	Becky Mcleod	3/6	Broomfield inspection staff is regularly onsite during all operations including flowback. Any irregularies noted during inspection, will be brought to the operator's attention for correction. Please see the graphic (linked here) created by CSU showing the difference in emissions collected during flowback at Interchange vs traditional flowback.		1	Strategic Initiatives
106			Can Broomfield purchase or lease a magnetometer to determine the location of plugged and abandoned wells?	3/4	Jean Lim	3/5	Due to the intensive training and expense involved in using a magnetometer, Broomfield would like to propose to use ERO or another qualified consultant to provide this information. Staff has received an estimate for these services to be included with their soil gas testing program. (ERO was hired to perform these tasks.)		1	Strategic Initiatives
107			Can we confirm that ERO (soil gas consultant) was able to locate all the plugged and abandoned wells?	3/4	Jean Lim	3/5	Following is the confirmation from ERO, Broomfield’s soil gas consultant: We have located all the wells provided to us, which are listed on the attached map, except 2. VEHR MA 18-13 and VEHR MA 18-14 are located at Holy Family HS in the football field and a gravel parking lot. We are confident in the location of these wells, but access has not been granted due to construction activity. We used the same approach to locate the wells, which was outlined in the protocol we submitted to CCOB.		1	Strategic Initiatives
108			Please provide an update on the Davis 43-6 well testing.	3/4	Jean Lim	3/5	The COGCC has created a soil gas treatment process. The Davis 43-6 will be included in this process. COGCC is working on getting payment mechanisms in place for a soil gas treatment process plan. As of 3/10/20, the COGCC states that they have received approval and will move forward with the consultant for planning. Broomfield will be notified and when the process will start, and will share this information with Council.		1	Strategic Initiatives
109			Tetrachloroethylene- Is Extraction testing for it in well water?	3/4		3/6	Not at this time. We will follow up if necessary when our soil test results are received. **UPDATE - The soil tests came back negative, so no additional tests will be requested.		2	Strategic Initiatives
110			Is the city doing water testing after the tetrachloroethylene trigger?	3/4	Jean Lim	3/6	In regards to groundwater, we need to wait until the soil testing results are completed to determine if water testing is necessary. If there was a spill it would have had to travel through the soil to reach the groundwater, so we would need to see residual tetrachloroethylene in the soil to know whether a spill occurred. **UPDATE - The soil tests came back negative, so no additional testing will be requested.		2	Strategic Initiatives
111			Is the city doing soil testing on the Livingston pad after the tetrachloroethylene trigger?	3/4	Jean Lim & Deven Shaff	3/5	Yes, the City hired ERO to provide soil testing of the area. Please see the link to the email with results here.		1	Strategic Initiatives
112			Confirm that COGCC will provide flowback specialist to be onsite to monitor XOG operations	3/4	Jean Lim	3/10	link to email		4	CMO
113			Confirm with COGCC that there may be a prolonged period of flowback due to Extraction waiting to install production tubing.	3/4	Jean Lim	3/4	Per Randy Silver: That is inaccurate, when they asked how long the coil tubing units would be there I informed them this process is going to take longer due to the fact they removed the third unit and only 1 unit is performing night time operations.		0.5	Strategic Initiatives
114			When will we get an updated schedule from Extraction on flowback?	3/4	Jean Lim	3/5	Staff has requested this information from Extraction and will share it as soon as it is received	follow up with XOG	1	Strategic Initiatives	April 29, 2020 - Staff continues to request this information from Extraction.
115			What type of future well operations should the residents of Wildgrass, Anthem, and Silverleaf expect at Livingston and the other sites? ( We need to let residents know if this is going to be a situation in which every few years these communities are facing extended well operations.)	3/4	Laurie Anderson	3/10	link to email		4	CMO	CMO emailed the COGCC. Response is included in the email link
116			COGCC - What safeguards are in place for future operations like production tubing, lifters, re-fracking, etc?	3/4	Laurie Anderson	3/10	link to email		4	CMO	"
117			COGCC - What type of operations would require a new permit?	3/4	Laurie Anderson	3/10	link to email		4	CMO	"
118			COGCC - What future operations are allowed under the current Form 2/2As and OA?	3/4	Laurie Anderson	3/10	link to email		4	CMO	"
119			Can Broomfield force Extraction to P&A the Carlson 1-24 well?	3/4	Jean Lim	3/5	COGCC records indicate the well has been shut-in since 12/1/2017. According to COGCC Rule 319.b.(3) A well which has ceased production or injection and is incapable of production or injection shall be abandoned within six months thereafter unless the well passes a successful mechanical integrity test per Rule 326, and the time is extended by the Director upon application by the owner. COGCC records indicate that a mechanical integrity test was performed on the Carlson 1-24 on the weekend of Veteran’s Day 11/11/2019. The COGCC states that the MIT is good for 5 years and the well may be tested again prior to the end of that period. If it passes it is good for another 5 years. Under the current rules this can continue indefinitely.		1	Strategic Initiatives
120			Given the unexpected nature of the tetrachloroethylene exceedance, a review of procedures used to do the well water sampling is needed to ensure all harmful chemicals that may be from oil and gas development are measured.	2/24	Anthem Ranch Residents (from Jean Lim)	2/26	This question was discussed with the CCOB water treatment staff and they did not recommend adding tetrachloroethylene to the list of parameters for the water well sampling for the following reasons: There are no water wells within a half mile of the Livingston Pad. Tetrachloroethylene was only detected in the air and not the soil near the Livingston Pad so there is not a reason to suspect that tetrachloroethylene is in groundwater. Drinking water for the communities adjacent to the Livingston Pad is supplied by the City and not groundwater. Tetrachloroethylene is not a compound commonly associated with oil and gas operations.		2
121			Please provide an estimate of Flowback with use of 3 coiled tubing units	2/22	Laurie Anderson	2/23	We currently estimate that flow back on the Livingston Pad could begin sometime between the first and third weeks of April. This estimate assumes: Milling operations of the remaining 8 wells continues with the two coiled tubing units, Production tubing installation requires 1 to 2 days per well and two workover rigs are used to install the production tubing, All of the production facility is built by the time production tubing installation is complete, and After production tubing is installed, it will take between 1 week and 10 days to finish installing and testing the flowlines from the wells to the production facility. Please keep in mind that this estimate is approximate and we will revise it if any of our assumptions change.		1	SI
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