BEFORE THE OIL AND GAS CONSERVATION COMMISSION
OF THE STATE OF COLORADO
IN THE MATTER OF ALLEGED VIOLATIONS OF THE ) CAUSE NO. 1V
RULES AND REGULATIONS OF THE COLORADO OIL )
AND GAS CONSERVATION COMMISSION BY ) ORDER NO. 1V-317
COLORADO INTERSTATE GAS COMPANY, )
MORGAN COUNTY, COLORADO )
ADMINISTRATIVE ORDER BY CONSENT
FINDINGS
BACKGROUND OF THE FIELD
1. On September 26, 1958, the Colorado Oil and Gas Conservation Commission (“the Commission” or “COGCC”) issued Order No. 49-4 which approved pressure maintenance operations pursuant to a unit agreement for the Fort Morgan Field (“Field”). The operations involved injecting and recycling gas into and from the “D” Sand reservoir to enhance oil recovery.
2. In 1961, Colorado Interstate Gas Company (“CIG”), through its subsidiary, Natural Gas Producers, Inc. (“NGPI”), acquired the Field as a potential gas storage facility.
3. On June 26, 1962, the Commission issued Order No. 49-6, which approved a revised plan of operations, including the drilling of additional injection/withdrawal wells.
4. In 1966, NGPI and CIG merged, and the Federal Power Commission granted CIG authority to operate the Field as a gas storage facility.
5. The Field is located in Morgan County, Colorado, and occupies 3,220 acres. The storage formation is at approximately 5,500 feet below ground surface (“fbgs”). The maximum storage capacity is 14.8 billion cubic feet of gas at a storage pressure of 2,000 pounds per square inch (“psi”). The gathering pipeline has a “maximum allowable operating pressure” of 2,160 psi guage. Currently, the Field has 34 wells, comprised of:
a. 26 injection/withdrawal wells;
b. 6 observation wells; and
c. 2 salt water disposal (Underground Injection Control) wells.
6. In July 1972, CIG drilled the Fort Morgan Unit Well #26 (“Well #26,” API #05-087-07228), located in the SWĽ NEĽ of Section 25, Township 3 North, Range 58 West, 6th P.M. Surface casing was set at a depth of 215 fbgs. A wellhead was installed on Well #26 on or about August 23, 1972 and replaced during 2001. A release of gas from this well (“the incident”) occurred on October 22, 2006 and is the subject of this AOC.
INTEGRITY MANAGEMENT OF THE FIELD
7. The wells and pipeline network within the Field are protected from corrosion by the use of a cathodic protection system. In addition, the wells in the Field are periodically inspected for integrity by the use of downhole instruments. In mid-2001, Micro-Vert casing inspection tools were run in wells in the Field, including Well #26. The tool detects internal and external metal loss in well casing strings. At the same time, Well #26 was inspected using a gamma ray/neutron inspection tool to detect any presence of gas behind the casing. No issues were detected in Well #26, and based on the results of the study, the next round of casing inspections was scheduled for 2007.
8. Fort Morgan Unit Well #12 (“Well #12,” API #05-087-05909), located in SEĽ SEĽ of Section 25, Township 3 North, Range 58 West, 6th P.M., is the “key” observation well in the Field. On a weekly basis, the casing pressure in Well #12 is measured and compared to the gas inventory stored in the Field. On a monthly basis, casing pressure in all the observation wells is measured and reviewed for anomalous behavior. Twice a year, the Field is shut down for one week, allowed to stabilize, and pressure readings are taken for all wells in the Field. All pressure data (production and surface casing) are reviewed for anomalous behavior that could be indicative of leaking wells. The production casing pressure data is converted into a contoured pressure map of the reservoir. On an annual basis, this data and analysis (for the previous fall and spring inspections) are incorporated into a report that is critically reviewed by a third party consultant, currently Robert C. MacDonald, P.E., of the firm Platt, Sparks and Associates, Consulting Petroleum Engineers, Inc.
BRADENHEAD PRESSURE READINGS FOR WELL #26
9. In November 2003, Well #26 demonstrated a relatively high bradenhead pressure reading (in the annulus between the production casing and surface casing) of approximately 210 psi. The field was at full capacity heading into the start of the withdrawal season. Two subsequent semi-annual readings were approximately 90-100 psi.
10. In March 2005, Well #26 again demonstrated a relatively high bradenhead pressure reading of approximately 160 psi. The Field was depleted at the end of the withdrawal season. A subsequent semi-annual reading was approximately 100 psi.
11. On April 10, 2006, the semi-annual spring testing showed a bradenhead pressure for Well #26 of 129 psi.
12. On September 22, 2006, the Field was shut-in to conduct the regular semi-annual assessment of well integrity and verification of gas storage inventories.
13. On September 25, 2006, the bradenhead pressure for Well #26 was measured at 240 psi. According to COGCC staff, this bradenhead pressure reading should have been investigated not only because it exceeded the estimated fracture pressure of 215 psi at the casing shoe (1 psi per foot) but also because it exceeded any previous bradenhead pressure reading on the well. CIG and its third-party consultant were reviewing these data, along with other Field pressure readings and performance information, while the Field was in stand-by status and during the occurrence of the incident.
CHRONOLOGY OF THE INCIDENT
14. On October 9, 2006, CIG personnel changed out the meter chart on Well #26. According to CIG, there was no gas flowing into or out of the well at this time, and the chart appeared normal in all respects. Later that morning, the chart recorder on Well #26 (analyzed after the incident on October 22, 2006) indicated that the well had suddenly gone on injection, rather than being stabilized. However, the chart was in an enclosed meter house and was not readily visible.
15. On October 11, 2006, CIG personnel tested the meter for Well #26. The measurement technician failed to recognize the implication of the chart readings indicating that Well #26 was on injection, despite the Field being shut-in at the time.
16. On October 14, 2006, a landowner in the Field reported that water was emerging from two cathodic protection wells, #18 and #26, in the vicinity of his house. CIG personnel were dispatched to contain the water.
17. On October 17, 2006, CIG personnel changed out the meter chart on Well #26 again. The technician heard gas movement through the piping but thought that the sound was the result of a malfunctioning separator valve. He manually tripped the valve several times and thought that the problem had been resolved. Later that day, the technician reviewed the charts but did not recognize the implication of the chart line showing that the well was on injection.
18. On Sunday, October 22, 2006, at approximately 12:30 p.m., the landowner in the vicinity of the discharging cathodic protection wells reported that significant quantities of gas and water were escaping from the ground. CIG quickly identified Well #26 as the leaking well by chart inspection and because the well showed an abnormally high bradenhead pressure of approximately 580 psi. Well #26 was isolated from the Field’s surface piping at 2:50 p.m. A bridge plug was set in the well at approximately 7:00 p.m., effectively stopping the leak.
19. On October 22, 2006, CIG personnel telephoned David Dillon, COGCC Engineering Manager, with notification of a casing leak on Well #26 that resulted in the evacuation of nearby residents. It was also reported that some gas and water were escaping from the ground. CIG reported that it shut off the gas flow the same day by setting a bridge plug in Well #26. CIG subsequently reported that it measured a bradenhead pressure of 580 psi on Well #26 on October 22, 2006, a pressure that significantly exceeded the estimated fracture pressure of 215 psi at the casing shoe.
POST-INCIDENT RESPONSE
20. On October 22, 2006, CIG evacuated the occupants of 13 nearby residences, and provided them with temporary housing and twice-daily briefings. On October 28, 2006, the residents were allowed to return, except with respect to the two homes closest to the gas processing facility (H100 and H101). Residence H100 is located at the intersection of County Road N and County Road 18, approximately 1,000 feet east of the gas processing facility. Residence H101 is located on County Road 18, approximately 1,000 feet south of H100 and approximately 1,700 feet southeast of the gas processing facility. These two residences are near some of the surface expressions of the gas release. CIG subsequently settled damage claims with these affected landowners.
21. On October 24, 2006, URS Corporation (“URS”), which had been contracted by CIG, contacted the COGCC environmental staff to discuss COGCC requirements for monitoring and remediating the gas leak. COGCC staff advised URS that testing of nearby water wells and ground water monitoring would be required, including analyses for benzene, toluene, ethylbenzene and xylenes (“BTEX”) and dissolved methane. URS did not discuss the details of the casing leak on Well #26 or the related gas release.
22. On October 25, 2006, CIG lowered a video camera down the casing of Well #26 and followed up with a side-scan video inspection on November 11, 2006. The video inspections revealed a crack in the Well #26 production casing at 846.4 fbgs.
23. On October 25, 2006, CIG representatives and COGCC staff discussed by telephone the status of abatement and corrective action as related to the gas release from Well #26. CIG, in conjunction with its consultants, identified all water wells within a three-mile radius of Well #26. Initially, CIG established a three-tiered approach to evaluate potential impacts to air in residences and to domestic water wells. The first priority included those residences within a one-mile radius of Well #26 that had a domestic well as the only source of water. The second priority included those residences within a one-mile radius of Well #26 that had both a domestic water well and water supplied by the Morgan Quality Water Company. The third priority included residences outside the one-mile and within the three-mile radius of Well #26. Continuous air monitoring instruments were placed in selected homes and made available to those residents that requested a monitor. COGCC staff directed CIG to provide daily reports to the COGCC via e-mail until further notice.
24. On October 27, 2006, COGCC Field Inspector Kevin Lively visited the site after receiving several phone calls from nearby residents. He observed surface-impacted areas that included craters and fissures, caused by the escape of gas, and sinkholes caused by the collapse of the ground surface into voids created by the expulsion of shallow sediments and associated ground water. These surface-impacted areas were located on private property approximately one-half to three-quarters of a mile to the south and southeast of Well #26 and along County Road 18 between Residences H100 and H101. A subsequent inspection approximately one mile to the southwest of Well #26 revealed another area of similar surface impacts. CIG’s reports to the COGCC on October 22 and October 25, 2006 had not indicated the significant impacts to the surface.
25. On October 31, 2006, COGCC and CIG staff conducted a joint inspection of the area. CIG presented the results of an aerial infrared survey it conducted on approximately 16 square miles surrounding Well #26 immediately following the gas release in an attempt to delineate the impacts. An inspection of the surface-impacted areas was also conducted and included CIG’s demonstration of the handheld Remote Methane Detector (“RMD”). The RMD was used to measure methane concentrations at the surface of the impacted areas while maintaining a safe distance. CIG’s October 25, 2006 video inspection of the wellbore of Well #26 was also reviewed.
26. On November 3, 2006, a meeting was held at COGCC offices with CIG personnel. Agenda items included regulatory authority (Federal Energy Regulatory Commission, COGCC) for the Field, an overview of CIG gas storage operations, corrective action related to the incident, and water well testing results. In addition, CIG provided an estimate that the amount of gas released was in the range of approximately 650 to 700 million cubic feet (MMcf). CIG later revised this estimate to 450-700 MMcf.
27. On November 7, 2006, CIG submitted a Spill/Release Report (Form 19) and a Site Investigation and Remediation Workplan (Form 27) as required by the COGCC. This was supplemented by a draft Environmental and Engineering Assessment Workplan (the “Workplan”), submitted on November 17, 2006.
28. On November 8, 2006, COGCC staff attended a public meeting conducted by CIG in Fort Morgan. Approximately 75 citizens were in attendance. The purpose of the meeting was to inform residents about the status of the gas release incident and results of the investigation and abatement efforts. In response to citizen concerns, COGCC staff requested that CIG perform organic and inorganic analyses on selected water wells and conduct soil sampling in and around the surface-impacted areas. On December 5, 2006, CIG submitted an addendum to the Workplan that incorporated this supplemental work request.
29. On November 20, 2006 a follow-up meeting between COGCC and CIG was conducted to discuss status of and ongoing corrective action related to the incident.
30. On December 8, 2006, CIG made a formal request to discontinue the extended volatile organic compound analyses via EPA Method 8260. This request was granted by COGCC staff on December 11, 2006 via e-mail with the condition that BTEX compounds continue to be analyzed. CIG concurred with this condition via email the same day.
31. On December 11, 2006, COGCC environmental staff approved the Workplan and addendum. Phase I of the Workplan included indoor air-monitoring of surrounding homes, methane monitoring of disturbed surface areas, sampling of domestic water wells within a two-mile radius of Well #26, sampling of selected water wells outside the two-mile radius, and soil sampling within and proximal to the disturbed surface areas. Phase II included land surface monitoring for subsidence or swelling, subsurface evaluation of the area using a cone penetrometer (“CPT”) rig, installation of piezometers for ground water sampling, monitoring of domestic and irrigation wells, evaluation of the gas release and migration pathways, down-hole logging of Field wells, and long-term ground water monitoring.
32. On December 18, 2006, COGCC staff issued Notice of Alleged Violation (“NOAV”) #1175591 to CIG for Well #26, citing violations of the following rules:
a. Rule 209., failure to exercise due care in the protection of water-bearing formations;
b. Rule 317.d., failure to plan and maintain a casing program to prevent the migration of oil, gas or water from one horizon to another, that may result in the degradation of ground water;
c. Rule 324A.a., failure to take precautions to prevent significant adverse environmental impacts to air, water, soil, or biological resources to the extent necessary to protect public health, safety and welfare and to prevent the unauthorized discharge of oil, gas, or exploration and production (“E&P”) waste;
d. Rule 324A.c., performing an act which constitutes a violation of any comprehensive plan adopted by the Air Quality Control Commission for the prevention, control and abatement of pollution of the air of the state;
e. Rule 324A.d., failure to demonstrate that injection activities would not result in a violation of any primary drinking water regulation or otherwise adversely affect the health of persons;
f. Rule 326.d., failure to maintain mechanical integrity;
g. Rule 327., failure to take reasonable precautions to prevent oil, gas or water from blowing uncontrolled;
h. Rule 404., failure to complete the well with safe and adequate casing or tubing so as to prevent leakage, and be so set or cemented that damage would not be caused to a fresh water resource;
i. Rule 906.a., failure to control and contain a spill/release of E&P waste immediately upon discovery; and
j. Rule 907.a., failure to ensure that E&P waste is properly stored, handled, transported, treated, recycled or disposed to prevent threatened or actual significant adverse environmental impacts to air, water, soil or biological resources or to the extent necessary to ensure compliance with the allowable concentrations and levels in Table 910-1, with consideration to WQCC ground water standards and classifications.
33. Corrective action in the NOAV required CIG, among other things, to provide the COGCC with the data to be acquired pursuant to the Workplan and addendum and to provide a draft Operating Plan outlining the operational practices and regulatory oversight of the Field by January 31, 2007.
34. On January 22, 2007, a two-week extension to the NOAV corrective action deadline was requested by CIG and granted by COGCC staff.
35. On January 23, 2007, a meeting was held between COGCC staff and CIG personnel at the CIG offices in Colorado Springs to review all of CIG’s gas storage operations in Colorado. The final Workplan, dated January 22, 2007, was submitted to the COGCC at the meeting.
36. On January 31, 2007, a high resolution Vertilog scan was conducted on Well #26 that did not detect the previously identified crack in the casing because it was masked by its proximity to the collar connecting two pipe segments.
37. On February 6, 2007, the COGCC received the corrective action data and draft Operating Plan as required in the NOAV.
38. Preliminary analytical results and progress reports were provided to the COGCC on a daily basis during periods of field activity. On or about February 14, 2007, CIG submitted the Workplan Phase I sampling report, dated February 12, 2007. Highlights of this report include:
a. Continuous air monitoring was initially conducted at eight residences within one mile of Well #26.
b. Methane screening was conducted at water wells prior to and during sampling. A total of 71 water wells were sampled and analyzed for dissolved methane and other water quality parameters. Typically, biogenic gas contains mostly methane with some ethane. The presence of heavier gases, such as propane, butane, pentane and hexane, is characteristic of thermogenic gas. Trace concentrations of gases other than methane, ethane and ethene were detected in 15 water wells. Additionally, trace concentrations of toluene and ethylbenzene were detected in 4 water wells.
c. A total of 132 soil samples were collected in and around the surface-impacted areas and submitted for specified analyses. Laboratory analysis of the soil samples indicated no petroleum hydrocarbon impacts to surface soils. Accordingly, COGCC staff approved the backfilling and reclamation of the disturbed areas.
39. On February 16, 2007, a follow-up meeting was held between COGCC staff and CIG personnel to discuss results of Phase I and status of Phase II of the Workplan.
40. On March 15, 2007, CIG submitted to the COGCC a Phase II Groundwater Sampling and Analysis Plan addendum to the Workplan, which included a summary of piezometer completion details. The addendum did not include BTEX analyses of the CPT samples. COGCC staff did not formally approve the addendum to the Workplan.
41. On May 4, 2007, CIG submitted to the COGCC the Phase I Well Water and Air Sampling Report Addendum dated May 2, 2007. This report described additional activities and data, including ground water sampling results for residences H100 and H101.
a. The sampling of the water wells at these two residences was delayed because of elevated methane readings with the RMD and related safety concerns.
b. According to this report, methane was detected at concentrations of 19 mg/l and 26 mg/l on February 20 and March 23, 2007, respectively, in samples collected from the water well associated with the H100 residence.
c. Methane concentrations in all other water wells sampled were below 2 mg/l.
d. Laboratory results from the water well sample collected from residence H100 on February 20, 2007 indicated a benzene concentration of 2.0 micrograms per liter (µg/l). The Colorado Basic Standards for Ground Water for benzene is 5.0 µg/l. Colorado Water Quality Control Commission (“WQCC”), Regulation 41, 5 CCR 1002-41; see also, COGCC Table 910-1 (which is based on WQCC standards for benzene).
e. Ninety-one CPT locations were drilled and completed with piezometers. Dissolved methane concentrations in water samples collected from 16 piezometers were greater than 2 mg/l and ranged from 2.5 mg/l to 18.0 mg/l.
42. On May 15, 2007, COGCC environmental staff collected gas and water samples for laboratory analyses. Benzene and methane were detected in water samples from residence H100 at concentrations of 2.7 µg/l and 9.9 mg/l, respectively. Residence H100 remains unoccupied. Toluene, ethylbenzene, and xylene compounds were not detected. A trace concentration of dissolved methane was detected in water samples collected from residence H101; no BTEX compounds were detected. Residence H101 also remains unoccupied.
43. On May 22, 2007, COGCC staff met with CIG and URS staff to review the results of Phase II Workplan activities and scheduling of future activities. CIG was instructed subsequently to analyze for BTEX compounds when dissolved methane concentrations exceeded 2 mg/l.
44. On June 21, 2007, a meeting was held between COGCC staff and CIG, including its outside counsel, to review the incident and discuss possible causes.
45. On June 21, 2007, URS collected samples from residence H100. Laboratory results indicated a benzene concentration of 3.0 µg/l. Toluene, ethylbenzene and xylene compounds were not detected. Dissolved methane was detected at a concentration of 19 mg/l.
46. On June 22, 2007, URS collected samples from CPT piezometer #41D. Laboratory results indicated a benzene concentration of 6.0 µg/l which exceeded WQCC groundwater standard for benzene of 5.0 µg/l. Toluene, ethylbenzene and xylene compounds were not detected. Dissolved methane was detected at a concentration of 15 mg/l.
47. On August 31, 2007, COGCC staff issued a Notice of Alleged Violation (“NOAV”) #1175635 to CIG for Well #26, citing a violation of Rule 324A.b., for conducting oil and gas operations which constituted a violation of the water quality standard for benzene established by the WQCC for waters of the state.
DIFFERENCES OF OPINION
48. On July 25, 2007, a meeting was held between COGCC staff and CIG, including CIG’s reservoir integrity consultant, Mr. MacDonald (see §8, supra). At this meeting, Mr. MacDonald stated that it was his professional opinion that the gas release was sudden and accidental and commenced on October 9, 2006. COGCC staff’s opinion is that the gas release may have occurred slowly prior to the sudden release on October 9, 2006, as evidenced by two consecutive high bradenhead pressure readings on April 10, 2006 and September 25, 2006. The bradenhead pressure reading on September 25, 2006 exceeded the estimated fracture pressure of 215 psi at the casing shoe (which means the pressure within the annulus between the production casing and the surface casing could theoretically fracture the rock formation at the surface casing shoe). In addition, the reading on September 25, 2006, while the Field was in stand-by status and supposedly stabilized, exceeded any previous bradenhead pressure reading on Well #26. COGCC staff’s opinion is that the high bradenhead pressure reading on a well in that condition could result in gas leaks to the surrounding formation.
49. COGCC’s staff believes that additional investigation should have been conducted pursuant to the two consecutive high readings in April and September 2006. COGCC staff also believes that, at a minimum, CIG should adopt the practice of conducting a “blow down” test on any well that displays a bradenhead pressure that approaches or exceeds the estimated fracture pressure at the casing shoe and that a rapid buildup of pressure in the surface casing after the well is blown-down should lead to shutting in the well for further investigation. CIG and its consultant, Mr. MacDonald, believe that the anomalous surface casing (bradenhead) pressure readings on Well #26 are not related to the sudden failure of the casing.
50. CIG and its consultant, Mr. McDonald, believe that CIG had a comprehensive reservoir integrity program in place to detect anomalies in the Field that would be potentially indicative of leaking wells. According to CIG, it does not appear that this sudden failure was detectable or preventable by CIG. There was no indication from previous casing inspections (including Vertilog and gamma ray/neutron tools) that would have alerted CIG to integrity issues with Well #26 and because CIG interpreted high bradenhead pressures in Well #26 as part of the normal behavior of the Field.
51. COGCC acknowledges that CIG has a comprehensive reservoir integrity program but believes CIG lacks a comprehensive program that anticipates issues related to daily wellbore operation. CIG personnel missed several opportunities to detect the release of gas in a timely fashion, which would have allowed CIG to take control measures to reduce the magnitude of the incident. These failures may be attributable to training deficiencies with respect to Field personnel, or to the failure to equip the Field with appropriate pressure monitors or gas leak detection equipment. CIG’s in-house procedures with respect to gas meter chart editing and integration were also deficient.
CONCLUSION
52. CIG is the “responsible party” within the meaning of C.R.S. §34-60-124(8) for an unauthorized release of gas that caused a significant adverse environmental impact to air, water, soil or biological resources. The incident involved a significant risk to public safety. The incident involved a significant waste of gas resources. The incident resulted in significant loss or damage to public or private property. Accordingly, the maximum penalty of $10,000 provided in C.R.S. §34-60-121(1), does not apply in this matter.
RULE VIOLATIONS
53. Based on the above findings, COGCC staff recommends that CIG be found in violation of the following provisions of the Oil and Gas Conservation Act and COGCC Rules and Regulations with respect to the incident:
a. Rule 209., for failure to exercise due care to protect water-bearing formations;
b. Rule 317.d., for failure to plan and maintain a casing program to prevent the migration of oil, gas or water from one horizon to another, that may result in the degradation of ground water;
c. Rule 324A.a., for failure to take precautions to prevent significant adverse environmental impacts to air, water, soil, or biological resources to the extent necessary to protect public health, safety and welfare and to prevent the unauthorized discharge of oil, gas, or E&P waste;
d. Rule 324A.b., for conducting oil and gas operations which constituted a violation of water quality standards established by the WQCC for waters of the state;
e. Rule 326.d., for failure to maintain mechanical integrity;
f. Rule 327., for failure to take reasonable precautions to prevent oil, gas or water from blowing uncontrolled;
g. Rule 906.a., for failure to control and contain a spill/release of E&P waste immediately upon discovery (which, according to COGCC staff, includes the point in time at which the release could have been discovered by reasonable diligence); and
h. C.R.S. §34-60-107 which prohibits the waste of oil and gas.
RECOMMENDED FINE AND ACTIONS
54. Rule 523.a. and c. specify a base fine of One Thousand dollars ($1,000) for each day of violation of each of the Rules cited above. C.R.S. §34-60-121(1) specifies that a violation of a provision of the statute may be subject to a fine of up to One thousand dollars ($1,000) for each day of violation. The parties disagree on the calculation of the number of days of each violation but have agreed to a fine of Four Hundred Sixteen Thousand dollars ($416,000).
55. The parties further agree that the fine includes adjustment for the following aggravating factors (because of the significant loss of gas, the distance the gas release traveled from Well #26, the proximity of surface impacts to the manned gas processing facility and residences, the required long-term evacuation of two houses, and the areal extent of the required subsurface mitigation) and results in no more than $1,000 per violation per day:
a. The violations caused, or threatened to cause, a significant adverse environmental impact to air, water, soil or biological resources or on public health, safety and welfare;
b. The violations resulted in significant waste of oil and gas resources; and,
c. The violations resulted in significant loss or damage to public or private property.
56. Rule 523.a.(2) specifies that fines may be adjusted downward by mitigating factors pursuant to Rule 523.d. COGCC staff recommends reducing the fine by Forty Two Thousand dollars ($42,000) ($2,000 x 3 mitigating factors x 7 violations (excluding Rule 324A.b.)) because of the following mitigating factors:
a. CIG self-reported the incident and took prompt, effective and prudent response measures, including assistance to impacted parties;
b. CIG cooperated with the COGCC with respect to the incident;
c. The cost of responding to the incident eliminated any economic benefit to CIG for failure to take adequate precautions.
57. Applying the mitigating adjustment factors to the fine results in a total recommended fine of Three Hundred Seventy-Four Thousand dollars ($374,000).
58. COGCC staff recommends that this Order require CIG to conduct Field activities in accordance with the Operating Plan received by the COGCC on February 6, 2007. The Operating Plan should be amended to require three-times weekly (with at least a day between) readings of shut-in surface casing (bradenhead) pressure. To the extent that such pressure exceeds a gradient of 0.25psi/foot at the casing shoe, the well shall be shut-in for a blow-down test to be conducted within 24 hours, and the results promptly reported to the COGCC. Blow-down tests shall be conducted on all wells in the Field during the semi-annual reservoir survey, and the COGCC shall be notified 48 hours in advance so that it may send an inspector to monitor such tests. The Operating Plan shall be subject to further amendment from time to time, with COGCC approval, including to conform it to any rule or regulation that the Commission may adopt with respect to gas storage operations generally.
59. CIG should assess the feasibility of equipping the Field with remote monitoring (e.g., surface casing pressure, gas leak detection) and report its conclusions to the COGCC on or before July 1, 2008.
60. CIG should continue to conduct further site investigation, monitoring activities, and other remedial requirements as necessary to comply with the approved Workplan and any addenda as may be approved by the COGCC staff.
ORDER
NOW, THEREFORE IT IS ORDERED, that Colorado Interstate Gas Company shall be found in violation of Rules 209., 317.d., 324A.a., 324A.b., 326.d., 327., 906.a., and C.R.S. §34-60-107 at Well #26, as explained below:
a. Rule 209., for failure to exercise due care to protect water-bearing formations;
b. Rule 317.d., for failure to plan and maintain a casing program to prevent the migration of oil, gas or water from one horizon to another, that may result in the degradation of ground water;
c. Rule 324A.a., for failure to take precautions to prevent significant adverse environmental impacts to air, water, soil, or biological resources to the extent necessary to protect public health, safety and welfare and to prevent the unauthorized discharge of oil, gas, or E&P waste;
d. Rule 324A.b. for conducting oil and gas operations which constituted a violation of water quality standards established by the Water Quality Control Commission for waters of the state;
e. Rule 326.d., for failure to maintain mechanical integrity;
f. Rule 327., for failure to take reasonable precautions to prevent oil, gas or water from blowing uncontrolled;
g. Rule 906.a., for failure to control and contain a spill/release of E&P waste immediately upon discovery; and
h. C.R.S. §34-60-107, for failure to prohibit waste of oil or gas.
IT IS FURTHER ORDERED, that Colorado Interstate Gas Company shall be assessed a total fine of Three Hundred Seventy-Four Thousand dollars ($374,000.00) for the eight violations, which shall be payable within 30 days of the date this order is approved by the Commission.
IT IS FURTHER ORDERED, that Colorado Interstate Gas Company shall continue to implement the approved Environmental and Engineering Assessment Workplan and Sampling Plan, as amended, and report the results to the COGCC in a timely manner.
IT IS FURTHER ORDERED, that Colorado Interstate Gas Company shall carry out the provisions of the Operating Plan, as approved by the COGCC staff, in a timely manner.
IT IS FURTHER ORDERED, that Colorado Interstate Gas Company shall carry out the Operating Plan, as amended, to require three-times weekly (with at least a day between) readings of shut-in surface casing (bradenhead) pressure of all wells in the Field. To the extent that such pressure exceeds a gradient of 0.25psi/foot at the casing shoe for any well, the well shall be shut-in for a blow-down test to be conducted within 24 hours, and the results promptly reported to the COGCC. In addition, blow-down tests shall be conducted on all wells in the Field during the semi-annual reservoir survey, and the COGCC shall be notified 48 hours in advance so that it may send an inspector to monitor such tests. The Operating Plan shall be subject to further amendment from time to time, with COGCC approval, including to conform it to any rule or regulation that the Commission may adopt with respect to gas storage operations generally.
IT IS FURTHER ORDERED, that Colorado Interstate Gas Company shall assess the feasibility of equipping the Field with remote monitoring (e.g., surface casing pressure, gas leak detection) and report its conclusions to the COGCC on or before July 1, 2008.
IT IS FURTHER ORDERED, that Colorado Interstate Gas Company shall continue to conduct further site investigation, monitoring activities, and other remedial requirements as necessary to comply with the approved Workplan and any addenda or supplemental workplans as have been or may be approved by the COGCC staff.
IT IS FURTHERED ORDERED, that pursuant to Rule 522.b.(3), this Administrative Order by Consent shall not constitute admission of the alleged violations by Colorado Interstate Gas Company.
IT IS FURTHER ORDERED, that under the State Administrative Procedure Act the Commission considers this order to be final agency action for purposes of judicial review within 30 days after the date this order is mailed by the Commission.
IT IS FURTHER ORDERED, that an application for reconsideration by the Commission of this order is not required prior to the filing for judicial review.
IT IS FURTHER ORDERED, that the provisions contained in the above order shall become effective forthwith.
IT IS FURTHER ORDERED, that the Commission expressly reserves its right after notice and hearing, to alter, amend, or repeal any and/or all of the above orders.
RECOMMENDED this ______ day of January, 2008.
OIL AND GAS CONSERVATION COMMISSION
By: ___________________________________
Carol Harmon, Enforcement Officer
Dated at Suite 801
1120 Lincoln Street
Denver, Colorado 80203
January 14, 2008
AGREED TO AND ACCEPTED THIS _________DAY OF _______________, 2008.
COLORADO INTERSTATE GAS COMPANY
By: __________________________________
Authorized Company Representative
_____________________________________
Print Full Name
_____________________________________
Print Title
(0801-GA-02/1V-317)
==============================================================================
This cause came on for hearing before the Commission at 9:00 a.m. on January 15, 2008, Suite 801, The Chancery Building, 1120 Lincoln Street, Denver, Colorado, for the approval of this Administrative Order by Consent.
ENTERED this________day of January, 2008, as of January 15, 2008
OIL AND GAS CONSERVATION COMMISSION
OF THE STATE OF COLORADO
By____________________________________
Patricia C. Beaver, Secretary
Dated at Suite 801
1120 Lincoln Street
Denver, Colorado 80203
January 24, 2008