In the matters of:
Conservation Order No. 360
A hearing to review the plan of development )
and operation and other agreements as they )
affect Natural Gas Liquid (NGL) throughput, ) Prudhoe Bay Oil Field
Miscible Injectant (MI) utilization and ultimate ) Prudhoe Oil Pool
recovery from Prudhoe Bay; )
The Petition of ARCO Alaska, Inc., for a )
ruling on maximization of NGL blending; and )
The Petition of BP Exploration (Alaska) Inc. )
requesting action or an order after the Com- )
mission's review of the plan of development )
and operation and other agreements as they )
affect NGL throughput, MI utilization and )
ultimate recovery from Prudhoe Bay. )
August 9, 1995 (Revised November 3, 1995)
IT APPEARING THAT:
1. The Alaska Oil and Gas Conservation Commission ("Commission"), in December 1994, was informed that Alyeska Pipeline Service Company ("Alyeska") was considering changing the operating parameters of the Trans-Alaska Pipeline System ("TAPS").
2. In response to the Commission's inquiry dated December 22, 1994, the operators of the Prudhoe Oil Pool ("POP"), ARCO Alaska, Inc. ("ARCO") and BP Exploration (Alaska) Inc. ("BPXA"), on December 29, 1994, expressed divergent views concerning ultimate recovery from the POP.
3. The Commission, on its own motion on January 23, 1995, scheduled a public hearing to review the plan of development and operation and other agreements as they affect natural gas liquid (NGL) throughput, miscible injectant (MI) utilization and ultimate recovery from Prudhoe Bay.
4. ARCO submitted a petition dated February 14, 1995, requesting a ruling on maximization of NGL blending.
5. BPXA submitted a petition dated April 11, 1995, requesting action on an order after the Commission's review of the plan of development and operation and other agreements as they affect NGL throughput, MI utilization and ultimate recovery from Prudhoe Bay.
6. Notice of pre-hearing conference was published March 30, 1995 in the Anchorage Daily News and a notice of date change for the pre-hearing conference was published April 5, 1995.
7. A pre-hearing conference was held on April 19, 1995 at the offices of the Commission, 3001 Porcupine Drive, Anchorage, Alaska. In an order following the conference, the Commission determined that evidence pertaining to ARCO's or BPXA's petition would be heard commencing May 16, 1995 and that, at the conclusion of the portion of the hearing concerning ARCO's and BPXA's petitions, the Commission intended to continue the hearing to a later date, tentatively June 21, 1995, to further review the plan of development and operation and other agreements as they affect NGL throughput, MI utilization and ultimate recovery from Prudhoe Bay. The order further stated that the Commission would consider making an interim ruling on ARCO's and BPXA's petitions at the conclusion of the portion of the hearing concerning those petitions.
8. Notice of public hearing was published in the Alaska Star on February 1, March 1, March 10, April 5, April 22 and May 3, 1995. Notice of public hearing was published in the Anchorage Daily News April 5 and April 19, 1995. Additional notice of public hearing regarding rebuttal testimony was published in the Anchorage Daily News on June 9, 1995.
9. Pre-filed testimony was received May 12, 1995. Pre-filed rebuttal testimony was received on June 12, 1995.
10. A public hearing was held on May 16, 17, 18, 22, 23, 24, 25, 26 and 31 and June 1, 20, and 21, 1995.
11. Participants in the hearing were ARCO, BPXA, Phillips Petroleum Company ("Phillips"), Exxon Company U.S.A. ("Exxon"), Yukon Pacific Corporation ("Yukon Pacific"), Shell Land and Energy Company ("Shell"), Mobil Oil Company ("Mobil"), Texaco Exploration and Production Company ("TEPI"), Chevron USA Production Company ("Chevron"), Amerada Hess Corporation ("Amerada Hess"), Marathon Oil Company ("Marathon"), the Alaska Department of Natural Resources ("ADNR"), and the Alaska Department of Revenue.
12. Post-hearing briefs were received June 30, 1995.
BACKGROUND AND HISTORY
1. The Commission issued Conservation Order 290, which approved fieldwide expansion of the Prudhoe Bay Miscible Gas Project ("PBMGP") in 1991. The PBMGP is an enhanced oil recovery ("EOR") project designed to substantially increase the ultimate recovery of oil from the POP. The PBMGP utilizes MI manufactured from separator off gas for recovering additional oil. ARCO and BPXA in the 1991 PBMGP hearings testified to the Commission that no trade-off would exist between manufacture of maximum blendable NGLs and sufficient volume of MI for planned EOR.
2. The Central Gas Facility ("CGF") is designed to yield three products from separator off-gas: residue or lean gas, NGLs and MI.
3. C.O. 290 did not establish a required volume of MI for EOR, although it did find that PBMGP expansion would require modifying the CGF at Prudhoe Bay to handle up to 7.5 bscfpd of gas and upgrading the MI distribution system to handle 700 mmscfpd of MI.
4. The Commission granted original certification of the PBMGP with Conservation Order 195 in 1984. At that time, the working interest owners ("WIOs") envisioned injecting MI in approximately 50 patterns. By the time the project started in 1987, expectations of scope increased to 100 patterns. In 1987 almost 50 patterns were on-line. In the 1991 PBMGP hearing, unit expectations were between 130 and 160 patterns. In 1991, the unit had approximately 70 patterns on-line. In May, 1995, 112 patterns were on-line and unit approval granted for almost 150 patterns. The 1994 Field Development Plan envisions approximately 225 patterns.
5. The Commission first approved MI for EOR for the Flow Station 3 Injection Project with Conservation Order 187 in 1982.
6. The GHX-1 project increased field gas off-take from 3.7 bscfpd to 5.3 bscfpd. The project was fully implemented in 1992. The GHX-2 project, completed September 1994, increased field gas off-take from 5.3 bscfpd to 7.5 bscfpd.
7. The current configuration of the CGF does not allow production of maximum blendable NGLs for transportation down the TAPS and manufacture of a nominal 640-700 mmscfpd of MI for EOR. The current MI capacity at the CGF with blending NGLs at 74,000 bpd is 520 mmscfpd.
8. The maximum blendable NGL volume is a function of vapor pressure limitations in TAPS. In February 1995, Alyeska implemented new vapor pressure control criteria which made it possible to increase NGL shipment through TAPS an additional 10 mbpd to 20 mbpd, raising NGL production volume from the POP to between 84 mbpd and 94 mbpd.
9. The TAPS tariff vapor pressure limit has been 14.7 psi for all relevant years. Safety concerns have apparently influenced Alyeska not to allow blending of POP NGLs to the TAPS tariff vapor pressure limit.
10. Before February 1995, Alyeska established volume limits for NGLs blended with POP separator liquid production ("SLP") in addition to vapor pressure control limits. The ceilings were 55 mbpd from December, 1986, to January, 1991; 58 mbpd and 60 mbpd in January, 1991; 61 mbpd in February, 1991; 62 mbpd from March, 1991 until May, 1992; 67 mbpd from May, 1992, until December, 1992; and 74 mbpd from December, 1992, until February, 1995. Effective in February, 1995, Alyeska removed all ceilings other than one dependent on a vapor pressure control limit of 14.2 psi.
11. A unit technical team was convened in January, 1995, to address disagreements between ARCO and BPXA concerning ultimate recovery. The technical team met until the third week in April, 1995, attempting to reach a technical consensus. They were not successful.
12. On February 9, 1995, ARCO, as operator of the CGF, increased the production of NGLs to meet Alyeska's new vapor pressure control limit.
13. Skid 50 is the facility where POP SLP and NGLs are blended for delivery to TAPS. On February 9, 1995, BPXA, as operator of Skid 50, restricted blending of NGLs to prevent production of an additional 10 mbpd to 20 mbpd of NGLs. ARCO attempted to blend additional NGLs through Flow Station 3, but BPXA further reduced Skid 50 blending to offset ARCO's efforts.
14. ARCO has asked the Commission to rule that the best conservation practice concerning NGLs and MI is to blend and ship the maximum volume of NGLs allowed by TAPS.
15. BPXA has asked the Commission to rule that the best conservation practice concerning NGLs and MI is to produce at least 700 mmscfpd of MI for EOR.
SURFACE FACILITIES AND PROCESSING
16. Flow stations and gathering centers could be operated so as to recover as part of SLP some of the hydrocarbon components that are otherwise recovered as NGLs at the CGF. However, all parties agree operation in this manner would reduce ultimate hydrocarbon recovery from the POP.
17. The maximum capacity of the NGL pipeline leaving the CGF under current conditions is approximately 100,000 barrels per day.
18. BPXA contends the capacity of the CGF as it exists today is 700 mmscfpd of MI. TEPI contends C.O. 290 quantified 700 mmscfpd as the volume of MI needed for EOR in the POP.
19. ARCO does not consider the 700 mmscfpd MI capacity a valid option and argues this option is without technical or economic merit. ARCO asserts the most feasible rate is an annual average of 640 mmscfpd, assuming estimates of 1996 feed gas compositions are accurate and planned upgrades to the CGF are funded and successful.
20. ARCO maintains the distribution system for MI was never upgraded to handle 700 mmscfpd as outlined in the 1991 PBMGP hearings and that the installed system is capable only of handling nominally 600 mmscfpd.
21. ARCO contends that the CGF could achieve a peak rate of 700 mmscfpd of MI if the distribution system were capable of handling 700 mmscfpd of MI, if artificial lift gas were limited to 800 mmscfpd, and if NGL shipments were limited to 67,000 bpd (volume in 1991).
22. BPXA testified that there were two reasons for a decrease in the anticipated MI capacity of 700 mmscfpd: wet gas problems and increases in NGL production.
23. BPXA testified that the design of GHX-2 included capacity to handle 1.28 bscfpd of artificial lift.
24. ARCO stated that while the work of the GHX-2 Conceptual Engineering Task Force was based on artificial lift rates of 1.28 bscfpd, GHX-2 was designed and constructed for 800 mmscfpd. Actual artificial lift rates have been running in the range of 1.1 bscfpd, lowering CGF efficiency. Dehydration upsets at the CGF and elsewhere in the field adversely affect MI production rates by as much as 20 to 35 mmscfpd.
25. BPXA testified that the dehydration system in the field is pushed to absolute capacity. Dehydration problems do not affect field gas off-take volume, but have reduced the volume of gas that can be turned into MI.
26. ARCO testified that 1991 predictions of CGF efficiency were predicated in part on less than 800 mmscfpd of artificial lift. Oil rim owners have increased artificial lift to 1.1 bscfpd, leaving the dehydration system undersized. Oil rim owners decided not to fund GHX-2 scope to add additional dehydration.
27. Testimony from hearing participants suggested operational changes or upgrades to the CGF to produce additional MI: for example, re-wheeling existing MI compressors, adding a third MI compressor, upgrading the CGF refrigeration system, pumping salable NGLs into MI, pumping stabilizer reflux into MI, pumping low temperature separator bottoms into MI, installing a third plant to recover MI components in the residue gas from the CGF, upgrading the dehydration system and optimizing existing equipment.
28. ARCO projected an increase during 1995 of 30 to 58 mmscfpd of MI as a result of facility upgrades and increased experience in operating the CGF.
29. BPXA contends the CGF, with some upgrades, can produce 700 mmscfpd of MI and 70 mbpd of NGLs.
30. ARCO asserts incremental efficiency of the CGF to recover returned MI components can decline from 70 percent to 30 percent with increasing MI production. BPXA concurs, but contends pump-up modifications to the CGF could return recovery to 70 percent. BPXA testified facility upgrades that return incremental recovery from 30 percent to 70 percent clearly prevent waste.
31. CGF production during the first quarter of 1995 was 520 mmscfpd of MI and 74 mbpd of NGLs.
32. Incremental NGLs above 74,000 bpd produced under current conditions at the CGF are predominantly butanes.
33. If the CGF produced 50-55 mbpd of NGL and 700 mmscfpd of MI, the increased NGL/MI production potential of GHX-1 and GHX-2 would go toward producing 250 mmscfpd more MI but no more NGLs than before the expansions.
EOR PROCESS AND RESERVOIR DEVELOPMENT
34. The 1994 Field Development Plan updates unit consensus for operation and development of the POP. It is not legally binding nor may it violate voluntary agreements or applicable regulations, orders or statutes. The plan references MI distribution guidelines designed to allocate MI injection volumes for patterns. Under the guidelines, EOR pattern performance is assessed annually and MI injection rates and targets are revised as needed.
35. All WIOs acknowledge the benefits derived from the PBMGP have exceeded initial projections and agreed that 1 tscf of MI has been injected, and 200 bscf returned MI ("RMI") and 85 mmb of EOR oil have been recovered.
36. Each PBMGP pattern performs best in its initial stage of MI injection.
37. ARCO asserts that up to 10 percent total pore volume ("TPV"), MI efficiency is high, requiring less than 6 mcf of MI per barrel of EOR oil, or .75 barrels of EOR oil for each barrel of NGL converted to MI. For 10-20 percent TPV, efficiency is modest, requiring 13 mcf of MI per barrel of EOR oil or .35 barrels of EOR oil for each barrel of NGL converted to MI. Above 20 percent TPV, MI efficiency is poor, requiring 23 mcf of MI per barrel of EOR oil, or .20 barrels of EOR oil for each barrel of NGL converted to MI.
38. BPXA contends that under increased NGL blending, expected cumulative MI injection by 2015 would be approximately 4 tscf, which is approximately 16 percent TPV based on the scope of the 1994 Field Development Plan.
39. BPXA contends that expanding EOR scope depends on expanding MI supply. BPXA suggested the ultimate scope of miscible flooding at the POP could easily exceed 360 patterns.
40. BPXA contends that 50,000 bpd of oil is attributable to existing patterns on MI in 1995.
41. BPXA asserts that for every barrel of NGL used for MI in the POP, more than 1.3 barrels of combined total liquid production is recovered, consisting of .6 barrels of EOR oil and the equivalent of .7 barrels of NGLs as RMI. ARCO's estimates are different and lower.
42. ARCO contends a constant supply 500 mmscfpd of MI through 2015 would recover 411 mmb of EOR oil; a constant supply of 600 mmscfpd of MI through 2015 would recover 444 mmb of EOR oil; and a constant supply of 700 mmscfpd of MI through 2015 would recover 463 mmb of EOR oil.
43. BPXA contends reduction of MI supply is magnified through time because MI normally cycled through the reservoir is no longer available for reinjection.
44. ARCO contends that the PBMGP project scope and reserves are essentially unchanged from the 1994 Field Development Plan, which is consistent with the 1991 PBMGP hearings. ARCO asserts that current MI supply at the POP is adequate to achieve 20 percent TPV in the PBMGP.
45. ARCO contends there is no risk in maximizing NGL blending because sufficient MI is still available to flood all existing EOR projects identified in the 1994 Field Development Plan. Although ARCO asserts all obvious EOR opportunities have been identified in the 1994 Field Development Plan, it contends that if an attractive EOR project is approved in the future, more MI can be created at that time. ARCO admits several EOR opportunities are under study.
46. ARCO contends the recovery and expansion objectives of the PBMGP, as envisioned in C.O. 290, can be met. Exxon contends the recovery objectives of the PBMGP can be met. BPXA does not agree that PBMGP goals will be realized if NGLs are blended to the maximum.
47. BPXA contends there is insufficient MI supply to fulfill the patterns and pore volumes contemplated in C.O. 290 and that the current MI supply will provide 25 percent TPV for those patterns envisioned during the 1991 PBMGP hearings but not the 200 plus patterns identified in the 1994 Field Development Plan.
48. BPXA asserts there is currently enough MI with 500 mmscfpd to supply 18-19 percent TPV to existing patterns by 2010.
49. BPXA contends that 5 tscf of MI must be injected to achieve approximate 30 percent TPV for 130-160 patterns by 2015. BPXA contends that for approximately 200 patterns identified in the 1994 Field Development Plan, 4.6 tscf of MI will be needed through 2015 and that if blending were allowed to rise to 84 mbpd, only 4 tscf of MI would be injected in those patterns.
50. BPXA asserts there are more attractive patterns for development beyond those identified in the 1994 Field Development Plan.
51. BPXA has expanded its view of EOR opportunities for the POP from that presented to the Commission in 1991. BPXA also asserts that gas sales offer another opportunity to transport NGLs from the POP later in field life.
52. The technical team did not consider the effects of a major gas sale on late-life recovery of NGL components or the effects of pressure maintenance through waterflooding the gas cap (i.e., the PSI project).
53. There was no consensus study done to analyze future recoveries using a single data set and assumptions or common tools. ARCO's and BPXA's EOR predictions are not comparable because they use different critical assumptions, project scope and conversion ratios for transforming NGLs to MI:
ARCO testified that the lean gas chase to recover late life NGLs is an unproven process; BPXA concurs insofar as its specific application in the POP, but elsewhere it has been successfully employed.
BPXA predictions include lean gas chase, ARCO's does not.
ARCO testified that PSI (i.e., water injection into gas cap) is a speculative high risk pressure support process; BPXA disagrees but admits that probably gas cap owners bear a disproportionate share of the risk with PSI. BPXA predictions include PSI, ARCO's does not.
ARCO characterizes Eileen West End as uncertain recovery and high cost; BPXA agrees and both include the project in their predictions. BPXA, however, included a larger scope project in its predictions.
ARCO describes Northwest Eileen as uncertain reservoir quality and high cost; BPXA agrees but is more optimistic. BPXA predictions include Northwest Eileen, ARCO's does not.
ARCO describes the DS 15/18 Romeo project as a very high risk process; BPXA disagrees and uses DS15/18 in its predictions, ARCO does not.
ARCO refers to gravity drainage miscible injection ("GDMI") as speculative high risk; BPXA describes GDMI as not being high risk, but needing additional work. BPXA extended case includes 360 patterns; 55 percent of them are in the GDMI. ARCO does not use GDMI in its predictions.
54. It is unlikely that a one or two year extension in waterflood will result in lost reserves. With each additional year however, due to the potential of corrosion and maturing waterflood, deferred EOR reserves might become lost reserves.
55. ARCO testified that original expansion plans called for MI facilities to be installed at Drill Site 4 and 11 in 1995. ARCO contends current MI supply is sufficient for Drill Site 4 to come on line in 1996 and for Drill Site 11 to come on line in 1997. ARCO issued an AFE for Drill Site 4 in 1994, which was signed by ARCO and BPXA but not Exxon. An AFE for Drill Site 11 was not issued. BPXA contends Exxon disapproved MI expansion to Drill Site 4 solely because of insufficient MI supply. Exxon contends its disapproval was based on economic considerations, not lack of MI supply.
56. ARCO and BPXA are the only participants to run detailed reservoir studies to predict NGL/MI recovery. ADNR testified that it does not have resources on-hand to perform the type of analysis necessary to replicate each petitioner's detailed reservoir studies regarding the MI/NGL allocation issue.
WASTE AND ULTIMATE RECOVERY
57. ARCO asserts maximum NGL blending yields an additional 100 mmb of NGLs, offset by a loss of 15 to 30 mmb of oil.
58. Exxon asserts maximum NGL blending yields an additional NGL recovery of 70 mmb, offset by a 10-15 million barrel reduction in EOR oil.
59. BPXA asserts potential total hydrocarbon recovery can be improved by 150-200 mmb by increasing MI supply capacity to 700 mmscfpd and extending the PBMGP scope.
60. BPXA asserts that the appropriate NGL rate to maximize total hydrocarbon liquid production is lower than the current rate under current operating conditions. BPXA stated that limiting production to 50-55,000 bpd of NGL would avoid waste.
61. BPXA and ARCO disagree on how much MI will remain trapped in the reservoir. BPXA contends about 30 percent of all MI will remain trapped. ARCO's estimates are higher.
62. BPXA testified that if NGL blending is increased to 84 mbpd and MI supply and EOR scope are reduced, liquid hydrocarbon production would decrease by 60-80 mmb.
63. Exxon contends increased blending today will not jeopardize EOR operations in the future because the balance between NGLs and MI can always be shifted with additional knowledge. Exxon testified that the ideal MI supply is the maximum available from unblendable NGLs that can be made economically.
64. ARCO defended maximum blending, suggesting that (1) under established MI guidelines supply will always be directed toward most promising projects; (2) any pattern at risk due to maturing waterflood would receive priority treatment; (3) there appear to be a number of facility upgrades available which will yield a substantial increase in MI; and (4) if any shortage existed that could not be dealt with under guidelines or extending injection period a couple years, MI supply can always be ramped up by converting some or all blendable NGLs.
65. Without late-life recovery of NGLs, there would be less than a barrel for barrel recovery of EOR oil for each barrel of NGL injected as MI.
66. The timing, recovery and salability of late-life NGLs reinjected as MI are uncertain.
67. ARCO stated that the situation at Prudhoe Bay's Skid 50 on or around February 9, 1995, when ARCO attempted to increase NGL production and BPXA refused to blend the increased volume, is not typical of good oil field management.
68. BPXA asserted that ARCO's actions on and around February 9, 1995 were not representative of good oil field practices and knows of no other field in the United States where such events could have occurred.
69. ARCO contends that between February 9, 1995, and June 20, 1995, 1.5 mmb of blendable NGLs had not been sent through TAPS because of BPXA's refusal to blend additional NGLs at Skid 50. ARCO further contends that reduced field gas offtake caused 200 mb of SLP to go unproduced.
70. BPXA asserts its actions at Skid 50 were taken to ensure greater ultimate recovery and to prevent waste in conformance with state oil and gas conservation statutes, even though operational procedures governing the CGF require blending the maximum NGL volume allowed by TAPS.
71. BPXA testified conditions have changed in the POP since the Commission held the 1991 PBMGP hearings. At the time, BPXA asserts, the WIOs thought maximum NGL blending was the preferred alternative in part because they anticipated insufficient liquid volume moving off the Slope to carry all the NGLs in later field life; that WIOs also expected up to 700 mmscfpd of MI following GHX-2; and, that no trade-off would exist between NGL and MI production.
72. TEPI contends that increasing NGL production will not promote conservation and will violate all efforts by the WIOs to collaborate in the best long term recovery plan for the POP.
73. ARCO and Exxon, jointly the majority equity owners of the gas cap, support the immediate sale of the greatest volume of NGLs blendable for transportation to market using the TAPS.
74. BPXA and the minority WIOs, jointly the majority equity owners of the oil rim, request up to a maximum of 700 mmscfpd of MI, or the maximum volume permitted by the MI distribution system, and endorse using salable NGLs if necessary to produce MI for EOR.
75. There is disagreement among the WIOs about the current market value of NGLs. Substantial uncertainty attaches to predicting the relative values of NGLs and EOR oil into the future.
76. ADNR has entered into settlements with BPXA, ARCO and Exxon that for royalty purposes value NGLs which are blended with POP crude oil and condensate and shipped through TAPS the same as SLP. ADNR does not rely only on Quality Bank methodology to value NGLs.
77. ARCO and Exxon value NGLs on the basis of the royalty settlement with the ADNR, which assigns that value essentially at crude parity.
78. BPXA stated that actual value of NGL is not on parity with POP SLP notwithstanding the ANS gas royalty settlement agreement between BPXA and ADNR establishing royalty payments for blended NGL on parity with SLP. Other dispositions of NGLs are reserved.
79. ADNR contends some components of NGLs are less valued than POP SLP, but the addition of NGLs still has a positive value.
80. NGLs sold blended with crude are more valuable than NGL components sold in the gaseous state as part of a major gas sale.
81. TAPS Quality Bank payments are intended to compensate for differences in the values of petroleum streams tendered to TAPS. Prior to December, 1993, API gravity was used to calculate differences in relative value. Today, the Quality Bank uses a distillation or assay methodology, including component market prices, to calculate differences in relative value.
82. Blending NGLs increases the API gravity of the POP hydrocarbon stream. Prior to December 1993, because Quality Bank value was a function of API gravity, the blending of NGLs increased the value of a SLP owner's share of the blended stream for TAPS Quality Bank purposes. There was no internal quality bank adjustment for NGLs blending with POP SLP within the Prudhoe Bay Unit.
83. Blending NGLs currently decreases the Quality Bank value of the POP hydrocarbon stream. Blending NGLs lowers the value of a SLP owner's share of the blended stream for TAPS Quality Bank purposes. There is no internal quality bank adjustment for NGLs blending with SLP within the Prudhoe Bay Unit.
84. ARCO agreed the effect of NGL blending with SLP from Prudhoe Bay reduced the Quality Bank value of a barrel of the mixed stream but argued that the addition of NGL was no different than blending condensate, which increases the value of a barrel of the mixed stream. Voluntary agreements make a specific value adjustment for condensate. Voluntary agreements do not make a specific value adjustment for NGLs.
85. Estimates of expected recovery, value and costs become highly speculative as the forecast period lengthens. For example, BPXA testified that in 1977 an average well cost $7 million (adjusted to 1995 dollars), while today an average well costs $1.5 million. During this period, the predicted recovery from the POP has risen from 9.6 billion barrels to over 13 billion barrels and the value of oil has been erratic. In addition, BPXA contends that in 1982 the WIOs expected 200-300 wells were left to drill to the POP. The unit has been drilling in excess of 50 wells each year and BPXA still anticipates there are some 200-300 wells to be drilled.
86. The volume of NGLs that could be produced exceeds the blending capacity of POP SLP. Every barrel of crude that goes by unblended is a lost opportunity for blending. Blending NGLs with SLP or selling them to another North Slope oil and gas field is the only viable means to market NGLs today. The ability to blend and transport NGLs with POP SLP declines with each day.
87. There is no opportunity to recapture MI components once they are sent down TAPS as NGLs. There is no evidence that enough MI components will not continue to be available in the POP to inject into any feasible EOR project.
88. BPXA characterized conversion of NGL into additional MI as investing a relatively low value product with the expectation of recovering a higher value product, at least from the oil rim perspective. BPXA testified that the CGF should make the maximum volume of MI and that failing to do that causes a reduction in ultimate recovery.
89. BPXA testified that deferred production caused by deferred expansion of EOR patterns due to lack of MI can become lost production because waterflood and facilities mature. This timing constraint can cause loss in ultimate production.
90. Exxon describes reservoir management, including identification of new opportunities to improve recovery, as a complex, continual and dynamic process which at times leads to different technical conclusions among owners.
91. Yukon Pacific. contends a major gas sale will maximize ultimate economic recovery of oil and gas. A major gas sale could begin as early as 2003 with continuing oil production. The Trans-Alaska Gas System ("TAGS") could move methane, butane, propane and ethane that would otherwise be undeliverable to market. A gas conditioning plant to process gas for shipment down TAGS could produce MI for reinjection on the North Slope.
92. Yukon Pacific contends the dual equity at the POP complicates future gas sales and does not benefit TAGS.
93. ADNR testified its understanding of the recovery mechanisms in the reservoir has evolved since initial depletion plans were formulated by the WIOs and approved by the ADNR. ADNR recommends approving reservoir production strategies that preclude flexibility in future operations only if there is no other choice available.
94. BPXA testified existing levels of MI injection and NGL sales are currently causing waste to occur. BPXA testified that to prevent waste a nominal 640-700 mmscfpd of MI must be injected in the reservoir to recover additional oil.
95. Exxon contends MI beyond that manufactured from unblendable components is too expensive in that it requires either additional investment or a loss of revenue. Remaining EOR expansions at the POP using MI can only be economic if they utilize unblendable NGL components.
96. ARCO testified existing levels of MI injection and NGL sales are causing waste, and that anything less than maximum blending of salable NGLs under the approved Plan of Development constitutes physical waste. Unless it can be demonstrated that injecting salable hydrocarbons is reasonably certain to produce more or higher value salable hydrocarbons, waste would occur.
97. BPXA claimed the trade-off for additional NGLs that could be converted to MI results in waste. BPXA testified that if 100,000 extra barrels of NGL are shipped today the unit will lose the opportunity to produce, at a minimum, 60,000 EOR barrels and potentially 200,000 barrels of EOR oil. The effect would be immediate.
98. BPXA stated that at the core of this disagreement are two very different views of how best to achieve greater ultimate recovery of oil and gas from the POP.
PROPERTY AND CONTRACTUAL ARRANGEMENTS
99. To prevent, or to assist in preventing waste, to insure a greater ultimate recovery of oil and gas, and to protect correlative rights of persons owning interests in tracts of lands affected, persons may validly integrate their interests to provide for the unitized management, development and operations of such tracts as a unit. AS 31.05.110.
100. The WIOs of the POP are Amerada Hess Corporation, ARCO Alaska, Inc., BP Exploration (Alaska) Inc., Chevron U.S.A., Inc., Exxon Corporation, U.S.A., Texaco Exploration and Production Inc., Louisiana Land and Exploration Company, Mobil Oil Corporation, Marathon Oil Company, Shell Western E & P Inc., and Phillips Petroleum Company.
101. The land owner, or royalty owner, is the State of Alaska as represented by ADNR. The State of Alaska has leased multiple properties overlying the POP. The State of Alaska retains a royalty share of 12.5% of all hydrocarbons produced from the POP.
102. The WIOs and ADNR entered into an agreement entitled, "Unit Agreement, Prudhoe Bay Unit, State of Alaska" on April 1, 1977. The Prudhoe Bay Unit Agreement ("PBUA") purportedly unitized all oil and gas rights in each lease overlying the POP so that unit operations may be conducted as if the unit area had been included in a single lease executed by the State of Alaska and any other party who may have authority to execute oil and gas leases, as lessor, in favor of all working interest owners, as lessees. Article 3.1. The PBUA established two participation areas, the Oil Rim Participating Area ("PA") and the Gas Cap PA. Article 5.2. The PBUA established two unit operators, now BPXA in the western half of the pool and ARCO in the eastern half of the pool. Article 4.1.
103. The PBUA provides that production from the gas cap be allocated to the Gas Cap Participating Area and production from the oil rim be allocated to the Oil Rim Participating Area. Article 6.1 Within each participating area, the agreement further provides that production be allocated among WIOs on the basis of tract participation agreed to by the WIOs. Article 5.2. The current approximate share of production for each working interest owner for each participating area is:
WIO Oil Rim Participating Area Gas Cap Participating Area
BPXA 50.68% 13.84%
ARCO 21.78% 42.56%
Exxon 21.78% 42.56%
Mobil 1.89% .28%
Phillips 1.88% .26%
Chevron .67% .48%
Amerada Hess .54% 0.00%
TEPI .55% 0.00%
LL&E .04% 0.00%
Marathon .05% 0.00%
Shell .14% 0.00%104. All oil derived from EOR is allocated to the oil rim owners. Approximately 90 percent of NGLs are allocated to the gas cap owners.
105. In signing the PBUA, the working interest owners agreed to develop with due diligence the unit area in accordance with good engineering and production practices. Article 4.2.
106. ADNR approved the PBUA with the understanding that unitization would prevent economic and physical waste by eliminating redundant expenditures and duplication of facilities for a given level of unit production, and that unitization would maximize ultimate recovery by the adoption of a unified reservoir-wide depletion strategy.
107. The WIOs entered into an agreement entitled, "The Prudhoe Bay Unit Operating Agreement" on April 1, 1977. The Prudhoe Bay Unit Operating Agreement ("PBUOA") provides, among other things, for unit operations, allocation of unitized substances, allocation of unit expenses and the establishment, enlargement and contraction of participating areas. The PBUOA provides that any portion of unit expense that is incurred by or directly related to and identified with a particular participating area shall be allocated to such participating area. Any portion of unit expense that is incurred by or directly related to and identified with more than one participating area shall be allocated among such participating areas in accordance with the provisions of the [PBUOA] applicable thereto....PBUOA Section 11.002
108. The PBUOA provides for the owners of the Gas Cap PA and the owners of the Oil Rim PA to develop and produce the POP using common facilities. The WIOs agreed to allocate costs of joint operations so that each participating area shares proportionally in the savings that occur as a result of joint operations. Article 32. For joint cost allocation purposes, unit operations were divided into three phases to reflect the change over from oil-oriented operations to gas-oriented operations. The first phase occurs until a major gas sale. The second phase is from commencement of major gas sales until operations in certain parts of the field become predominately gas oriented. The third phase applies after major gas sales to those areas of the field that have become predominately gas oriented and last until termination of the agreement. The PBUOA originally anticipated a major gas sale and initiation of the second phase to occur as early as seven years after signing. The POP, now 18 years later, continues under phase one management.
109. The POP is the only oil pool in Alaska where the WIOs attempt to unitize a reservoir while maintaining separate and disparate equities between that portion of the pool that is gas (gas cap) and that portion of the pool that is oil (oil rim). All other unitized gas cap reservoirs in Alaska are integrated with common equity between oil and gas.
110. No party to these proceedings identified any other unitized reservoir in the United States that attempts to develop the reservoir while maintaining separate and disparate equity interests between oil and gas where oil and gas are in communication in a common accumulation.
111. ADNR has not sought to create, nor has it approved, the formation of both a gas cap participating area and a oil rim participating area for any other reservoir in Alaska.
112. In order to produce the POP while trying to protect correlative rights, prevent waste and provide for maximum hydrocarbon recovery, the WIOs negotiated and signed the following documents which have amended the PBUOA since the unit was formed in 1977:
The Prudhoe Bay Unit NGL/EOR Operating Procedures and Flow Station 3 Injection Project Operating Procedures in 1983,
The Prudhoe Bay Unit Gas Handling Expansion Agreement in 1988,
The Prudhoe Bay Unit Issues Resolution Agreement ("IRA"), effective in 1990, and signed by all parties by 1993,
The Amended and Restated Prudhoe Bay Unit NGL/EOR Operating Procedures and Flow Station 3 Injection Project Operating Procedures, effective 1992, and signed by all parties in 1993.113. The ADNR was not a signatory, nor did ADNR object, to amendments to the PBUOA.
114. The original PBU NGL/EOR Operating Procedures Agreement established a ten year limit for the Gas Cap PA to provide, without additional compensation, MI produced at the CGF to the Oil Rim PA for EOR. The new limit established by the Amended and Restated PBU NGL/EOR Operating Procedures Agreement, as modified by the Issues Resolution Agreement, is for the Gas Cap PA to provide, without additional compensation, MI produced at the CGF to the Oil Rim PA for the life of the EOR project, unless the WIOs vote otherwise to terminate.
115. The Amended and Restated PBU NGL/EOR Project Operating Procedures also addressed the priority given to NGL and MI production. The WIOs disagree about the application of voluntary agreements governing NGL and MI production.
116. The WIOs negotiated and signed the Gas Handling Expansion Agreement to provide the contractual basis for construction of gas handling expansion projects. The Agreement was required, at least in part, because working interest owners had differing interpretations of the PBUOA for the sharing of costs between the Gas Cap PA and Oil Rim PA for gas handling expansion projects.
117. The Gas Handling Expansion Agreement defined the CGF as the gas processing facility built pursuant to the NGL/EOR Project Operating Procedures.
118. The IRA established the original gas cap gas reserves at 24.8 tscf, the original oil rim gas reserves at 10.7 tscf, and the original condensate reserve at 1.175 mmstb. The IRA provides that when cumulative condensate production volumes equals the final redetermined original condensate reserves, all base separator liquid volumes shall thereafter be allocated to the Oil Rim PA in accordance with PBUOA Article 28.007.
119. The IRA also amended the PBUOA, 30.008.04. "Unit Expense Allocation for Fuel Supplied" (Fuel Gas Supply Option). The value of fuel gas, established by arbitration, was set at $3.04 per million BTU for the term of the Fuel Gas Supply Option ("FGSO"). IRA Article 6.2. The IRA established that the FGSO ends in 2005 or with a major gas sale, whichever comes first.
120. ADNR testified that the entire FGSO and subsequent arbitration would not have had to take place if there had been only one participating area.
121. The PBUOA, as amended, specifies that the manufacture and shipping of NGL will take priority over the manufacture and injection of MI. This priority was set prior to significant competitive demand between NGL and MI. There is no commitment to a volume of MI or NGL in the PBUOA, as amended.
122. ARCO contends the reason the impasse on NGL blending could occur at the POP is that there are two participating areas with different equities. ARCO contends BPXA's action violates the PBUOA and commitments made to the Commission to maximize production and economic recovery from the POP.
123. ARCO testified that they must operate under both field rules and voluntary contracts. ARCO asserts the contracts require maximization of NGL blending. ARCO asserts that the first and foremost goal is maximization of ultimate recovery from the POP in the context of approved plans of development. ARCO testified that the unit provision that require operating conditions be reviewed are to ensure appropriate crude stabilization to allow maximum NGL blending and maximum total hydrocarbon liquid recovery.
124. Exxon asserts it is the responsibility of the unit owners to determine the operating parameters that achieve maximum economic recovery from the POP. Exxon asserts the appropriate course is obvious: NGL blending should be maximized and owners should put the unit technical teams to work to iron out differences.
125. Exxon contends the IRA established that unblendable NGLs were dedicated primarily to the owners of the Oil Rim PA as MI for EOR and blendable NGLs were dedicated to the owners of the Gas Cap PA. Exxon asserts that any MI produced from blendable NGLs are an operational cost primarily to the owners of the Gas Cap PA not covered by any agreement.
126. Phillips contends there is a disagreement among WIOs regarding the meaning of agreements about appropriate level of NGL blending. Phillips asserts that the unit should determine what MI and NGL rates will maximize economic hydrocarbon recovery in the Prudhoe Bay Unit and recommends a sequestered technical team to work out the best solution for ultimate economic recovery.
127. TEPI views the POP as one unitized property with two equity ownerships. TEPI is not aware of any other field unitized in such a manner.
128. TEPI asserts that maximum NGL blending destroys the only key IRA benefit it will receive as a minority owner in only the Oil Rim PA.
129. BPXA argues that the PBUOA, as amended, requires prudent maximization of total liquid hydrocarbon recovery before blending maximum NGL volumes. BPXA asserts that if either participating area is adversely affected by production, the unit operators must review the operating conditions and, where prudent, revise them to address adverse impacts.
130. BPXA proposes Module 880 to take its share of SLP production in-kind and bypass existing blending facilities at Skid 50. BPXA argues that ARCO and Exxon have no contractual right to blend their allocated volumes of low value NGLs and degrade BPXA's SLP without compensation for BPXA. BPXA argued blending NGLs with SLP forces BPXA to incur a severe penalty when the combined stream is measured by the Quality Bank.
131. Module 880 will not increase ultimate recovery from the POP.
132. ARCO described Module 880 as a BPXA effort that violates the NGL/EOR Operating Agreements which expressly require the maximization of NGL production and separator liquid production.
133. The State of Alaska, in a response dated January 13, 1994, filed with the Alaska Public Utilities Commission ("APUC"), Docket Nos. P-89-1, et. al., argued that BPXA, in voluntary cooperation with other Prudhoe Bay Unit interest owners, negotiated voluntary agreements that allow for NGLs and SLP to be commingled and offered at Pump Station 1 as a single stream. The State asserted that the threat by BPXA to construct separate facilities to deliver its own SLP by taking what BPXA termed a "vastly inefficient" step of constructing separate facilities need not be a concern of the APUC because the Alaska Oil and Gas Conservation Commission possesses sufficient regulatory authority to ensure that waste is not committed in the production of oil or gas citing AS 31.05.030(b); and AS 31.05.095.
134. In the same January 13, 1994, response the State also argued that the TAPS Quality Bank had no legal or logical responsibility to account for the addition of NGLs to the SLP within the Prudhoe Bay Unit. The State asserted BPXA should handle the question of whether NGLs blended at Skid 50 are lower in value than the remainder of the oil as the internal Prudhoe Bay Unit matter that it is.
135. On April 21, 1995, BPXA filed a request for declaratory relief in Alaska Superior Court, Case No. 3AN-95-3321-CIV, in which BPXA, in part, asserts that it has a contractual right under the PBUOA to take Prudhoe Bay Unit production in-kind and tender it as BPXA sees fit and that it has no obligation to blend its allocated SLP with other WIO's NGLs without compensation.
136. On May 11, 1995, Exxon filed a complaint in Alaska Superior Court, Case No. 1JU95-1013 CI, in which Exxon, in part, accuses BPXA of willful violation of the PBUOA, the NGL/EOR Agreement and the Amended NGL/EOR Agreement and unreasonable interference with unit operations.
137. On May 11, 1995, ARCO filed a complaint in Alaska Superior Court, Case No 1JU-95-1012 CI, in which ARCO claims, in part, BPXA has violated its contractual obligations as a unit operator, is contemplating building facilities that will unreasonably interfere with unit operations and has repudiated the basic allocation of hydrocarbons under the operating agreements underlying the entire organization and operation of the Prudhoe Bay Unit.
138. Notwithstanding the PBUA and the PBUOA and its amendments, the WIOs cannot agree on implementing a plan of development for the POP, at least as it pertains to the balance between NGLs and MI, that will prevent waste, protect correlative rights and ensure greater ultimate recovery.
139. The WIOs' failure to agree on implementing a plan of development, as it pertains to the balance between NGLs and MI, is not in accordance with good oil field practices, is leading to the inefficient operation and production of the POP and is contributing to a reduction in the quantity of oil and gas that can be recovered from the POP.
140. If there were an integrated ownership of oil and gas within the POP, it is unlikely the WIOs would be before the Commission on whether to maximize blendable NGLs or make more MI.
141. During 1995, the WIOs have been unable to cooperatively resolve differences with respect to how their voluntary agreements protect their respective correlative rights.
142. ARCO testified BPXA's refusal to blend is a repudiation of contractual obligations motivated by its economic interests.
143. BPXA has stated that the negative economic impact of NGL blending is increasingly becoming an impediment to full cooperation in the Prudhoe Bay Unit.
144. BPXA testified there is competition between the oil rim and gas cap owners to produce their just and equitable shares of their respective resources manifested in the competition for MI and NGLs from the CGF.
145. Exxon testified cost of MI is a key variable affecting EOR scope, and that, as a gas cap owner, it had no problem selling NGLs back to the unit to use as MI, but as an oil rim owner it might have a problem with purchasing an expensive MI.
146. TEPI testified that if it had only gas cap ownership and no oil rim ownership, it would be in a position to support increased blending.
147. BPXA contends it will be deprived of its just and equitable share of the total oil reserves if the MI supply is allowed to be depleted by increasing the NGL blending rate.
148. ADNR stated that even if the WIOs, ADNR, the Commission and all other interested parties could agree on a common reservoir behavior and a common production forecast model using the same set of given assumptions, the differing oil rim versus gas cap ownership interests may mean that the different owners will favor different operating and depletion strategies based on each owner's specific economic position. As long as there are two participating areas those commercial differences are going to exist and have to be considered.
149. BPXA suggested that if the disagreement were only technical, resolution by unit owners would be possible.
150. ARCO contends the right of the gas cap to sell marketable components to the oil rim within the POP is analogous to selling to a different reservoir.
151. ARCO testified it has no further obligation to provide salable NGLs for EOR and asserts its correlative rights to produce its gas would be harmed if forced to manufacture MI from salable NGLs. ARCO suggests the Commission require the oil rim to pay for converting blendable NGLs into MI to protect its correlative rights.
152. BPXA and TEPI testified they had already paid for MI for EOR by investing in the gas handling expansions. They assert their correlative rights to produce oil would be jeopardized if they were unable to use all that gas for EOR. They stated that 700 mmscfpd of MI has been purchased by the oil rim by constructing GHX-2 for use in the EOR project.
153. ARCO or Exxon each own roughly 42 percent of a barrel of NGL but each own roughly 22 percent of a barrel of EOR oil that might be recovered using MI converted from salable NGLs. BPXA owns approximately 14 percent of each barrel of NGL but owns approximately 51 percent of a barrel of EOR oil that might be recovered using MI converted from salable NGLs. TEPI sacrifices no potential revenue converting salable NGLs to MI because it owns no appreciable share of NGLs and about .5 percent of each EOR barrel. For ARCO or Exxon, the return on a barrel of EOR oil versus a barrel of NGL must be two or three times that of BPXA's return to have a roughly equivalent economic impact.
154. The separate equities between the Gas Cap PA and the Oil Rim PA fosters differing commercial interests, which have led to competition to produce the POP between each participating area.
155. BPXA, TEPI, Mobil, Marathon, Chevron, Shell, Phillips, Amerada Hess and Exxon all support reconvening the unit technical team to review the question of what balance of NGL and MI production will lead to greater ultimate recovery. WIO participants supporting reconvening the technical team estimate 90 to 120 days will be needed for the technical team to complete work. BPXA recommends the technical team, if ordered to reconvene, report back to the Commission within 90 days.
156. Except for Exxon, all the WIOs recommending reconvening the technical team request that in the interim the Commission limit NGL blending to 74,000 bpd.
157. Exxon recommends that maximum NGL blending to the TAPS limit be implemented "until sufficient data/studies dictate otherwise."
158. ARCO opposes an order reconstituting a unit technical team because it contends additional unit technical work is unlikely to change anyone's view of NGL/MI utilization. ARCO asserts technical teams cannot address business and contract issues which are the ultimate drivers in the current dispute. ARCO contends business issues are too complex and the economic interests of the companies are too different to be resolved by a technical team. For example, ARCO suggests a technical team cannot assign risk to speculative projects or judge the willingness of one company to risk another's resource.
159. ARCO requests the Commission require BPXA to allow NGL blending to the maximum allowed by TAPS.
160. ADNR testified the Commission, with respect to unitization and unitized operations of pools, has a responsibility to prevent or to assist in preventing waste, to ensure a greater ultimate recovery of oil and gas, and to protect the correlative rights of persons owning interests in the affected tracts of land. ADNR asserts the correlative rights of the owners of the Oil Rim PA and the Gas Cap PA in the POP need to be considered and protected. ADNR requests the Commission consider what operating plans and depletion strategies best maximize ultimate recovery of both oil and gas from the POP, then the economic interests of the various parties can be weighed and balanced.
161. ADNR also submitted a post-hearing brief contending the Commission should defer to ADNR to address the issues.
JURISDICTION AND AUTHORITY
162. The authority of the Commission applies to all land in the state subject to its police powers including land of the United States and land subject to the jurisdiction of the United States. The authority of the Commission further applies to all land included in a voluntary cooperative or unit plan of development or operation entered into in accordance with AS 38.05.180(p). AS 31.05.027.
163. ADNR has standing before the Commission to raise all issues relating to state-owned land without regard to the type of proprietary interest held by the State in the land. ADNR has the same standing (no more or less) before the Commission as granted by law to any other proprietary interest. AS 31.05.026(a)(e).
164. The waste of oil and gas in the state is prohibited. AS 31.05.095.
165. The Commission has jurisdiction and authority over all persons and property, public and private, necessary to carry out the purposes and intent of AS 31. The Commission shall investigate to determine whether or not waste exists or is imminent, or whether or not other facts exist which justify or require action by it. The Commission shall adopt regulations and orders and take other appropriate action to carry out the purposes of this chapter. The Commission may require the filing and approval of a plan of development and operation for a field or pool in order to prevent waste, ensure a greater ultimate recovery of oil and gas, and protect the correlative rights of persons owning interests in the tracts of land affected. The Commission may regulate, for conservation purpose the quantity and rate of the production of oil and gas from a well or property; this authority shall also apply to a well or property in a voluntary cooperative or unit plan of development or operation entered into in accordance with AS 38.05.180(p). AS 31.05.030(a), 31.05.030(b), 31.05.030(d)(9) and 31.05.030(e)(6).
166. ARCO, Exxon and BPXA suggest the Commission can protect the State's interest and ensure maximum recovery of economic hydrocarbons without deciding the contractual disputes between ARCO, Exxon and BPXA now pending before the Alaska Superior Court.
167. ARCO, BPXA, and Exxon agree that the Commission has the jurisdiction and authority to determine the appropriate level of NGL blending based on considerations of preventing waste and maximizing recovery. ADNR argues that at most the Commission's authority is limited to deciding matters of physical waste and that it may not base its decision on "economic analysis." Phillips argues that there is no issue of physical waste in this case because BPXA is at worst putting "to some use" the blendable NGL components that are being made into MI.
168. Economics necessarily plays a role in some of the decisions that may face the Commission. For example, economic practicability is implicit in the statutory standard of "conducted in accordance with good oil field engineering practices." AS 31.05.170(14)(A). The role of economics in a similar provision of Wyoming's conservation statute ("prudent and proper operations") was acknowledged by the Wyoming Supreme Court in Majority of Working Interest Owners in Buck Draw Field Area v. Wyoming Oil and Gas Conservation Comm'n, 721 P.2d 1070 (Wyo. 1986).
169. Despite the fact that the relative values of NGLs and EOR oil were addressed and disputed by the parties, it is not necessary for the Commission to consider economics to the extent of determining the relative values of those substances. The basis of the Commission's decision does not require that determination nor does the Commission's decision pertain to "economic waste" as that term is used in certain other states' conservation statutes in which it relates to market prorationing.
170. Phillips' interpretation of waste is not consistent with the Alaska Oil and Gas Conservation Act. AS 31.05.170(14) defines "waste" as including the "operating or producing of any oil or gas well in a manner which results or tends to result in reducing the quantity of oil or gas to be recovered from a pool in this state under operations conducted in accordance with good oil field engineering practices."
171. ADNR urges the Commission to defer jurisdiction to ADNR because it asserts it has jurisdiction over the entire dispute and economic expertise. ADNR has scheduled a hearing to address similar issues as those before the Commission.
172. It is not clear action by ADNR pursuant to its own authorities would resolve the controversy. A WIO aggrieved by ADNR's decision could seek recourse at the Commission.
173. There is a claim before the Commission that waste has been taking place and continues to take place. The Commission has jurisdiction and is obligated to make a determination in this controversy as quickly as practicable.
174. DNR also argues that voluntarily unitized state leases are solely within the purview of ADNR and that the Commission has extremely limited or even non-existent jurisdiction to address issues relating to unitization and management of the Prudhoe Bay Unit, or even issues of waste and conservation within the Prudhoe Bay Unit.
175. ADNR's assertion is not consistent with the Alaska Oil and Gas Conservation Act. Among other provisions of the act, AS 31.05.027 expressly provides, in relevant part: "The authority of the commission further applies to all land included in a voluntary cooperative or unit plan of development or operation entered into in accordance with AS 38.05.180(p)."
176. If a failure to achieve unitization within the meaning of AS 31.05.110 results in problems unitization is designed to rectify, notwithstanding that a unit agreement has been entered into by the working interest owners and approved by ADNR under AS 38.05.180(p), "it is [the Commission's] duty to . . . do the things necessary or proper to carry out the purposes of" AS 31.05.110.
1. The eleven WIOs have agreed to unitized management, development and operation of the Prudhoe Oil Pool under the terms of the Prudhoe Bay Unit Operating Agreement as amended. The management, operation and development of the Prudhoe Oil Pool has not been able to proceed as approved in the Prudhoe Bay Unit Operating Agreement without a number of voluntary amendments to the PBUOA.
2. The Alaska Department of Natural Resources endorsed unitized management, development and operation of the Prudhoe Oil Pool under the terms of the Prudhoe Bay Unit Agreement.
3. The Commission has jurisdiction regarding the conservation of oil and gas in Alaska. Leases subject to voluntary units and voluntary cooperative or unit plans of development and operation entered into in accordance with AS 38.05.180(p) are not exempt from Commission regulation to prevent waste or assist in preventing waste, ensure greater ultimate recovery of oil and gas or protect the correlative rights of persons owning interests in the tracts of land affected. AS 31.05.027, AS 31.05.030 and AS 31.05.110
4. Resolution of the controversy presented in this proceeding concerning the appropriate rate of NGL blending falls squarely within the Commission's authorities to prevent waste, AS 31.05.030(b), to require the filing and approval of a plan of development and operation, AS 31.05.030(d)(9), and to regulate for conservation purposes the quantity and rate of the production of oil and gas from a well or property, AS 31.05.030(e)6).
5. Conservation Order 290, authorizing the Prudhoe Bay Miscible Gas Project, need not be amended. However, the commitment to EOR contemplated by Conservation Order 290 requires that the Central Gas Facility (CGF) be capable of producing a supply of MI consistent with commitment to EOR without competition with production of salable NGLs. Testimony during 1991 hearings leading to C.O. 290 convinced the Commission that those twin objectives were integral to greater ultimate recovery and were not, and would not be, in competition. Failure to pursue and achieve those twin objectives may compel the Commission to reconsider C.O. 290.
6. Competition exists between the production of blendable NGLs and the manufacture of MI. There are facility upgrade options that can eliminate or reduce competition between the manufacture of NGLs and MI at the CGF.
7. The WIOs disagree about how their property and contractual arrangements affect the management, development and operation of the unit to ensure greater ultimate recovery of oil and gas.
8. The WIOs disagree about how their property and contractual arrangements protect the correlative rights of both the oil rim owners and the gas cap owners to produce their just and equitable share of oil and gas without waste. This is possible because of separate and disparate equity interests between two participating areas within the Prudhoe Oil Pool.
9. It appears that all persons' correlative rights will be best protected by complete integration of interests in the Prudhoe Oil Pool under AS 31.05.110.
10. To the extent, if any, that correlative rights may be affected by the Commission's order concerning the volume of NGL production, the need to prevent waste is paramount. Gilmore v. Oil and Gas Conservation Comm'n, 642 P.2d 733 (Wyo. 1982).
11. Maximizing blendable NGL production does not compromise correlative rights because it allows the owners of the gas cap to produce all the gas cap hydrocarbons they seek to produce and does not prevent the oil rim owners from producing all the oil rim hydrocarbons they seek to produce without using gas cap products the gas cap owners wish to produce and sell. To the extent the oil rim owners contend they have paid for MI made with blendable NGLs, that is a contractual matter not determined by this Order.
12. ARCO and BPXA agree that current production practices are producing physical waste from the Prudhoe Oil Pool, but disagree why. Current property and contractual arrangements governing the operation and development of the Prudhoe Oil Pool are inadequate to prevent, and may promote, physical waste.
13. If NGL production is increased to the current TAPS vapor pressure control limit, on average less than one barrel of EOR oil, and probably not more than 0.6 barrel of EOR oil, will be foregone, at least temporarily, for each barrel of additional NGLs produced during the next year. The volume of foregone additional hydrocarbon recovery in the form of "late-life NGLs," that BPXA asserted could be as much as 0.7 barrel per barrel of additional NGLs produced, is highly speculative in quantity and salability.
14. If NGL production during the next year is increased to the current TAPS vapor pressure control limit, and if it later appears some lower volume of NGL production is the optimal conservation practice, there will remain an adequate volume of MI components in the Prudhoe Oil Pool with which to make sufficient MI for any EOR project. It is likely any interim loss in EOR oil production (and any late-life NGL recovery) will be made up by extending the EOR project, by making other modifications in EOR facilities or operations, or by a combination of such changes.
15. If NGL production during the next year is not increased over the level at which BPXA is currently constraining it, and if it later appears that maximum NGL production is the optimal conservation practice, it is unlikely any interim loss in NGL production will be made up because of the limited and declining capacity of the Prudhoe Oil Pool stream to accept NGL.
16. At least in the short term, the quantity and rate of production of oil and gas most likely to prevent waste and ensure greater ultimate recovery is to produce the maximum blendable volume of NGLs from hydrocarbons delivered to the CGF.
17. Module 880 will not contribute to greater ultimate recovery or prevent waste. WIOs disagree whether voluntary agreements seeking to protect correlative rights allow or do not allow such a facility to be constructed. WIOs are involved in civil suits in an attempt to resolve the dispute. If equity within the Prudhoe Oil Pool were integrated as a single property, there would be no need for an owner to build such a facility to protect its correlative rights.
18. Sufficient evidence has been heard regarding the effects of property and contractual arrangements on Prudhoe Bay development and operation to convince the Commission that the next phase of these proceedings should be more focused than the general investigation previously anticipated. It appears that more complete unitization and integration of interests in the Prudhoe Oil Pool will be necessary to prevent waste, ensure a greater ultimate recovery of oil and gas, and protect correlative rights. Consequently, in the absence of voluntary efforts, further hearings in this matter will be directed toward developing a plan of compulsory unitization.
19. Competition between the gas cap and oil rim has compromised conservation principles in the development and operation of the Prudhoe Oil Pool. If the competitive effects of disparate equity interests are eliminated, the working interest owners should be able to recommend a cooperative and uniform plan of operation and development to prevent waste and ensure greater ultimate recovery of oil and gas from the Prudhoe Oil Pool. Therefore, a permanent rule governing the production of NGLs and MI is unnecessary at this time.
THEREFORE, IT IS ORDERED BY THE COMMISSION THAT:
1. Effective immediately, the operators of the Prudhoe Oil Pool shall, from hydrocarbons delivered to the CGF, produce NGLs to the maximum volume that could be blended with POP SLP and tendered to TAPS from the Prudhoe Oil Pool, whether or not such volume is actually blended and tendered. This section of this Order expires on August 31, 1996, unless extended by this Commission after notice and opportunity for hearing. The authority for this section of this Order is AS 31.05 generally and AS 31.05.030(b), 31.05.030(d)(9), and 31.05.030(e)(6) specifically.
2. A hearing is scheduled for January 11, 1996, to develop a plan for compulsory unitization of the Prudhoe Oil Pool. Upon receipt of a written request, this hearing may be postponed if, in the judgment of the Commission, the owners of the Prudhoe Oil Pool are working to integrate the separate and competing equities of the gas cap and oil rim within the Prudhoe Bay Unit. The authority for this Order is AS 31.05 generally and AS 31.05.027, 31.05.030, 31.05.095 and 31.05.110 specifically.
3. Written submittals in response to the Commission's questions and inquiries concerning the plan of development and operations and other agreements as they affect NGL throughput, MI utilization and ultimate recovery from the Prudhoe Oil Pool (Appendix A, April 20, 1995 Procedural Order) are now due September 1, 1995. Upon receipt of a written request, this deadline may be postponed if, in the judgment of the Commission, the owners of the Prudhoe Oil Pool are working to integrate the separate and competing equities of the gas cap and oil rim within the Prudhoe Bay Unit. The authority for this Order is AS 31.05 generally and AS 31.05.030(b), 31.05.060 and 31.05.070 specifically.
4. An annual plan of operation and development for the Prudhoe Oil Pool and any amendment to that plan must be submitted to the Commission by October 1, 1995, and by August 15 thereafter. The plan must include a report on the feasibility and progress made toward eliminating the competition between NGLs and MI at the CGF. This section of this Order expires on August 31, 1996, unless extended by the Commission after notice and opportunity for hearing. The authority of this section of this Order is AS 31.05 generally and AS 31.05.030(d)(9) specifically.
5. Each agreement executed hereafter modifying any provision of the PBUA or PBUOA or any agreement listed under Finding 112 that may affect operation of the Prudhoe Oil Pool must be submitted to the Commission to afford it an opportunity to investigate whether the agreement contains anything that may impair correlative rights, reduce ultimate recovery or otherwise lead to waste. This section of this Order expires on August 31, 1996, unless extended by the Commission after notice and opportunity for hearing. The authority of this section of this Order is AS 31.05 generally and AS 31.05.030(d)(9) specifically.
6. This Order is not intended to preclude any person from seeking to enforce contractual rights, subject to compliance with the provisions of this Order.
DONE at Anchorage, Alaska and
dated August 9, 1995 (Revised November 3, 1995). _____________________________________
David W. Johnston, Chairman
Alaska Oil and Gas Conservation Commission
Russell A. Douglass, Commissioner
Alaska Oil and Gas Conservation Commission
Tuckerman Babcock, Commissioner
Alaska Oil and Gas Conservation Commission
This decision is the final order of the Alaska Oil and Gas Conservation Commission. Any appeal to superior court must be brought within 30 days from the date that this decision is mailed or otherwise distributed.