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10/6/2005 Orders File Cover Page.doc
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INDEX CONSERVATION ORDER NO. 362
PRUDHOE BAY OIL FIELD
LISBURNE, WEST BEACH, N. PRUDHOE BAY, NIAKUK OIL POOLS
POINT McINTYRE OIL FIELD
PT. McINTYRE, STUMP ISLAND OIL POOLS
1. April 4, 1995 Affidavit of Publication for Notice of Public Hearing
2. April 5, 1995 AOGCC ltr to DNR Commissioner Shively requesting
DNR presence at Public Hearing
3. April 7, 1995 AOGCC ltrs to DOR Commissioner Condon and DNR
Commissioner Shively requesting testimony in
commingling/allocation hearing
4. April 9, 1995 Concerned Citizen ltr
5. April 13, 1995 ARCO ltr re: Production Allocation Hearing
6. April 26, 1995 DNR ltr re: attendance at Public Hearing
7. April 26, 1995 DOR ltr re: attendance at Public Hearing
8. April 28, 1995 EXXON Company ltr re: Hearing on Commingled
Production
9. May 3, 1995 Sign- In Sheet for Public Hearing
10. May 3, 1995 Public Hearing Transcript
11. March 1, 2007 AOGCC e-mail response to BP re: Lisburne L5 Pad crude
heater and well testing
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STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
3001 Porcupine Drive
Anchorage Alaska 99501-3192
Re: AOGCC Motion to review well testing
and allocation procedures for producing pools
in the Greater Pt. McIntyre Area for royalty
accounting, taxation and conservation purposes.
IT APPEARING THAT:
) Conservation Order No. 362
) Prudhoe Bay Field
) Lisburne Oil Pool
) West Beach Oil Pool
) N. Prudhoe Bay Oil Pool
) Niakuk Oil Pool
) Point McIntyre Oil Field
) Pt. McIntyre Oil Pool
) Stump Island Oil Pool
September 12, 1995
1. The Alaska Oil and Gas Conservation Commission, acting on its own motion, gave
notice of intent to hold a public hearing to examine the appropriateness of well testing
and aIlocation procedures for measuring produced fluids from pools in the Greater Pt.
McIntyre Area ("GPMA") for royalty accounting, taxation and conservation purposes.
2. Notice of public hearing was published in the Anchorage Daily News on March 31,
1995.
3. The public hearing was held May 3, 1995 beginning at 1 :30 p.m. at the Commission's
office, 3001 Porcupine Drive, Anchorage, Alaska.
4. Hearing participants included ARCO Alaska, Inc. ("ARCO"), BP Exploration (Alaska)
Inc. ("BPXA"), Exxon Company, USA ("Exxon"), the Alaska Department of Natural
Resources ("ADNR") and the Alaska Department of Revenue ("ADOR").
5. Representatives of ARCO, BPXA and ADOR gave sworn testimony.
6. Written comments were received from ARCO, April 13, 1995, ADNR, April 26, 1995,
ADOR, April 26, 1995, Exxon, April 28, 1995 and a concerned citizen, April 9, 1995.
In addition, a letter to ARCO from ADNR, dated April 21, 1995, was included in the
hearing record.
FINDINGS:
1. Production from the Lisburne Oil Pool, West Beach Oil Pool, N. Prudhoe Bay Oil
Pool, Niakuk Oil Pool, Pt. McIntyre Oil Pool and Stump Island Oil Pool is
Conservation Order 362~
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Page 2
commingled on the surface and processed at the Lisburne Production Center (LPC).
Together these pools make up the GPMA.
2. The State of Alaska, as represented by ADNR, owns all land in the GPMA. ADNR
has issued oil and gas leases in the GPMA subject to different royalty and tax
severance rates. Royalty rates vary from 5 percent to 12.5 percent on individual
leases. Severance taxes vary from about 12 percent for the Pt. McIntrye Oil Pool to at
or near zero for each of the other pools. The ADOR collects severance taxes.
3. The mineral interest owners of lands leased in the GPMA are ARCO, BPXA and
Exxon.
4. ARCO is operator of the Lisburne Oil Pool, West Beach Oil Pool, N. Prudhoe Bay Oil
Pool, Pt. McIntyre Oil Pool and Stump Island Oil Pool. BPXA is operator of the
Niakuk Oil Pool.
5. ARCO is operator of the LPC.
6. Production from each pool in the GPMA is not metered directly. Water, oil and gas
must be separated for accurate metering. Fluid separation occurs at the LPC. The
separate fluid streams leaving the LPC are metered.
7. Production from each pool in the GPMA is approximated using twice monthly
production tests. Production is allocated to each producing well in the respective
pools by the following procedures:
1. Conduct well tests to determine production rates for each well.
11. Calculate each well's theoretical monthly production ("TMP") based on well test
rate( s) and actual time on production.
111. Sum the TMP volume for all wells in all pools.
tv. Determine an allocation factor as the ratio of the metered volume to the TMP for
all wells in all pools (i.e., metered/TI\1P)
v. Calculate each well's actual monthly production ("AMP") volume as:
AMP = TMP x Allocation Factor
8. Natural Gas Liquid ("NGL") is allocated to each pool based on actual gas production
volumes and NGL process simulations.
9. Wells that have been shut in and cannot meet the twice monthly test frequency are
tested within five days of startup.
Conservation Order 362 \~
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Page 3
10. The operator determines optimum test duration and stabilization time on a well by well
basis.
11. Water volumes are determined by API/MPMS approved methods, or by industry
proven, on-line water cut measurement devices approved by the Commission.
12. API gravity is determined by API/MPMS approved methods for each producing well
annually.
13. Gas samples are taken and analyzed for composition from each non gas lifted
producing well annually.
14. The operator holds allocation process reviews with the Commission twice each year.
15. The Commission may require the gauging or other measurement of oil and gas to
determine the quality and quantity. AS 31.05.030.
16. On April 26, 1995, ADOR wrote the Commission stating that a 10 percent allocation
error at the LPC (where 10 percent of Pt. McIntyre oil is misallocated) would cost the
state $2 million annually. With technical assistance from the Commission, ADOR
stated it has developed a surveillance tool and procedure for measuring well-by-well
volumes.
17. ADOR testified the well testing process is acceptable and working satisfactory, and
that the Commission need not do anything more to improve the process on the
account of ADOR.
18. ADOR testified that some flexibility in the testing frequency may be appropriate for
wells with stable production profiles in order that additional test separator time can be
directed toward wells with variable or cyclical production.
19. On April 26, 1995, ADNR wrote the Commission stating it was generally satisfied
with current production allocation, reporting requirements and verification opportunity
for determining the volumes of fluids produced through the LPC.
20. ADNR did not participate further in the hearing, except to send an observer.
CONCLUSIONS:
1. Current well testing and allocation procedures are adequate for the Commission to
ascertain appropriate production volumes for each pool and determine issues of waste,
correlative rights and ultimate recovery.
2. The Alaska Department of Natural Resources is satisfied with current well testing and
allocation procedures for royalty accounting purposes.
Conservation Order 362',,-,
'....,../
Page 4
3. The Alaska Department of Revenue is satisfied with current well testing and allocation
procedures for severance taxation accounting purposes.
4. Except for allowing additional flexibility in well test frequency for individual wells with
stable production, there is no need to revise current well testing and allocation
procedures for pools in the GPMA at this time.
NOW THEREFORE IT IS ORDERED:
Produced fluids from the Lisburne Oil Pool, West Beach Oil Pool, N. Prudhoe Bay Oil
Pool, Niakuk Oil Pool, Pt. McIntyre Oil Pool and Stump Island Oil Pool may continue to
be commingled on the surface for processing at the Lisburne Production Center.
Production from each pool may be assigned on the basis of twice monthly well tests, using
procedures described in individual conservation orders for those pools or in this order.
The Commission may approve a different test frequency for individual wells upon
application.
DONE at Anchorage, Alaska and dated September 12, 1995.
Russell A. Douglass, Co ssioner
Alaska Oil and Gas Conservation Commission
AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the
Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the
order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in
part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30
days ffom the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the [mal
order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the
Commission, the 30 day period for appeal to Superior Court rons ffom the date on which the request is deemed denied (i.e., 10th day after
the application for rehearing was filed).
#11
Ke: LIsourne L;) paa cruae neater ana well testmg
~/
Subject: Re: Lisburne L5 pad crude heater and well testing
From: Jane Williamson <jane _ williamson@admin.state.ak.us>
Date: Thu, 01 Mar 2007 15:29:51 -0900
To: "French, Samuel W"<Samue1.FreIlcl1~~~:C~~
CC: "Weggeland, Mark C"<Mark.\V~g~~l~~($~r.~()p1~,i':.f~~~~~~~,~~tt
<Alan.Mitchell@BP . com> , Cathy P Fo~rst~ri0ca.t4Y2..roel'st~1'@a~JJl~~~t~~~~~f'",~OªY}iº(.)1<>j;JJ.I.li~
<jody _colombie@admin.state.ak.us>
Sam,
CO 362 requires production from each pool commingled for processing at the LPC to be allocated on the
basis of twice monthly well tests. We temporarily authorize allocation of L5 production on the basis of
monthly well tests through September 30,2007.
Jane Williamson
French, Samuel W wrote:
lof2
3/5/2007 11 :38 AM
~,"e. LISDUUJe L) pad crude heater and well testing
Jane,
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A recent inspection of the Lisburne L5 pad crude heater detected cracks in the heater head and the
heater was shut down. The crude heater heats the crude and gas lift gas as it leaves L5 pad as well as
provides heat to the L5 pad module. The L5 module is currently being heated with portable heaters but at
current ambient temperatures it is not up to normal temperature. The lower temperature in the L5 module
has impacted our ability to obtain well tests on wells at the L5 pad. It is unlikely we will be able to get a
second well test in February on L5 wells. We are currently working on a solution that would allow us to
use the well test equipment on L5 pad without the crude heater. If that solution is unsuccessful, we will
implement a process of using a portable test separator twice a month to test all L5 wells until ambient
temperatures warm up to where we can use the L5 pad test equipment. Please let me know if the
commission approves of this plan for well testing L5 pad wells.
The L5 pad currently produces approximately 5000 bopd (SLP+NGLs) but the gas production from this
pad is necessary to keep the LPC gas plant in operation. Without the L5 pad gas production, the LPC
would have to be shut down, resulting in a production loss of approximately 35,000 bopd (13,000 bopd
Lisburne, 8,000 bopd Niakuk and 14,000 bopd Pt Mcintyre). The impact to Pt Mcintyre would occur
because the LPC provides lift gas to Pt Mcintyre.
The L5 heater is currently shut in while bid letters and purchase orders are being prepared for
replacement equipment. Delivery is estimated to be 4 months from the time a contractor is selected and
authorized to purchase the equipment. The install would take approximately one month. This results in
September 1 st being an approximate date for the crude heater to be back in operation. This estimate is
based on preliminary information and could end up being later in the year.
Regards,
Sam
Sam W. French
Lisburne Subsurface Team Leader
GPMA
BP Exploration (Alaska) Inc.
( 907) 564-4168 Office
( 907) 440-4182 Cell
Mail Stop MB 5-4
Jane Wi1liamson, PE <Jane williamson(á¿admin.state.ak.us>
Senior Reservoir Engineer (907) 793-1226
Alaska Oil and Gas Conservation Commission
2of2
3/5/2007 11 :38 AM
#10
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ALASKA OIL AND GAS CONSERVATION COMMISSION
PUBLIC HEARING
MAY 3, 1995, 1:30 O'CLOCK P.M.
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TRANSCRIPT OF PROCEEDINGS
RE: COMMINGLED PRODUCTION
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HELD AT THE
ALASKA OIL AND GAS CONSERVATION COMMISSION
3001 PORCUPINE DRIVE
ANCHORAGE, ALASKA
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RECEIVED
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MA Y - 8 1995
Alaska Oil & Gas Cons. Commission
Anchorage
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R & R C 0 U R T R E P 0 R T E R S
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PRO C E E DIN G S
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CHAIRMAN JOHNSTON: I'd like to call this
3 hearing to session. The date is May 3, 1995, it's
4 approximately 1:30 in the afternoon. The location is 3001
5 Porcupine Drive, Anchorage, Alaska, and that is the offices of
6 the Alaska oil and Gas Conservation commission. The
7 proceedings will be recorded in this matter. Laurel Evenson,
8 of R & R Court Reporters, will be making the transcript of the
9 proceedings. Those people wishing to obtain a transcript, we'd
10 ask that you contact R & R Court Reporters directly to obtain
11 that transcript when it is available.
12 The purpose of the hearing is to examine well testing
13 procedures and allocation methodologies for pools commingled on
· 14 the surface and processed at the Lisburne Production Center.
15 If you'd like to make your motion.
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COMMISSIONER BABCOCK: Thank you, Mr. Chairman.
17 I'd like to move that the Notice of Public Hearing Re:
18 Commingled Production which was published March 31, 1995, be
19 entered into the record as Exhibit A.
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CHAIRMAN JOHNSTON: So moved. Any discussion?
21 Thank you. We'll accept that exhibit, and it is entered into
22 the record as Exhibit A.
23 The hearing will be conducted in accordance with
24 20 AAC 25.540. I think most everybody is familiar with those
25 proceedings, but essentially that allows us to take sworn
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1 testimony or unsworn statements. Sworn testimony will be
2 provided greater weight in the deliberations of the Commission.
3 As you testify, we ask that you state your name and who you
4 represent. If you wish to be considered an expert witness in
5 this matter, we would require you to state your qualifications
6 and then the Commission will rule as to whether we would
7 consider you as a witness in this matter.
8 The order of testimony, we will first have ARCO, as the
9 operator of the LPC, testifying first. I believe that will be
10 followed by a statement or comments from BP Alaska, and then
11 we'll move to state agencies. At the conclusion of sworn
12 testimony we will take unsworn statements or written comments.
13 Members of the audience may not ask questions directly of the
· 14 witness, but if you do have a question, we'd ask that you write
15 it down and forward it to the Commission. If we believe that
16 it's germane to the topic at hand we will then ask that
17 question.
18 Before I begin, I would like to make one announcement.
19 Yesterday the Commission received word from the legislature
20 that they have approved $80,000.00 for the Commission to
21 develop an allocation oversight program. Thus, at this time in
22 assuming this funding holds, the Commission does not see the
23 need to investigate the alternatives outlined in our notice.
24 Nevertheless, we do believe that proceeding with testimony will
25 be beneficial. We would appreciate your thoughts, for example,
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1 on the appropriate elements of Commission oversight, and we
2 would appreciate any updates that you care to provide the
3 Commission with the nature and extent of commingling, at least
4 from the operator's perspective. Should the state agencies
5 wish to parti~ipate or make a statement or testify, again, we
6 would appreciate your thoughts on any problems that you see or
7 any elements of a proper Commission oversight program.
8 So with that I would like to ask ARCO Alaska to appear
9 before the Commission.
COMMISSIONER BABCOCK: Would you put the mike
on your lapel, Mr. Oba?
CHAIRMAN JOHNSTON: And before you begin, I
just noticed here that I did want to enter into the record some
letters that we have received in this matter. Briefly what I
will do is indicate who they are from and the date of the
letter, and we can refer to them in that way.
We have a letter from a concerned citizen, it was
unsigned, dated April 9, 1995; we have a letter from ARCO
Alaska, dated April 13, 1995; we have a letter from Exxon
Company U.S.A., dated April 28, 1995; a letter from the Alaska
Department of Natural Resources, dated April 26, 1995; and a
letter dated -- or excuse me, from the Alaska Department of
23 Revenue, dated April 26, 1995. And I'd like to enter these
24 into the record as Exhibits B, C, D, E, and F.
25
COMMISSIONER BABCOCK: Mr. Chairman, I'd also
R & R C 0 U R T R E P 0 R T E R S
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1 like to enter into the record a letter dated April 21, 1995,
2 from the Department of Natural Resources, Division of oil and
3 Gas, which is addressed to Mr. Siekkinen, of ARCO Alaska.
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CHAIRMAN JOHNSTON: So that would be Exhibit G?
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COMMISSIONER BABCOCK: Right. I move that we
6 enter all those exhibits, B through G into the record.
7
CHAIRMAN JOHNSTON: Any discussion? Okay. So
8 moved and so done.
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CHAIRMAN JOHNSTON: At this time, Mr. Oba, if
10 you'd introduce yourself for the record, then we can proceed.
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MR. OBA: Okay. My name is Ronald Oba. I am a
12 supervisor for the Greater Point McIntyre Area Field Operations
13 Support Group, from ARCO Alaska. I received a bachelor of
· 14 science degr~u in mechanical engineering in 1972, and a master
15 of science degree in mechanics in 1974, from the University of
16 Colorado.
17 I have more than 20 years of experience in the
18 petroleum industry, working in the areas of production
19 research, operations engineering, reservoir engineering and
20 facility engineering. I've been working in Alaska since 1984.
21 My work efforts in Alaska have been directed towards the
22 development and production of the Lisburne, Pt. McIntyre,
23 West Beach, North Prudhoe Bay, Niakuk and West Niakuk
24 accumulations.
25 More ~pecifically relating to the subject of discussion
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· 1 here today, I've been continuously involved in the development
2 of the well test base production allocation methodology as it
3 is applied to production processed by the Lisburne Production
4 Center since the inception of the concept in late 1989.
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CHAIRMAN JOHNSTON: Thank you. No objection?
COMMISSIONER DOUGLASS: No objection.
COMMISSIONER BABCOCK: No objection.
CHAIRMAN JOHNSTON: Thank you, Mr. Oba. The
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9 Commission will accept you as a witness -- or an expert witness
10 in this matter. Please proceed.
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MR. OBA: Okay.
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COMMISSIONER BABCOCK: Sworn testimony?
CHAIRMAN JOHNSTON: Oh, that's right. I'm
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14 sorry. I assume you would like to be considered for sworn
15 testimony?
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19 hand.
MR. OBA: That's correct.
CHAIRMAN JOHNSTON: Okay.
COMMISSIONER DOUGLASS: Please raise your right
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(Oath administered)
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MR. OBA: That was my left hand.
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COMMISSIONER DOUGLASS: You don't have any
23 fingers crossed, do you?
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MR. OBA: No.
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CHAIRMAN JOHNSTON:
Let the record
. . . . .
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MR. OBA: Yes, I do.
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CHAIRMAN JOHNSTON: Let the record show that
3 Mr. Oba has been sworn.
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MR. OBA: Work on commingled production and
5 well test production allocation among fields was initiated in
6 1989. Since that time numerous meetings and discussions have
7 been held with the Alaska oil and Gas Conservation commission,
8 the Alaska Department of Revenue, the Alaska Department of
9 Natural Resources, and the Working Interest Owners; ARCO
10 Alaska, Incorporated, BP Exploration, and Exxon Company U.S.A,
11 to develop a mutually agreeable plan for the implementation of
12 well test based production allocations for fields producing
13 through the Lisburne Production Center, also known as the LPC.
14 Based upon the plan which will be summarized in a few
15 minutes, the Alaska Department of Revenue issued an advanced
16 tax ruling on February 28th of 1991 recognizing the value of
17 facility sharing and providing for the separate treatment of
production from Lisburne, Niakuk, and Pt. McIntyre fields for
severance tax purposes.
The Alaska Department of Natural Resources also
approved this methodology as part of its tract operation and
participating area approvals.
The details of this plan, as well as the supporting
technical and economic data, have been previously provided to
the Commission in public hearing testimony presented in support
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1 of the following conservation orders:
2 Conservation Order 311, covering the West Beach Field;
3 Conservation Order 317, covering the Pt. McIntyre Field;
4 Conservation Order 327, covering Niakuk Field; Conservation
5 Order 345, covering the North Prudhoe Bay Field.
6 Each of the above named conservation orders
7 incorporated this well test based production allocation
8 methodology in the field specific rules.
9 Since the commencement of commingled production
10 operations the the LPC on April 8th of 1993, numerous informal
11 technical meetings and discussions have taken place to address
12 issues identified by the various parties as they became
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13 familiar with the allocation process. In addition to the
14 monthly reports and informal discussions, formal periodic
15 reviews were held with the state agencies on February 1, 1994,
16 October 13th of 1994, and March 28 of 1995. In neither the
17 informal discussions nor the formal presentations has ARCO
18 received feedback of any fundamental concerns about the
19 methodology or its execution.
20 Turning to the methodology, I present Exhibit 1, (sic)
21 (Exhibit H) which lists the eight major components of the
22 methodology:
23
CHAIRMAN JOHNSTON: Mr. Oba, if you're going to
24 be using the overhead, the court reporter has asked that you
25 hold the mike up to your mouth as you speak.
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· 1 MR. OBA: Okay.
2 CHAIRMAN JOHNSTON: It's somewhat difficult for
3 her to get what you're saying down on tape.
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MR. OBA: Okay. I do have three hard copies
5 for you of the exhibits.
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CHAIRMAN JOHNSTON: Thank you very much. Okay.
7 And why don't we designate the ARCO exhibits as Exhibit -- what
8 are we, H now?
MR. OBA: Okay. This first exhibit shows the
eight major components of the methodology:
The first component is that we conduct two well tests
per well per month.
The second component would be that we review the well
test results for validity.
The third step is that we review significant production
events for each well.
Step four is that we calculate the theoretical monthly
production volumes for all wells in all fields.
The sixth step is that we calculate an allocation
factor which compares the sum of the theoretical monthly
production volumes for all wells in all fields to the total
sales volume as determined by a sales meter.
Step six -- okay, step six is shown on the top of this
page, and step seven, we calculate the allocated monthly
production volumes for each well as a product of the well's
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1 theoretical production volume times the allocation factor.
2 The final step is that we sum up the allocated
3 production volumes for each well in each field to determine the
4 amount of production derived from each field.
5 Now shown in my next exhibit (Exhibit I) we calculate
6 three allocation factors. One for oil, one for gas, and one
7 for water. Of these three factors, only two, the oil and gas
8 factors have any impacts on revenues. The same allocation
9 factor is applied to production from every field producing
10 through the LPC.
By the 20th of each month the operator files a monthly
report, both in hard copy format and electronic computer disk
format, containing the following information:
Well tests for all wells for the reporting month, plus
an additional 15 days; allocated production by well by day;
allocated production by field by day; well testing statistics;
and, finally, field allocation factors.
Shown in my next exhibit (Exhibit J), which shows
historical allocation factors since April of 1993, oil
allocation factors have been within 4 percent of a perfect 1.0,
and for most months are within less than 1 percent of the ideal
22 value. Gas allocation factors have been off by as much as 4
23 percent but are generally within 2 percent of the ideal value.
24 The water allocation factor has shown the most variation with
25 excursions as high as 24 percent being observed. Because no
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1 revenues are impacted the extent of the water variations has
2 not been a major concern to date, although we are continuing
3 attempts to improve upon this factor. We are confident that
4 the source of this water factor discrepancy is an inaccurate
5 meter value on our water disposal line rather than a problem
6 with the water cut measurements made during the well tests.
7 We base our belief on the source of the discrepancy in
8 the water factor on our knowledge about the particular meter,
9 and by our experience with water measurement at the Greater
10 Pt. McIntyre Area drill sites.
11 My next exhibit (Exhibit K) is a plot of water cut
12 meter values versus shakeout sample values for a continuous
13 water cut meter installed on Lisburne Drill site L3. This plot
·
14 is representative of the very tight correlation that we observe
15 between the water cut meter output values and the shakeout
16 sample values at all of the test facilities in the Greater
17 Pt. McIntyre Area. You will notice that the fit 'is extremely
18 good over the entire range from 0-100 percent water. This
19 independent verification of the measurement accuracy of the
20 water cut meters over a substantial length of time, coupled
21 with the continuous measurement of water cuts during the entire
22 well test period leads us to our confidence in the well test
23 based water volumes. In contrast we have experienced a number
24 of difficulties in obtaining reliable disposal water volume
25 measurements.
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19
20
21
22
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12
1
To date the owners have spent over $3 million to
2 upgrade our metering facilities to conform with industry
3 recommended practices, we have tightened up our maintenance
4 procedures, improved the consistency of our well testing
5 procedures and production event histories, and we've increased
6 manpower dedicated to production allocation beyond levels
7 normally utilized for reservoir management purposes.
8 Relative to oversight and the checks and balances we
9 have incorporated into the well test based allocation process,
10 I would offer the following observations:
11 First, since well testing is the foundation of the well
12 test based production allocation methodology, a number of
13 parties with competing interests are motivated to insure that a
14 proper balance between accuracy and efficiency is achieved.
15 Second, we have at least eight ARca Alaska people who
16 are examining the well test information to ensure that valid
17 tests are being obtained. This number includes a drill site
18 operator who places a well into test, his day or night shift
alternate, the day and night shift drill site operators on the
alternate weekly shift, two drill site supervisors who oversee
the work of the drill site operators, our field engineers, and
finally our allocation engineers.
In addition to this ARca activity, I am also aware that
BP has two people watching over the well testing results and
activities and Exxon also has a similar resource commitment.
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1
Therefore, at least 12 people representing companies
2 with disparate interests scrutinize these well tests.
3 Furthermore, as we have -- furthermore, we have
4 purposely attempted to make the allocation process as simple
5 and straightforward as possible. We have intentionally tried
6 to limit the amount of user discretion that can be exercised ~
7 the allocation engineer. That is why, for instance, we have
8 used straight line step function rate changes from well event
9 to well event rather than a curve fit or productivity index
10 driven routine. Again, we have multiple ARCO Alaska people
11 reviewing this part of the process to ensure that the
12 allocations are being conducted according to this simple plan.
13 BP and Exxon also monitor this part of the allocation process
·
14 very closely.
15
The state also dedicates a significant amount of
16 resources monitoring the production allocation process. My
17 understanding of the state's surveillance activities to date
18 are as follows:
19 First, the AOGCC receives a hard copy and a computer
20 disk copy of the monthly allocated production information from
21 ARCO, loads the information onto a computer system, and has a
22 technical staff person review the results.
23 The Alaska Department of Natural Resources receives a
24 copy -- a hard copy and a computer disk copy of the monthly
25 allocated production from ARCO, also loads the information onto
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1 a computer system, and has a technical staff person review the
2 results.
3 Third, the Alaska Department of Revenue also receives a
4 hard copy of this data as well as a computer disk copy. The
5 monthly allocated production information, and turns this data
6 over to an outside consultant for review.
7 While I recognize that not all of the issues on well
8 test based production allocation are technical in nature, I
9 believe that the accuracy of the allocation process will not be
10 improved by committing additional state resources.
11 To our knowledge, all the parties are satisfied that
12 fair, effective, accurate allocation of production is taking
·
13 place for all fields producing through the LPC. Therefore, we
14 believe that the interests of all of the parties are best
15 served by continuation and refinement of the current
.
16 implementation of the well test based production methodology.
17 As all of the parties become more comfortable with the process,
18 streamlining of the reporting requirements and the adaptation
19 of the methodology to other fields will be appropriate actions
20 to maximize recovery of oil and gas resources in the state of
21 Alaska.
22 Let me close with the following analogy between well
23 test based production allocations and telephone communications.
24 Single field production streams, processed and metered
25 separately for custody transfer are analogous to old telephone
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1 systems that depended upon the transmittal of continuous analog
2 signals in order for conversations to take place. The well
3 test based production allocation methodology we have been
4 discussion today, similar to the latest digital communications
5 technologies which sample an analog signal at discrete points,
6 transmit those discrete digital data points and then
7 reconstruct the original signal. Just as we have been able to
8 convert using reéonstructed digital telephone communication
9 signals on a routine basis, we are able to accurately and
10 effectively allocation production back to multiple fields via
11 our twice monthly digital sampling of well production. Just as
12 we are comfortable with digital technology in our
13 communications world, we see no reason for any discomfort with
·
14 well test based production allocations. To the contrary, we
15 believe that our experiences with the methodology have
16 demonstrated the wisdom of the various state agencies that
17 approved this methodology in the Greater Pt. McIntyre Area.
18 The methodology has proved its promise as a necessary and
19 reliable technology for use in the oil industry in the state of
20 Alaska.
21 This completes my prepared testimony, and I thank you
22 for your attention.
23
CHAIRMAN JOHNSTON: Thank you, Mr. Oba. On
24 your chart on page 3 of your submittal, how would you
25 characterize the test separator accuracy as it pertains to oil
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1 and gas? This is page 3 which shows the .....
2
COMMISSIONER BABCOCK: Mr. Chairman, he
3 referred to these as separate exhibits.
4
CHAIRMAN JOHNSTON: Okay. I'm sorry. I was
5 looking at the Roman numeral number III at the bottom of the
6 page.
7
COMMISSIONER BABCOCK: So I would just move on
8 the Roman numeral II be Exhibit Ii III, Exhibit Ji and IV,
9 Exhibit K.
10
CHAIRMAN JOHNSTON: Okay.
11
COMMISSIONER BABCOCK: That's how they were
12 referred to in his testimony.
13
CHAIRMAN JOHNSTON: Okay. How would you
·
14 characterize your test separator accuracy or your allocation
15 accuracy as it pertains to gas and oil on this chart?
16
MR. OBA: I think reflected in this particular
17 chart we have the oil and gas allocation factors. I think
18 looking at it historically, during the early discussions some
19 of the concerns were that those values might be as high as 10
20 or 15 percent, which was typical for reservoir management
21 purposes, and during the discussions a lot of the focus was
22 trying to ensure that those allocation factors would be in say
23 the 5 percent range -- plus or minus 5 percent. I think what
24 you see demonstrated here is that we have been well with the
25 plus or minus 5 percent region. In fact are within -- in many
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1 cases with a percent of the ideal value. So I'd characterize
2 it overall is that we have done extremely well in allocating
3 production, and I believe we've exceeded the regional
4 expectation of all the parties.
5
CHAIRMAN JOHNSTON: Thank you. Exxon, in its
6 letter to us, referred to an audit of the allocation procedures
7 which occurred in November of 1994. Apparently ARCO, Exxon and
8 BP participated in that audit. Are you familiar with this
9 audit?
10
MR. OBA: To some degree. It was not an audit
11 per se of the allocation methodology, but it did involve our
12 measurement procedures and processes which are a key driver to
·
13 this overall allocation process. And we routinely have these
14 joint company reviews of our measurement process and procedures
15 to ensure that the three companies are satisfied that industry
16 standards are being followed, proper procedures are being
17 implemented.
18
CHAIRMAN JOHNSTON: So you see that this audit
19 was called as just a routine matter in the allocation process?
20
MR. OBA: I see it as .....
21
CHAIRMAN JOHNSTON: Or I guess why was the
22 audit called?
23
MR. OBA: As I said, on a routine basis we
24 conduct these audits. I think there was definitely some
25 additional incentives to scrutinize how we made our
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1 measurements at each one of the drill sites because of the
2 revenue implications of those measurements. And so I would see
3 this audit as being very much a part of the operators, the
4 Working Interest Owners' concern and desire to make sure that
5 accurate allocation is taking place.
6
CHAIRMAN JOHNSTON: Can you share with us what
7 the audit revealed?
8
MR. OBA: The audit revealed basically that the
9 procedures, the processes that -- measurement processes that
10 were in place were appropriate, did flag a couple of areas
11 where we needed to improve some of our record keeping, but as I
12 recall, just off the top of my head, those were the main
13 findings of that audit.
14
CHAIRMAN JOHNSTON: Was a report prepared?
15
MR. OBA: Oh, I would have to go back and check
16 the records.
17
CHAIRMAN JOHNSTON: If you would, I would
18 appreciate that, and I guess I'd also as if the parties do not
19 have any objections, the Commission would appreciate receiving
20 a copy of that report. Do you have plans or do the Exxon, ARCO
21 and BP have plans to conduct further audits?
22
MR. OBA: Yes. As I said, we, on a routine
23 basis, conduct these type of audits, and we would continue to
24 do those type of audits in the future.
25
CHAIRMAN JOHNSTON: Would you have any
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1 difficulty inviting the Commission to observe the audit process
2 and actually be a participant in the audit process?
3
MR. OBA: No, I don't see any problem with
4 that.
5
CHAIRMAN JOHNSTON: Moving on to slightly --
6 oh, when do you think the next audit will be?
7
MR. OBA: Since we just completed the current
8 one, I would anticipate that it would be something on the order
9 of probably one to two years before we do that.
10
CHAIRMAN JOHNSTON: Thank you. How do you
11 ensure that the well testing guidelines, such as stabilization
12 time, test duration and test frequency, are followed and that
13 the wells are tested at uniform intervals?
·
14 MR. OBA: Okay. As I indicated, we have done a
15 certain amount of training with our drill site operators. They
16 are the primary sources of initiating the test and have the
17 primary responsibility for ensuring that we are getting valid
18 tests. We also -- as the data is recorded when we take the
19 test it is possible for the operator that has run the test plus
20 the other operators that have indicated to review that data as
21 it's coming in to constitute a test, they're able to review
22 that information. Our field engineers can pull up and do pull
23 up that data and look at it. We have our allocation engineers
24 look at that, the flow rates that comprise that well test, and
25 so we can look at the performance -- flow performance of the
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1 wells as the test is being run, and from that data we can tell
2 whether or not the wells have stabilized or not.
3
CHAIRMAN JOHNSTON: So basically you're saying
4 each well would have a different characteristic in that they
5 would not necessarily have a uniform stabilization time for all
6 wells, that each well would have a different characteristic,
7 and you would try and identify that .....
8
MR. OBA: Tha·t' s correct.
9
CHAIRMAN JOHNSTON:
. . . . .
and communicate those
10 different needs to the individuals that are conducting the
11 test?
12
MR. OBA: Right. From a practical standpoint,
·
13 we look at the wells and put 1them into different performance
14 categories in terms of how quickly the well stabilized in test,
15 how long they need to test, factors such as how much the well
16 slugs, for example, will determine how long we need to keep the
17 well on test in order to get a representative test. So what we
18 will do is look at every well that produces through the LPC for
19 that type of performance behavior, and before the well is put
20 into test, we will make sure that the drill site operator has
21 some idea of what the stabilization period should be for that
22 period, how long should the test duration be, and then as the
23 test is being run or as the data is finalized and pulled of the
24 system we will again scrutinize the information to make sure
25 that we indeed had a stable well before we started a test and
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1 the duration was long enough.
2
CHAIRMAN JOHNSTON: So are these guidelines and
3 procedures written up someplace?
4
MR. OBA: Yes, they are.
5
CHAIRMAN JOHNSTON: Is that something that you
6 can share with us as well?
7
MR. OBA: We could do that.
8
CHAIRMAN JOHNSTON: Thank you. What is the
9 state of multiphase metering?
10
MR. OBA: I think there have been continuous
11 attempts to increase the accuracy of multiphase metering. My
12 evaluation of where the technology stands right now is that the
13 accuracy of three phase metering per se is not up to the
·
14 standards of what we would want for custody transfer purposes.
15 You can get to some things equivalent to multiphase metering,
16 but true multiphase metering is not a viable technology right
17 now.
18
CHAIRMAN JOHNSTON: Are there any testing being
19 done anywhere with multiphase metering?
20
MR. OBA: There is not, that I've been directly
21 involved with. I know there are other companies in the
22 industry that continue to work that. We continue to look at
23 that capability at a research lab, but in terms of something
24 that's out in the field, is operational, I'm not aware of
25 anything.
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1
CHAIRMAN JOHNSTON: Do you see any effort on
2 the part of ARCO, as the operator of the LPC, to move in that
3 direction to actually doing their own tests of multiphase
4 meters and seeing how they actually do work in Alaska?
5
MR. OBA: We continue to pursue the acquisition
6 of a good multiphase metering system. We have some concepts
7 that we are currently pursuing that I would term more what oil
8 metering than multiphase metering per se, which will accomplish
9 the same thing that as an approach probably offers something
10 that would come to fruition quicker than true multiphase
11 metering.
12 So the short answer to your question is, yes, we
.
13 continue to pursue that type of technology. We just do not
14 feel at this point in time that it's far enough along that it's
15 appropriate to implement it.
16 CHAIRMAN JOHNSTON: I understand that the
17 technology is in its infant stages. I was just kind of curious
18 as to what ARCO's efforts were along those lines to further
19 this technology along.
20
MR. OBA: I guess the best thing I can say is
21 we continue to get the technology.
22
CHAIRMAN JOHNSTON: The letter that ARCO
23 submitted to the Commission in response to this hearing
24 indicated that you had consulted, at least informally, with
25 other state agencies and found that no fundamental concerns
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1 existed among the agencies with procedures. What do you mean
2 by fundamental?
3
MR. OBA: I would characterize that as, you
4 know, are there basic flaws in the methodology, are there some
5 systematic errors in what we're doing, you know, are we missing
6 some significant factor in this process, are there concerns
7 that major errors are being committed.
8
CHAIRMAN JOHNSTON: Are you aware of any
9 dissatisfaction that may exist with the state agencies?
10
MR. OBA: As things currently stand, no, I
11 don't.
12
CHAIRMAN JOHNSTON: Do you feel that industry
13 has been given certainty relative to state support -- state
·
14 agency support for the allocation process?
15
MR. OBA: In terms of black and white, yes or
16 no, it's a report on whether the results have been acceptable
17 or not. I don't believe that we have received consistent or
18 clear answer.
19
CHAIRMAN JOHNSTON: What do you think is
20 lacking there?
21
MR. OBA: I think what is lacking is any --
22 what I would get to is that, you know, we have not received in
23 writing, for example, that the allocation process is working or
24 that the results indicated by the allocation factors that we
25 have posted are acceptable. We've gotten lots of verbal
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15
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1 communication indicating that things appear to be working
2 properly, that people are getting comfortable with the process,
3 but we've never gotten anything in writing stipulating that we
4 are satisfied with the way the process is going.
5
CHAIRMAN JOHNSTON: And have you checked with
6 the other .....
7
COMMISSIONER BABCOCK: Excuse me, Mr. Chairman.
8 You mean from the Department of Revenue, because it appears to
me that you have received a comment to that effect from the
Department of Natural Resources and a letter signed by
Ken Boyd.
MR. OBA: Yeah. I stand corrected on that in
terms of we did get the recent communication from DNR, and that
really has been the most -- up until that point that was a very
definitive statement, and I stand corrected in not
acknowledging that.
COMMISSIONER BABCOCK: Okay.
CHAIRMAN JOHNSTON:
Thank you for
. . . . .
19
COMMISSIONER BABCOCK: Go ahead. Excuse me
20 for .....
21
CHAIRMAN JOHNSTON: Yeah, I thought that was
22 important. Have you checked with the other minority Working
23 Interest Owners and are they satisfied with these processes?
24
MR. OBA: We have had the discussions with our
25 partners in this project and we have received their assurances
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1 that they are satisfied with the way the process is working
,2 with the accuracy of the results.
3
CHAIRMAN JOHNSTON: And have they -- you say
4 that you've received their assurances. Have you received clear
5 written statements from them similar to what you were alluding
6 to, that it was lacking at least on the part of certain state
7 agencies?
8
MR. OBA: I think, if I recall correctly, there
9 is a letter that Exxon submitted to the Commission indicates
10 that, so we do have that in writing. Right now I can't, off
11 the hand, recollect that we have anything in writing from BP to
12 that effect.
13
CHAIRMAN JOHNSTON: What about the smaller
· 14 owners? Is there any other owners besides -- okay, I guess I'm
15 thinking of Prudhoe Bay. So we're just talking in all of the
16 fields being commingled through the Lisburne Production Center
17 basically the owners as being the BP, ARCO, Exxon and DNR?
18
MR. OBA: And the state, that's correct.
19
CHAIRMAN JOHNSTON: Do you have any questions?
20 Any questions there, Tuckerman?
21
COMMISSIONER BABCOCK: Well, yes. Mr. Oba,
22 would you explain a little bit to me how the allocation figure
23 for gas is determined, at what stage in the process as the
24 disposition is broken down between flared and used for lease
25 purposes and reinjected and sold? At what point does the
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1 allocation measurement come into play, is it right after the
2 process
right after the separation before any gas is flared
3 or used for lease purposes or does it come after that point?
4
MR. OBA: Okay. Looking at this exhibit that
5 shows the equation of how we calculate the gas factor, as our
6 facilities are set up there is no single meter that measures
7 all of the produced gas, one single meter, so we have to do it
8 by summing up the values measured by several different meters,
9 those being the LPC fuel gas, the injected gas, and our drill
10 site fuel gas. From that total we would subtract off drill
·
11 site lift gas usage and then we also add into the total
12 produced gas volume gas shrinkage that is associated with the
13 production of our NGLs, gas that was used for flare assist,
14 which is a metered value. Then we do have to estimate how much
15 gas has been flared, and that number is included in the
16 produced gas number. We also have the ability to use Prudhoe
17 fuel gas at our facilities, so we need to take that off on our
18 field. We need to take that off on our fuel. It's basically a
19 deduction off the LPC fuel number. So that gives us the total
20 gas volume produced, and that is compared to the gas rates that
21 we get out of all of our well tests.
22
So I can't give you a real clear answer. You know,
23 does all of this flared gas come in before or after we do the
24 allocations, it's very much a part of -- included in the
25 calculation of the gas allocation factor. Now, in terms of the
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1 breakout of the flare gas volumes to the specific fields, if
2 that's your question, then that is driven by the produced gas
3 volumes that we've allocated to each of the fields.
4
COMMISSIONER BABCOCK: No, that part -- that
5 part I understand. Well, in looking at that the only estimated
6 section is the flared gas?
7
MR. OBA: That's correct.
8
COMMISSIONER BABCOCK: Well, this -- I have a
9 letter from October 5, 1994 from A.D. Simon regarding an
10 underestimation of 250,000 cubic feet a day, and what I was
11 curious about, how any underestimation of the gas sent to flare
12 could occur if all the other disposition of gas is metered?
·
13 MR. OBA: Okay. What we found is that part of
14 the volume we typically include in the flare volume includes
15 gas that is leaking through some of the control valves for our
16 gas system in the plants, basically. And so we had this
17 leakage which -- through some valves that is unmeasured, and
18 what we had to -- we realized as we did a review of our
19 reporting of flare volumes that there was an uncounted -- this
20 leakage volume was basically unaccounted for. And so what we
21 had to do is go back and trace how far back this situation
22 went, and it ended up being that it essentially started at the
23 time that the LPC was brought up, that we had this issue of
24 leakage through some of these valves. What we then did is ran
25 some tests to try to estimate what the leakage volumes would
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19
20
21
22
23
24
25
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28
1 be. Again, they aren't values that we have a way of metering.
2 And so we did some testing to determine what those values are.
3 Those are the values that are reported in Mr. Simon's letter
4 and would be now included in our estimated flare volumes in our
5 monthly reports. But, again, a part of what we're looking at
6 there is a relatively small volume compared to what you
7 typically have as volumes that end up being flared.
8
COMMISSIONER BABCOCK: I'm just curious as to
9 how that gas had been reported prior to discovering that it was
10 being flared. In other words, if the other -- all the other
11 categories are metered, there's only one that is estimated, how
12 did the reconciliation occur; how does that occur in -- how
13 would you over-report metered gas in other words? That seems
14 to be one of the alternative explanations is that metered gas
15 was over-reported. So I'm just -- in establishing the total
16 amount of gas produced you, rather than knowing that from
17 production reports, you know that from your disposition report.
MR. OBA: I think that the one unknown there is
that flared volume.
COMMISSIONER BABCOCK: Uh-huh.
MR. OBA: And, again, we estimate that volume,
we do not measure it, and I think that, you know, we are
confident that the values that we may meter in all these other
areas are accurate values, so the only area that we do have any
uncertainty in is that flare volume, and it had to be occurring
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1 in that flare volume.
2
COMMISSIONER BABCOCK: Well, I guess what I'm
3 driving at is if you meter all the other disposition of gas,
4 whatever is left over had to go to flare unless your meter --
5 you have a meter factor error. So the flare doesn't
6 necessarily have to be estimated, it's just whatever is left
7 over. You might estimate what caused different elements of
8 that . . . . .
9
10
11 flare.
12
13
· 14 of the . . . . .
15
MR. OBA: No, .....
COMMISSIONER BABCOCK: ..... gas to be sent to
MR. OBA:
okay.
What
. . . ..
COMMISSIONER BABCOCK: Unless I'm missing one
MR. OBA: Okay. What that assumes is that you
16 know what the total volume of produced gas is, which we don't
17 know. The way we -- because we don't know it because we don't
18 measure it. Now, the best estimation of what that is, we go
19 through this process of adding up all of the metered values and
20 deducting metered values, plus we estimate what our flare
21 volume was, and we add all of those numbers up and that is what
22 we carry as our produced gas volume. And the reason -- you
23 know, if we had that total produced gas volume metered at one
24 point we could do what you're saying, and we would have some
25 closure there on the measurement. But the way we have our
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1 system set up, we do not get that one -- one single metered
2 value.
3
COMMISSIONER BABCOCK: I'm not familiar with --
4 on your oil factor what the unrecoverable oil means.
5
MR. OBA: Okay. There are certain times when
6 we will pump some -- take some crude and pump it down a well --
7 in a well operation, and the part that we get into it,
8 sometimes as we go past month-end boundaries we may have pulled
9 some or on a daily basis when you look at it you pull out some
10 crude for -- we'll call it well operations. So those values
11 aren't reported in say the TAPS volume, but they were produced
12 during that day.
13
COMMISSIONER BABCOCK: You mean using produced
.
14 oil for lease operations?
15
MR. OBA: Right. For example, if we want to go
16 hot oil a well we would pull some of that oil out of the
17 process screen and go inject it back into the well, and so when
18 we -- we try to bring some closure to all the numbers, we need
19 to account for that volume, and usually that will tend to even
20 itself out over a longer period 'cause you tend to get most of
21 that oil back.
22
CHAIRMAN JOHNSTON: Could you give us a
23 thumbnail sketch of the changes that have occurred in the LPC
24 since the well testing allocation process was originally
25 approved under what I believe was the West Beach Pool Rules?
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1
MR. OBA: Okay. Well, from a mechanical
2 standpoint, one of the biggest things we've ended up doing at
3 the LPC, we had some piping within the plant that as we raised
4 the production rates there were some vibrations of those lines,
5 and we added some bracing support to those lines to prevent the
6 vibrations of those lines. We've also rearranged some of the
7 front-end vessels, in particular our produced water drums and
8 our treater flash drums. We've added a second treater flash
9 drum basically to the process to give us some additional
10 capacity in the plant. We have also added a produced water
11 module to the facility to handle produced water in anticipation
12 of water flood breakthrough taking place at Pt. McIntyre and
13 Niakuk. But in terms of the oil processing stream, that's kind
·
14 of off to the side.
15 Other than that we've done very small valve changeouts.
16 We've changed some trims, we've rearranged controllers, worked
17 on the control schemes at the plant. We've also put in some
18 bigger impellers in our shipping pumps so we can move more
19 crude out the sales line on the back end of the plant.
20 So it's been a lot of what I would term relatively
21 minor changes and additions.
22
CHAIRMAN JOHNSTON: In terms of your total
23 throughput in the LPC, has that changed?
24
25
MR. OBA: Yes, considerably. You know, prior
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1 to West Beach coming in, I'd have to go back and look at the
2 exact production numbers, but we were producing in the 25 to
3 30,000 barrel a day range out of Lisburne. We've got -- have
4 gotten some healthy increases with West Beach, North Prudhoe
5 and finally Pt. McIntyre coming on line. So, you know, we're
6 operating the plant in say 180,000 barrel a day range, so
7 there's been a significant increase in the throughput rate of
8 the facility.
9
CHAIRMAN JOHNSTON: Of that 180,000 can you
10 break that down as from -- by field, by pool?
11
MR. OBA:
Oh, you're going to test
. . .. .
12
CHAIRMAN JOHNSTON: Just ballpark.
13
MR. OBA: ..... me here. Roughly, okay,
·
14 Lisburne makes about 20,000 barrels a day; Pt. McIntyre is
15 making about 137,000; Niakuk is making 23,000; and -- so that's
16 about 180, and we have roughly 4,000 out of the North Prudhoe.
17 CHAIRMAN JOHNSTON: And what about . . . . .
18 MR. OBA: West Beach is shut-in.
19 CHAIRMAN JOHNSTON: Shut-in right now.
20 MR. OBA: So, hopefully, that's somewhere close
21 to 180.
22 CHAIRMAN JOHNSTON: And the Stump Island, I
23 presume, is incorporated in the Pt. McIntyre?
24
MR. OBA: That's correct.
25
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1
CHAIRMAN JOHNSTON: Any further questions?
2
COMMISSIONER DOUGLASS: No.
3
CHAIRMAN JOHNSTON: Tuckerman?
4
COMMISSIONER BABCOCK: I'm still wrestling with
5 how -- if the gas isn't all metered how does it meet the
6 commingled rule? For example, I'm just looking at Niakuk's
7 rule in Conservation Order 329 where it says that you shall
8 determine an allocation factor as the ratio of the metered
9 volume to the total monthly production for all wells in all
10 pools, and I don't know if that's -- is that really being
11 accomplished with the process that you have now, that
12 specific -- I'm not saying the process that you have now
13 doesn't accomplish an allocation, I'm just wondering if it
·
14 meets the precise language of determining an allocation factor
15 as the ratio of the metered volume to the total monthly
16 production for all wells in all pools.
17
MR. OBA: What I would -- I'd have to go all
18 the way back to the discussions and the testimony we presented
19 back for the West Beach rules because at that time, I think, we
20 took a great deal of pains to make sure that everybody
21 understood how we were coming up with our total produced gas
22 volumes at that time, and it included the fact that there were
23 going to be metered values -- a number of metered values that
24 are added together plus there was this flare volume that we
25
physically could not measure,
. . . . .
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21
22
23
24
25
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34
1
COMMISSIONER BABCOCK: Uh-huh.
2
MR. OBA: ..... and that that was going to be a
3 part of that produced gas volume. And I'm fairly confident
4 that that was also presented in the North Prudhoe Bay and on
5 the Pt. McIntyre, in those testimonies. I'm not that familiar
6 with exactly what was presented in all of the Niakuk testimony,
7 but I would say that the intent of the Niakuk testimony and the
8 process that we implemented for Niakuk was along those same
9 lines as what we had proposed for the other fields.
10 COMMISSIONER BABCOCK: I just want to make sure
11 we're not ordering you to do something in a conservation order
12 that you're not capable of doing. Would you explain some of
13 the problems that you've encountered and corrected?
14
MR. OBA: Sure.
15
COMMISSIONER BABCOCK: There's a couple of
16 those that we went over in our March meeting.
17
MR. OBA: Sure. I think one of those that
18 we've had that has caused some additional work was relating to
19 NGLs. As part of the process for allocating NGLs we need to
20 determine what the individual field yield factors are. When we
started West Beach production, in particular, we had some
problems there in that we did not have West Beach oil and gas
compositional samples to be able to determine a yield factor
for them. So what we did was started running the calculations
with the assumption that the field factors for West Beach would
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1 be similar to those for -- or that the West Beach yield factor
2 would be similar to those that we had for Lisburne, and we ran
3 those numbers. It took us some time to get that information
4 back, and when we did get it back we found that the yields were
5 higher for West Beach, and that caused us to go back and
6 recalculate some numbers, which we have done. And so that
7 caused us to revise some of the reported numbers.
8 Another area that we've identified and worked was with
9 the phase dynamics water cut meters themselves. And the issue
10 first really came to the forefront when we brought Pt. McIntyre
lIon production. Those wells have extremely low water cut, and
12 we were --.we observed some very low -- while we were recording
·
13 some 2 and 3 percent water cut numbers at Pt. McIntyre our
14 shakeouts and Karl Fischer titrations were saying that the
15 water -- produced water amounts were much smaller, and we had
16 to track down what the cause of that discrepancy was. It
17 turned out that in the calibration process of the water cut
18 meters at the factory they were using different API gravity
19 oils. And it turns out that the API gravity of the fluid does
20 have some small impact on the water cut measurement at very --
21 very low, you know, 1 to 2, 3 percent water cut range. So what
22 we ended up implementing was a field check calibration
23 basically between our shakeout and Karl Fischer titrations and
24 what the meters were outputting as their signal. And so we
25 have corrected that, and that is part of the data I showed on
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· 1 the phase dynamics versus shakeout sample there for -- exhibit
2 for drill site 3 was that it's that type of check that we now
3 make on a regular basis to make sure that there is a good time
4 between the meter values and what shakeout can give us.
5 So those are representative examples of things that we
6 have learned as we've gone along, and we've done our best to
7 flag these issues as early as we possibly can to be very
8 forthcoming with what we see and what we see as the appropriate
9 fixes to those issues.
10
COMMISSIONER BABCOCK: No further questions at
11 the moment.
12
CHAIRMAN JOHNSTON: Thank you, Mr. Oba. We
·
13 have no further questions right now, although we do reserve the
14 right to call you back again if the need arises.
15 Someplace there is a sign-in sheet that's been
16 circulating. Can we get it forwarded up here? Has everybody
17 signed the sign-in sheet? Thank you.
18
I guess our next guest to have the pleasure of
19 addressing the Commission is the BP representative. And before
20 we proceed, do you have any idea of how long your testimony is
21 going to be today?
22
MR. JAMES: It's fairly short. It's about one
23 page single spaced.
24
CHAIRMAN JOHNSTON: Okay. Well, maybe we can
25 go through your testimony and then take a short break
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1 afterwards.
2
MR. JAMES: Sounds good.
CHAIRMAN JOHNSTON: If you'd like to identify
3
4 yourself for the record, please?
5
MR. JAMES: Okay. My name is Bob James, and I
6 work for BP Exploration Alaska Incorporated. I graduated with
7 a master's degree in petroleum engineering in 1977 from the
8 University of Missouri at Rolla. I have 18 years' experience
9 in the industry; 15 of experience is with BP Exploration, and I
10 have been working in the Greater Pt. McIntyre Area in reservoir
11 engineering/production engineering matters since 1991, and I
12 have been involved with production allocation in the Greater
13 Pt. McIntyre Area mostly over the last several years.
·
14
CHAIRMAN JOHNSTON: Thank you. We'll accept
15 you as an expert witness in this matter. Do you wish to
16 provide sworn testimony?
17
MR. JAMES: Yes, I do.
18
COMMISSIONER DOUGLASS: Would you raise your
19 right hand?
20 (Oath administered)
21
MR. JAMES: Yes, I do.
22
CHAIRMAN JOHNSTON: Now, I did notice that the
23 BP representative got the right hand. Thank you.
24
MR. JAMES: My name is Bob James. Today I
25 would like to testify on behalf of BP Exploration Alaska
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1 regarding the allocation of produced fluids from fields in the
2 Greater Pt. McIntyre Area.
3 BP is a working interest owner in the Lisburne,
4 Pt. McIntyre and Niakuk fields in the Greater Pt. McIntyre
5 Area. These fields, along with North Prudhoe Bay state, and
6 West Beach have been approved for well test based production
7 allocation by the state of Alaska for severance tax, royalty
8 and reservoir management purposes, as well as by the three
9 Working Interest Owners, BP, ARCO and Exxon.
10 Well test based production allocation began with the
11 start of production from West Beach state Number 4 on April
12 1993. BP took on a new role in the Greater Pt. McIntyre Area
13 as operator of Niakuk when production began in April 1994.
·
14 since April 1994 BP has monitored Niakuk well performance and
15 well test operations performed by ARCO as LPC and drill site
16 operator. BP monitors the testing program in our Anchorage
17 office and works with ARCO to ensure that valid tests are being
18 obtained to meet the approved allocation process. In addition,
19 BP has met with ARCO on a monthly basis to review the tests in
20 an effort to ensure that production is allocated correctly to
21 Niakuk.
22 outside of Niakuk BP monitors production allocation
23 more broadly. We review the results of the allocated
24 production reports on a monthly basis and pay most attention to
25 the allocation factors, test separator utilization and number
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·
1 of well tests obtained. In addition, we have relied on the
2 regularly scheduled informal reviews with the state, ARCO and
3 Exxon to keep aware of any other concerns from other parties.
4 To date we do not believe there have been any other significant
5 criticisms raised with the allocation process.
6 As we have expressed at those review meetings, we
7 believe the allocation process has been implemented and
8 approved -- as approved and offers proper precision and
9 verification opportunity. Based on our monitoring to date the
10 process has been working as it was envisioned to allocate
11 produced fluids as accurately as possible to the individual
12 field. We further believe ARCO has worked hard to implement
13 the allocation process as approved and has attempted to conduct
·
14 well tests in a fair and unbiased manner and will continue to
15 do so in the future.
16 BP will continue to monitor the allocation process in
17 the future and in our role as Niakuk operator. We will also
18 continue to work directly with ARCO on Niakuk well tests to
19 ensure their validity and proper allocation of produced fluids
20 to Niakuk.
21 Thank you for giving BP the opportunity to testify at
22 today's hearing.
23
COMMISSIONER BABCOCK: Mr. James, were you ever
24 involved with the audit that was referred to earlier taking
25 place or concluding in November of last year?
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1 MR. JAMES: I was not personally involved in
2 the audit, and in fact it was initiated out of our Cleveland
3 office for BP, but BP was involved in the audit.
4 COMMISSIONER BABCOCK: Were there any
5 significant concerns that you are aware of in that audit?
6
MR. JAMES: To my knowledge, as ARCO testified,
7 there were some minor concerns, and I don't recall exactly what
8 they were at this time, but they were not -- they did not
9 register with me as being anything of significance, and I
10 believe that the audit concluded that things were largely
11 satisfactory.
12
COMMISSIONER BABCOCK: No further questions at
13 this time, Mr. Chairman.
14 CHAIRMAN JOHNSTON: Does BP witness the actual
15 test itself?
16
MR. JAMES: We do not witness the tests on the
17 North Slope, no.
18
CHAIRMAN JOHNSTON: So basically what your
19 review consists of is just looking at the data that has been
20 produced?
21
MR. JAMES: Right. We have electronic access
22 to the well testing as it occurs, and we review the actual well
23 testing and the results, and also have dialogues with the
24 operators and others involved in the well testing procedure.
\
25
CHAIRMAN JOHNSTON: If you do not witness the
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1 actual test itself how do you obtain certainly that the test is
2 being properly conducted?
3
MR. JAMES: We rely on the operator, I guess
4 you would say, in trust and in good faith that they are in fact
5 conducting the test as they represent that they are. We also
6 are able to see enough of the actual well test data that I
7 believe we have reasonable assurances that they are in fact
8 being conducted in that manner.
9
CHAIRMAN JOHNSTON: And what specifically do
10 you look at to give you this level of assurance?
11
MR. JAMES: We can look at the actual tests
12 while they're being conducted as far as the various parameters
13 while the well is in the separator; pressure, I believe we can
14 see temperature and parameters along those lines.
15
CHAIRMAN JOHNSTON: So that data is sent
16 directly to BP's offices?
17
MR. JAMES: Yes, it is.
18
CHAIRMAN JOHNSTON: So you can monitor it in
19 Real Time then?
20
MR. JAMES: Right.
21
CHAIRMAN JOHNSTON: Interesting. Do you have
22 any questions? Any questions? Okay, the individuals
23 monitoring this stuff, how would you characterize their
24 expertise or level of training?
25
MR. JAMES: I have two engineers that work for
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1 me, production engineers, that also have responsibilities for
2 other production engineering matters. One of the two engineers
3 has a fair degree of experience in field operations as well as
4 production operations. He knows a fair amount about well
5 testing procedures and diagnostics of well tests, et cetera.
6 My other engineer is not as experienced and is not really the
7 principal person that gives us assurances that the well test is
8 conducted in a satisfactory manner.
9
CHAIRMAN JOHNSTON: Do you think BP would be
10 comfortable with this procedure if you were not monitoring this
11 data in Real Time?
12
MR. JAMES: That's a difficult question to
13 answer, I guess, but one of the things that has evolved over
· 14 the past year and a half since we have been observing these
15 well tests is a comfort factor about how the tests are being
16 performed and about how the tests probably are in actuality
17 being conducted. We have constant dialogue or intermittent
18 dialogue with the operator of the drill site. We also have
19 discussions ongoing with the allocation engineers themselves,
20 and there's been a certain amount of relationship established
21 between them and our engineer in the office. And I guess
22 through that process my first reaction would be that we're
23 comfortable and maybe we could get along without monitoring
24 those tests at that level.
25
CHAIRMAN JOHNSTON: If we were to request an
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·
1 overview of your procedures, an actual demonstration of what
2 you're looking at and, you know, basically a show and tell over
3 at BP's facilities by a Commission representative would you be
4 amenable to that?
5
MR. JAMES: I don't anticipate any problem with
6 that.
7
CHAIRMAN JOHNSTON: Thank you. I think that
8 would be helpful to us to understand exactly the monitoring
9 that is taking place in a Real Time situation, looking at the
10 actual parameters of the well testing. Part of my frustration,
11 of course, is I get these pages of documents and I don't
12 necessarily know what they represent, and I'd like to actually
13 see the data coming in to see what the technical people that
·
14 you have are looking at to obtain that comfort level with this
15 process.
16
Any further questions? Okay. Well, thank you very
17 much.
18 And at this time I'd like to ask if there's any other
19 people representing industry that wish to address the
20 Commission?
21
okay. I guess that leaves us with the Department of
22 Natural Resources. In light of my earlier announcement that
23 the legislature has authorized money to
for the Commission
24 to develop an oversight program, we see no real need at this
25 time to investigate the three alternatives outlined in our
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1 Notice to the Public. Given that, does the Department of
2 Revenue still with to make any comments to the Commission?
3
MR. MARKS: To be brief, our comments focused
4 on that .....
5
COMMISSIONER BABCOCK: Mr. Marks, I don't know
6 that .....
7
CHAIRMAN JOHNSTON: A simple yes or no question
8 right now would suffice.
9 MR. MARKS : Okay. Yes.
10 CHAIRMAN JOHNSTON: okay. Why don't we take a
11 10-minute break and we'll come back and listen to the
12 Department of Revenue. Thank you.
13
(Off record - 2:50 p.m.)
.
14
(On record - 3:00 p.m.)
CHAIRMAN JOHNSTON: I'd like to reconvene this
15
16 hearing, and at this time we'd like the representative from the
17 Department of Revenue to address the Commission.
18
MR. MARKS: Speak into this?
19
COMMISSIONER BABCOCK: Yes.
20
MR. MARKS: Okay. Mr. Chairman, my name is
21 Roger Marks. I'm a petroleum economist with the Department of
22 Revenue. I received degrees in economics and accounting from
23 Brown University and the University of Maryland. Between 1977
24 and 1983 worked for the U.S. Geological Survey doing resource
25 evaluation and designing bidding systems for leasing on the
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·
1 outer continental Shelf. Since 1983 I've been with the
what
2 is now the oil and Gas Audit Division of the Department of
3 Revenue doing policy analysis for taxation and regulations and
4 revenue forecasting.
6
CHAIRMAN JOHNSTON: Thank you.
COMMISSIONER BABCOCK: Good.
5
7
COMMISSIONER DOUGLASS: No objection.
CHAIRMAN JOHNSTON: Thank you, Mr. Marks. We
8
9 will accept you as an expert witness in this matter. Do you
10 wish to offer sworn testimony?
11
12
13 hand.
· 14
15
16
MR. MARKS: Yes, I do.
COMMISSIONER DOUGLASS: Please raise your right
(Oath administered)
MR. MARKS: I do.
CHAIRMAN JOHNSTON: Thank you very much.
17 Please proceed.
18
MR. MARKS: okay. You received our August -- I
19 mean our April 26, 1995 letter from Commissioner will Condon on
20 the subject. Given it's part of the written record now, rather
21 than reading that over again, I'd just like to make a few
22 comments on that, and they'll be brief.
23 The Department of Revenue first recognized the problems
24 with the issue of allocation between fields in 1989 when there
25 were some statutory changes to the production tax law which
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19
20
21
22
23
24
25
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46
1 made for large tax differences between fields, depending on
2 production.
3 We realized even in going -- when that law was passed
4 that allocation would be a problem and we recognized that
5 mechanism for allocating were not perfect but good. We believe
6 that perfect tax compliance is costly both for the
7 administrator and the taxpayer, and we went for an approach
8 that was short of a perfect tax compliance, meaning watching
9 over every little thing. We said -- we mentioned in the
10 April 26 letter that given a 10 percent allocation error that
11 the tax consequences would be about $2 million annually. I'd
12 just like to note that 10 percent is an extreme, and that's
13 sort of the maximum range of the exposure, and nothing
14 empirically near 10 percent has been observed.
15
In 1991 we made an agreement with the owners of the LPC
16 regarding the mechanism for allocation and metering. There are
17 serious sanctions for the taxpayers by not complying with that
18 in that we had the prerogative to actually aggregate the
separate PAs into one field for. calculating the economic limit
factor, which would be a huge tax increase for them. So there
is serious sanctions for not abiding by the agreement.
Another factor here is that there is significant
self-policing available for the producers at the LPC. The fact
that different companies have different ownership percentages
in the different fields means it's to their interest to make
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1 sure the allocations are done properly. For example, our
2 records show that BP has about 37 percent of the share of
3 Pt. McIntyre but only 20 percent of Lisburne and none of
4 West Beach or North Prudhoe Bay state. So assuming the profits
5 from producing a barrel of oil, the profits are greater than
6 what the severance tax is, there's a big incentive for BP to
7 make sure the allocation is done properly.
8 In 1993 we procured the services of an outside
9 contractor to monitor these commingling agreements technically,
10 and he is here today to answer any technical questions you
11 might have, subject to confidentiality.
12 In summary, we started actively monitoring when
13 Pt. McIntyre came on in late 1993. It's been an evolving
·
14 process. We've gotten significant assistance from the AOGCC
15 staff doing data analysis on well production for us, and that's
16 been real useful. There's been periodic discussion sessions
17 with the companies which the AOGCC has participated in. Also
18 there's lots of opportunity to discuss the issues. There's
19 constant active review going on. As far as the Department of
20 Revenue is concerned, this whole process right now is
21 acceptable and working satisfactorily, and we don't believe the
22 Commission has to do anything on this matter on the account of
23 DOR.
24 And that concludes my comments.
25
CHAIRMAN JOHNSTON: Thank you. The DOR letter
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1 indicates that you've developed a surveillance tool and
2 procedures for measuring well by well volumes. Could you
3 please describe your efforts in a little bit more detail as to
4 what you have done?
5
MR. MARKS: Okay. I think at this point it
6 would probably be more fruitful to bring our contractor up.
7
CHAIRMAN JOHNSTON: Okay. Thank you. Please
8 identify yourself for the record.
9
MR. PLATT: My name is Dudley Platt.
10
CHAIRMAN JOHNSTON: And do you wish to be
11 considered an expert witness in this matter?
12
MR. PLATT: Yes.
13
CHAIRMAN JOHNSTON: Would you state your
.
14 qualifications?
15
MR. PLATT: I received a BS in petroleum
16 engineering at Marietta College in 1981. Graduating from
17 school I came straight to Alaska and have spent the last 14
18 years working in the oil industry for industry, for the
19 Minerals Management Service, for the State of Alaska, and for
20 the last three years as a consulting engineer.
21
CHAIRMAN JOHNSTON: Any objection? No
22 objections. Okay. We'll accept you as an expert witness in
23 this matter. Do you wish to provide sworn testimony?
24
MR. PLATT: Yes.
25
COMMISSIONER DOUGLASS: Please raise your right
.
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1 hand.
2
(Oath administered)
3
MR. PLATT: I do.
4
COMMISSIONER DOUGLASS: Thank you.
CHAIRMAN JOHNSTON: Mr. Platt, did you
5
6 understand my question I asked?
7
MR. PLATT: Yes. Specifically your question
8 addressed the -- perhaps the details of the surveillance tool
9 that the Department of Revenue and members of the Conservation
10 Commission staff have helped to develop and further, yes.
11
CHAIRMAN JOHNSTON: If you'd please describe
12 that in greater detail for us?
13
MR. PLATT: Okay. It's a series of graphs, if
·
14 you will, that monitor allocated data and production data, both
15 on a nominal basis and a hourly adjusted basis, and it
16 considers all the parameters of well testing that one would use
17 to identify deviations from short-term trends. It's based on
18 the premise that over short periods of time a well's GOR,
19 water-oil ratio or water cut producing rate exhibit
20 identifiable trends.
21
We can take a look at that. I think the way that the
22 graphs come out are a four to six-month sliding average or
23 sliding time frame. And we can identify through using the
24 allocated data when spikes up or down in either the gas to oil
25 ratio, water cuts occur, and then we go and try to identify if
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1 that spike is a function of the enumerator changing or the
2 denominator changing. And we've been fairly accurate in being
3 able to identify two specific areas where that comes into play.
4 One is when the facilities happen to be put on
5 proration or shut down for whatever reason and then start back
6 up. Two is when any cyclical wells have been brought back on
7 production. We've noticed inconsistencies or -- and by that I
8 mean the short-term trend that you would expect to have happen
9 in whatever parameter you're looking at, the allocated data
10 falls outside that range. And we've continued to use this tool
11 to develop a comfort level.
12
COMMISSIONER DOUGLASS: Could you define what
·
13 you consider short-term?
14 MR. PLATT: As far as the identif- .....
15
COMMISSIONER DOUGLASS: When you talk about
16 these short-term trends what is short-term?
17
MR. PLATT: Well, the graphs we plot are four
18 to six months, but clearly you can go a week before, a week
19 after the event, if you will, a month before, a month after,
20 but I think it varies according to what type of a well you're
21 looking at.
22
COMMISSIONER DOUGLASS: Okay. Well, I guess
23 maybe I didn't understand. I thought you were saying you had
24 identifiable short-term trends .....
25
MR. PLATT: Sure. I .....
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2 looking at.
3
4
5 the . . . . .
6
COMMISSIONER DOUGLASS: ..... that you were
MR. PLATT: Yes.
COMMISSIONER DOUGLASS: And so I thought maybe
MR. PLATT: Yeah, identified as gas/oil ratios.
7 For a Lisburne well that trend is going to be increasing over
8 time. It's much more helpful to describe this process if I had
9 some plots and overheads involved.
10 CHAIRMAN JOHNSTON: Do you look at
11 stabilization time and test duration?
12
MR. PLATT: We look at it. We have deferred to
·
13 the people who should know best on how to do that, and that
14 would be the operator.
15
CHAIRMAN JOHNSTON: So essentially what you are
16 reviewing is the printed material that is provided?
17
MR. PLATT: Absolutely. We are not in any way
18 attempting to recreate the process.
19
CHAIRMAN JOHNSTON: The Department of Revenue
20 does not attempt to actually witness the actual test itself?
21
MR. PLATT: The Department has reserved the
22 right to do that. To date we have not done that.
23
CHAIRMAN JOHNSTON: You have not done that. Is
24 there anything that would lead you to actually looking at the
25 actual tests or going up to the North Slope and verifying that
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· 1 the tests
2 printout?
3
·
·
are actually being conducted as reflected on the
MR. PLATT: Absolutely. If nothing else, just
4 to spot check on the methodology.
5
CHAIRMAN JOHNSTON: Do you think that would be
6 an appropriate thing to occasionally throw into an oversight
7
program, the
. . . . .
8
MR. PLATT: I believe that .....
9
CHAIRMAN JOHNSTON: ..... actual monitoring of
10
the actual tests by
. . . . .
11
MR. PLATT: I believe so.
12
a representative?
CHAIRMAN JOHNSTON:
. . . . .
13
MR. PLATT: Uh-huh.
14
CHAIRMAN JOHNSTON: Any questions?
15
COMMISSIONER DOUGLASS: I have a question but
16 it's really for a clarification from Roger's comment. If I
17 heard you -- I mean tell me if I'm wrong, but if I heard you
18 right the Department of Revenue is not contending that any
19 additional oversight is warranted at this time?
20
MR. MARKS: Not for administration of
21 production tests, that's right.
22
COMMISSIONER BABCOCK: Is there anything about
23 the allocation methodology that leaves you with any questions
24 as to the actual allocations as they've been presented to the
25 Department of Revenue since 1991?
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1
MR. PLATT: Over the last five years every
2 party involved, I believe, has enjoyed a learning curve. Up
3 front there was a lot of uncertainty; today there's less
4 uncertainty. Over the years I've been able to identify two
5 major areas of possible allocation errors. One is problematic,
6 I guess, but it's identifiable. It's resolvable provided there
7 is some kind of oversight involved. This type of error
8 specifically is what ARCO's testimony was previously, and that
9 is the water cut meter calibration issue, natural gas algorithm
10 issues. The water cut meter -- a second type of water cut
.
11 meter concern is -- and that's the master water cut meter that
12 is what you use to compare the sum of the well test to. These
13 are all problematic, they are identifiable with surveillance.
14 They are resolvable. It requires constant communication with
15 the operator. And that first type of a problem is resolvable.
16 The second kind of problem that we are still striving
17 to develop a better comfort level with is the type of problem
18 that occurs by virtue of the arithmetic nature of the
19 allocation methodology. And in simple terms that means when
20 you take the sum of a bunch of well tests it never, ever adds
21 up. So you've got a difference, and the current allocation
22 methodology suggests that you take that difference -- and it
23 suggests that you don't know precisely what's causing that
24 difference, so you spread it evenly over every single well that
25 participated for the month. You're taking a very simplified,
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1 relatively low cost methodology and you're applying it to wells
2 with, what I would consider, drastically different producing
3 characteristics. On the one hand you've got 86 percent of the
4 fluids coming from a very stable producing reservoir -- that
5 would be Pt. McIntyre, and probably Niakuk, too. I should bump
6 it up. Low water cuts, low GORs, relatively stable, for the
7 most part. You compare that to a well that very recently when
8 it was producing at all -- this is West Beach -- was a very
9 cyclical producer. The North Prudhoe Bay state exhibits the
10 same type of producing characteristics. Lisburne, being a
11 relatively mature oilfield, producing from a very different
12 type of a reservoir, subject to increasing gas to oil ratios,
·
13 has a very higher degree of what I call cyclical well
14 production. The cyclical wells are wells that don't always
15 produce 30 or 31 days in a month.
16 But prudent operatorship suggests that you should burp
17 them on a regular basis and benefit from the oil production.
18 When you do that it's not always easy to burp it into the same
19 pan (ph), so you kind of stick a cup out there as it's burping
20 and you measure it and you catch it and then you kind of
21 extrapolate it. That burping of cyclical wells is one of the
22 specific problems in the second category of problems identified
23 that may contribute to that -- that difference being allocated
24 evenly over all wells when indeed and perhaps maybe it should
25 be allocated to a certain type of well. Again, we don't know
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1 the answer yet. We're continuing to monitor it. The
2 Department of Revenue has appreciated the efforts of the staff
3 of the Conservation commission to assist in that, and our goal
4 is to make sure that that comfort level is obtained as soon as
5 possible.
6
COMMISSIONER BABCOCK: Do you find anything
7 objectionable in any of the exhibits presented by ARCO as to
8 its factual representation?
9
MR. PLATT: All the exhibits I've seen today
10 are exhibits that I've seen in an evolutionary fashion for the
11 last five years. The oil rates have come up, the water cuts --
12 the accuracy in water cuts -- I guess if I had any uncertainty
·
13 it would be the reliability or the accuracy of the automatic
14 and continuous water cut meter. Again, I'm not suggesting
15 that's a problem right now, it's just that that's part of what
16 we need to have a comfort level with.
17
COMMISSIONER BABCOCK: Do you mean that ARCO's
18 representation that it's been off by as much as 24 percent is
19 inaccurate or is that a correct representation of the problems
20 with the water cut .....
21
MR. PLATT: I think you're .....
22
COMMISSIONER BABCOCK:
. . . . .
allocation?
23
MR. PLATT: ..... referring, on the 24 percent,
24 is the -- is attributed to the problems ARCO was having with
25 the master water cut meter on the injection well. There may be
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1 some concerns regarding the water allocation at the drill site
2 level. The information that we've been provided -- I've got
3 actually no reason to believe that that's not the proper
4 information.
5 Again, if you were to take on the one plot -- I don't
6 know what exhibit it was, but it showed the straight line and
7 it compared the shakeout data to the water cut data.
8
COMMISSIONER BABCOCK: Okay. Exhibit K?
9
MR. PLATT: That, Exhibit K, represents the
10 drill site L3 version of that. I'm not certain of what the
11 okay, this is Lisburne. The one note that I would have, I
12 guess, would be that the accuracy of this -- or the .....
13
COMMISSIONER BABCOCK: Well, Mr. Platt, my
14 question was were there any of the facts represented by ARCO in
15 these exhibits that you think are inaccurate?
16
MR. PLATT: No.
17
COMMISSIONER BABCOCK: Okay.
MR. PLATT: No.
18
19
COMMISSIONER BABCOCK: Are there any
20
improvements that you would recommend from your years working
on this to the allocation methodology itself?
MR. PLATT: I think that part of the
improvements that we think that are out there we're not
21
22
23
24 prepared to state fully now. We're still waiting on some
25 information we've requested, and, again, the improvements I
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1 think can be identified, maybe threefold:
2
One, allow for some adjustments in the allocation
3 methodology to account for some cyclical well production. That
4 adjustment might be -- relax the requirement for a second well
5 test on a very stable producing well and allow the operator to
6 get more wells -- more well tests on that type of well. Or,
7 ideally, to keep it in the test separator if it's only going to
8 produce three days out of a month continuously and get an
9 accurate measure of it.
10 Two, another issue that we have not spoken to yet is
11 the way NGLs are allocated. NGL allocation is a function of a
12 number of things: Operating temperature and pressure for
13 certain pieces of equipment at the Lisburne Production Center,
· 14 the volumes of the gas and oil produced and the compositions of
15 those. Ideally, if you could assume a constant makeup or
16 composition of the gas and ensure that whatever simulation
17 program you're using accounts for the variation in the
18 operating conditions of the LPC that we know occurs, and then
19 make sure that your gas allocations are correct, because the
20 NGL allocation is based on the gas allocations. Then the
21 methodology is working and it would be a little less difficult
22 to find fault with it.
23 Department of Revenue has not yet come to the level of
24 comfort that they need to come to to make sure that all three
25 of those instances are working. That's part of the data we've
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1 requested we haven't received yet.
2
CHAIRMAN JOHNSTON: ARCO earlier testified that
3 they -- and also their letter reflects this, that they have at
4 least consulted informally with the state agencies. Presumably
5 that means Revenue, and they indicate that there was no
6 fundamental concerns expressed. Would that be an accurate
7 statement you believe, at least as far as it pertains to the
8 Department of Revenue?
9
COMMISSIONER BABCOCK: Mr. Chairman, before he
10 answers that question, perhaps he could get to number three in
11 the cyclical well tests, the NGL and .....
12
MR. PLATT: commissioner, I've forgotten what
13 number three was going to be, but .....
·
14
COMMISSIONER BABCOCK: I didn't mean to put you
15 on the spot or cut you off if you had number three. All right.
16
MR. PLATT: Again, Mr. Chairman?
17
CHAIRMAN JOHNSTON: The question I wanted to
18 ask is whether you felt that ARCO properly characterized the
19 fact that in their opinion anyway, after consulting with state
20 agencies, they found there were no fundamental concerns
21 expressed. Do you think that is fair representation of the
22 Department of Revenue in this regard, that you have no
23 fundamental concerns?
24
MR. PLATT: Well, I can't say over the years
25 that in addition to the formal correspondence and
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.
1 communications and meetings that we've had there has been an
2 incredible amount of informal discussions. It's not unlikely
3 for me to talk to any number of people within the operator
4 company regarding this. Fundamental differences, I think
5 there's still issues out there that we're still looking at and
6 need to be resolved. Things that would be a showstopper, no.
7 CHAIRMAN JOHNSTON: Part of my desire in
8 holding these hearings is to basically develop either an
9 inhouse system in here or perhaps just recognition that the
10 process has sufficient oversight that the state agencies are
11 comfortable with it and that we clearly communicate to industry
12 this point, and that thereby doing, give them certainty in this
13 process. Do you think the Department of Revenue is at the
. 14 point now where we can send very clear signals to industry that
15 this process is indeed appropriate, that the oversight that is
16 extended is indeed appropriate and that there is no concern ont
17 he part of, at least, the Department of Revenue?
18 MR. PLATT: I think it's in everybody's best
19 interest to minimize the administrative burden for this type of
20 oversight. Nonetheless, I believe that there's a small,
21 minimal amount of oversight necessary. That type of oversight
22 would probably include periodic inspections of the well
23 testing, it would include sitting down with the operator
24 which I've done on different occasions, and actually watch them
25 perform allocation methodology. There's some subjectivity
.
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1 involved with it, and, thirdly, use some kind of a tool that
2 would let the little things slide within a band of comfort, but
3 identify the big events and then set up a procedure, ideally by
4 phone, where somebody calls the operator and says, "Did you see
5 this event? What can we do about it, and get it done."
6
CHAIRMAN JOHNSTON: You also mentioned earlier
7 on, you know, the difficulty with cyclical wells, and you were
8 suggesting that perhaps an improvement on the system maybe
9 moving away from a mandatory two-tests per month for certain
10 wells that reflect stability, and really more focusing on the
11 wells that exhibit some production problems, for whatever
12 reason. That was one approach that we considered early on in
.
13 the process with West Beach, but I think the State collectively
14 decided, at least in the near term, over the next few years,
15 that we should just go with a mandatory two-month -- or two
16 tests per month process. Sounds like the thinking has now
17 evolved a little bit to where you're suggesting perhaps the
18 approach should be that we focus more appropriately on those
19 problem wells and direct the industry to sample those or test
20 those a little more frequently than two months -- or twice per
21 month and in turn drop the two tests per month requirement for
22 the stable wells. Is that a fair characterization?
23
MR. PLATT: The transition to that type of
24 philosophy is not inappropriate. I would preface that
25 statement on the fact that it sure would be nice to make sure
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1 that the test separators were being used as fully as possible.
2 I believe now it's ranging in the 70 to 75 percent utilization,
3 with a few occasions where it drops below that for certain
4 drill sites, and a few occasions where it goes above that. I'd
5 certainly like to see that improved a little bit.
6
CHAIRMAN JOHNSTON: During our discussions,
7 prior to West Beach, we investigated these alternatives. One
8 of the difficulties we had with this idea of tailoring the
9 tests or the frequency. of the test to the problem wells was to
10 -- how do we communicate that, as state agencies, to the
11 industry? And the thought was that we should have, clearly, a
·
12 single point of contact where industry says this is what's
13 happening, how about hitting these wells three, four, five
14 times a month and dropping out these wells because they have
15 this history of stabilization. Do you think that is an
16 appropriate type response?
17
MR. PLATT: I think that if a single point of
18 contact can be achieved while still preserving the individual
19 statutory authorities of the different agencies, that that
20 would be beneficial, yes.
21
CHAIRMAN JOHNSTON: And who would you suggest
22 that single point of contact be?
23
MR. PLATT: I might be sounding self-serving
24 here. I don't know, some independent consultant.
25
CHAIRMAN JOHNSTON: Well, I suppose that kind
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1 of puts you on the spot there. I didn't want to necessarily
you the opportunity to advertise, but you did quite a good
2 give
3 jOb.
4
5
6
7
MR. PLATT: What do I owe you for that?
CHAIRMAN JOHNSTON: Any other questions?
COMMISSIONER DOUGLASS: None.
CHAIRMAN JOHNSTON: At this juncture apparently
8 we have no further questions for you. I think you for your
9 testimony, appreciate it.
10 Roger~ do you have any other comments on behalf of
11 Revenue then?
12
(Shakes head negatively)
MR. MARKS:
13 COMMISSIONER BABCOCK: One more question for
14 Mr. Marks, which is: Were you stating then that the Department
15 of Revenue has no concerns with the allocation methodology now
16
as it's --
. . . . .
17
MR. MARKS: Well, we .....
18
COMMISSIONER BABCOCK:
or just no
. . . . .
19 concerns that arise to the level of trying to do something
20 differently?
21
MR. MARKS: We have concerns, but we believe
22 the process we have in place will resolve those concerns.
23
COMMISSIONER BABCOCK: All right.
24
CHAIRMAN JOHNSTON: And do you see -- obviously
25 an integral part of this process that you've developed is the
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1 employment of an independent contractor. Do you see those
2 efforts continuing on the part of the Department of Revenue?
3 MR. MARKS : We've requested the budget -- like
4 for FY-96, so at this point that's all we know.
5
CHAIRMAN JOHNSTON: So things look pretty good
6
for a continuation,
.....
7
MR. MARKS: You know, I would guess .....
8
CHAIRMAN JOHNSTON: ..... at least at this
9 juncture?
10
MR. MARKS: If I had to guess, I would say it
11 would for at least FY-96.
12
CHAIRMAN JOHNSTON: Okay. And does this have
·
13 -- does the allocation of this money for this consultant, does
14 that have high priority within the Department?
15
MR. MARKS: Yes.
16
CHAIRMAN JOHNSTON: Any questions -- further
17 questions? Okay. Thank you.
18
COMMISSIONER BABCOCK: I have just one. The
19 last question that I have is how does the -- part of the reason
20 commingling is permitted is to encourage the development of
21 smaller fields where separate processing facilities would not
22 be economically justified.
23
MR. MARKS: Uh-huh.
24
COMMISSIONER BABCOCK: If the companies that
25 are trying to develop these fields have no closure on their tax
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1 liability, even though they're using an approved commingling
2 allocation methodology, it is my opinion that could also affect
3 their determination to develop marginal or smaller fields.
4 MR. MARKS : Uh-huh.
5 COMMISSIONER BABCOCK: What sort of closure
6 does the Department of Revenue have as the taxing authority
7 with respect to the allocation of production to different
8 fields under our commingling allocation agreement?
9
MR. MARKS: Well, the agree- -- well, I need to
10 get back to you on that one.
11
COMMISSIONER BABCOCK: Okay.
MR. MARKS: Okay.
12
13
· 14
15
16
17
COMMISSIONER BABCOCK: I guess I'll recommend
we hold the record open for a while.
MR. MARKS: Okay.
COMMISSIONER BABCOCK: Thank you.
CHAIRMAN JOHNSTON: Thank you, Mr. Marks. At
18 this time I note that there is a representative from the
19 Department of Natural Resources here. It was our
20 understanding, as reflected in communications to us that a
21 representative would not be attending, although we did respond
22 to that communication and allowed the opportunity for the
23 Department of Natural Resources to testify if they did in fact
24 have any problems or dissatisfaction with the allocation
25 process.
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1
Do I take your presence here to mean that DNR is
2 satisfied or is not satisfied with the allocation process?
3
MR. KOTOWSKI: I think the Commissioner spoke
4 that there would not be a representative here. I believe it is
5 a public hearing and that I'm as interested in the process
6 (indiscernible - away from microphone).
7
CHAIRMAN JOHNSTON: Okay. That's fine.
8
MR. KOTOWSKI: The Commissioner's statement is
9 the statement of the Department.
10
CHAIRMAN JOHNSTON: Okay. That's fine. I
12
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· 14
15 that's all.
16
17 with that.
11 didn't know how to interpret your presence is all, .....
MR. KOTOWSKI: Well, again, I believe .....
CHAIRMAN JOHNSTON:
. . . . .
given our .....
MR. KOTOWSKI: ..... this is a public hearing,
CHAIRMAN JOHNSTON: Yeah. We have no problem
Given our response to the Commissioner, I was not
18 certain as to whether you were here to testify or were not. So
19 we appreciate you clarifying that for us. Thank you.
20
COMMISSIONER BABCOCK: Mr. Chairman. The
21 Commission is holding this hearing on its own motion. It has
22 tried for -- and recognized, rather, for several years that a
23 more in-depth review of the commingling methodology is
24 warranted, at least in our judgment. We were unsuccessful in
25 the last legislature in acquiring funding to focus on this
·
R & R C 0 U R T R E P 0 R T E R S
810 N STREET
277-0572/Fax 274-8982
1007 WEST THIRD AVENUE
272-7515
ANCHORAGE, ALASKA 99501
.
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66
·
1 issue, and we're uncertain of the prospects in this legislative
2 session. Apparently the Conference Committee approved an
3 engineering position to fund an oversight activity, and that
4 being the case it leaves, of course, the Governor to decide
5 whether or not to fund that position. And I would like to hold
6 the record open and move that the hearing be recessed until
7 July 12 to take up -- should we not receive funding, then take
8 up a more detailed examination of whether or not we need to
9 pursue Alternatives 1, 2 or 3 or some other alternative.
10
11 motion?
12
13 negatively)
· 14
CHAIRMAN JOHNSTON: Any discussion on that
COMMISSIONER DOUGLASS:
(Shakes head
CHAIRMAN JOHNSTON: Any objections to it then?
15 There being no objections, the motion is passed and we'll hold
16 this proceedings in recess till close of business on July 12,
17 1995, unless we take action to close it sooner.
18 COMMISSIONER DOUGLASS: We'll reconvene?
19 COMMISSIONER BABCOCK: I mean my motion was to
20 reconvene. I didn't give a time, but 9:00 a.m. on July 12, . but
21 otherwise you stated my motion accurately.
22
CHAIRMAN JOHNSTON: Well, why don't we leave it
23 at that then, if we feel any need to reconvene, we'll do it on
24 July 12th, and if we see that things are proceeding in an
25 acceptable manner, then we can close it at an earlier date if
·
R & R C 0 U R T R E P 0 R T E R S
810 N STREET
277-0572/Fax 274-8982
1007 WEST THIRO AVENUE
272-7515
ANCHORAGE, ALASKA 99501
·
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·
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.
67
1 we so desire.
2
COMMISSIONER BABCOCK: certainly.
CHAIRMAN JOHNSTON: With that, I'd like to
3
4 thank everyone for attending. It was very helpful. Hopefully
5 the transcript will be available in about -- how long, Laurel?
6
COURT REPORTER: Next week.
7
CHAIRMAN JOHNSTON: Next week, about a week
8 from now, okay. Thank you. And, again, if you desire to
9 receive a copy, please contact R & R Court Reporters directly.
10 These proceedings
11
And I note the time is approximately 3:35.
are closed for the day anyway.
(Off record - 3:35 p.m. )
12
13
(END OF PROCEEDING)
* * * * * *
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R & R C 0 U R T R E P 0 R T E R S
810 N STREET
277-0572/Fax 274-8982
1007 WEST THIRD AVENUE
272-7515
ANCHORAGE, ALASKA 99501
.
.
· 1 C E R T I F I C ATE
2 UNITED STATES OF AMERICA)
) SSe
3 STATE OF ALASKA )
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4 I, Laurel L. Evenson, Notary Public in and for the
State of Alaska, residing at Anchorage, Alaska, and reporter
5 for R & R Court Reporters, Inc., do hereby certify:
THAT the annexed and foregoing Public Hearing of the
Alaska oil and Gas Conservation commission Re: commingled
Production was taken before me on the 3rd day of May 1995,
commencing at the hour of 1:30 o'clock p.m., at the offices of
the Alaska oil and Gas Conservation Commission, 3001 Porcupine
Drive, Anchorage, Alaska, pursuant to Notice;
THAT this Transcript, as heretofore annexed, is a true
and correct transcription of the testimony given at said Public
Hearing, taken by me and thereafter transcribed by me;
THAT the original of the Transcript will be lodged with
the Alaska Oil and Gas Conservation commission, 3001 Porcupine
Drive, Anchorage, Alaska;
IN WITNESS WHEREOF, I have hereunto set my hand and
affixed my seal this 8th day of May 1995.
~~
Notary Public in and for Alaska
O f"C:I^~ ~¡¡4~
STATE OF ALASKA
NOTARY PUBLIC
LAUREL L. EVENSON
My Comm. expires: November 3, 1998
RECEIVED
MAY .., 8 1995
AlaD\<.aUI~ & Gas Cons. CommlsslO.R
- 'I Anchoragll
R & R C 0 U R T R E P 0 R T E R S
810 N STREET
277-0572/Fax 274-8982
1007 WEST THIRD AVENUE
272-7515
ANCHORAGE, ALASKA 99501
·
--=E)(H~ßII A
-
NOTICE OF PUBLIC HEARING
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Re: Commingled Production
The Alaska Oil and Gas Conservation Commission, acting on its own motion, will hold a
hearing on May 3, 1995 beginning at 1 :30 pm at 3001 Porcupine Drive, Anchorage, Alaska. The
hearing will address whether measurement of produced fluids from Niakuk, Pt. McIntyre, Stump
Island, West Beach, North Prudhoe Bay State and Lisburne oil pools is appropriate to satisfy state
royalty accounting, taxation and conservation needs.
TIle Commission will consider whether current allocation methodology using monthly well
tests offers proper precision and verification opportunity. The Commission must be assured that
existing methodol?gy can detemlÎne the quality and quantity of oil and gas.
The Commission will consider alternatives to current methodology including:
1. Requiring the mineral interest owners and royalty owners to hire a
Commission-approved third party to witness well tests and verify allocation
methodolgy.
-
2. Requiring separate processing and measuring facilities for each reservoir.
3. Unitizing all reservoirs contributing to a single processing facility.
J,~
~-~
The Commission will consider testimony from all interested parties. If you are a person
with a disability who may need a special modification in order to comment on the proposed
regulations or to attend the public hearing, please contact Diana Fleck at 279-1433 no later than
April 27, 1995.
<í
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Tuckeffilan Babcock
Commissioner
Published March 31, 1995
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April 9, 1995
ø
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David W. Johnston
Commissioner
Alaska Oil & Gas Conservation Commission
3001 Porcupine Drive
Anchorage, Alaska 99501-3192
Subject: Senate Bill 99 & House Bill 46 - "An Act relating to the
practice of architecture, engineering, and land surveying."
Dear Mr. Johnston,
As a Registered Engineer and Chairman of the AOGCC, you may have a
keen interest in the above bills which are currently moving quickly
through the Alaska Legislature with little public hearing or testimony. In
1990, the Legislature repealed a then existing exemption which allowed
large utilities and resource development companies to avoid utilizing
engineers who were licensed by the' state as "Registered Engineers". The
utilities and resource companies have failed to comply with the new
statutes and are now mounting a campaign to change the law so they are
again exempted from having to utilize licensed engineers.
The safety and welfare of Alaskan's is impacted by these Bills. For
example, monthly oil and gas production is reported to the State by the
producers. This includes commingled oil production and natural gas
liquids. As. you know commingled production allocation is a calculated,
not measured, volume. It is these production calculations and subsequent
reports which are used to determine royalty and severance liabilities to
the State. Senate Bill 99 would allow for these production calculations to
be done not only by unlicensed engineers but potentially by lawyers,
accountants or high school interns. The next time a producer gives
testimony to the Commissioner ask if the engineering calculations and
plans were reviewed by a Registered Engineer!
This proposed legislation is bad public policy and anti-local hire. I don't
understand why I need a Registered Engineer to approve a water well plan
for my cabin but no such approvals are necessary to drill an oil well or
change it from production to injection.
Sincerely,
(f~ (fitkuvtmd0~
REeEIVED
APR 1 1 1995
Alaska Oil & Gas Cons. Commission
Anchorage
--
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SB 99 &HB 46
"An Act relating to the practice of architecture,
engineering, and land surveying."
·
Occupational licensing helps to ensure that only JJqualified" persons practice
and/ or offer services to the public. Engineering has fallen into the category of
licensing since a rash of boiler explosions in schools and public buildings in the
1800's started to maim and kill hundreds of people every year. Excluding a
person who JJpractices engineering involved in the operation of the employers
business only" (Sec. 3. 08.48.331) defeats the purpose of licensing the occupation.
This wording would exclude the Alaska Railroad, gas and electric utilities, the
phone companies, mining and other resource production companies from
having to utilize licensed engineers. Consider the following cases which all
happen on private property (owned or leased); 1) a railroad bridge fails and
toxins are released. into a local \'later supply, 2) power to the city is interrupted
for over 12 hours due poor equipment design causing hospitals to complete
surgeries and maintain life support systems using emergency power (if the
emergency power systems work), 3) seven people including one employee die
from hydrogen sulfide poisoning due to improper material selection on a valve,
and 4) a Teamster. is severely burned in a fire caused by overloaded electrical
circuits while staying at a North Slope camp. Are these cases real or
hypothetical?
Consider this: Would the large companies promoting this exclusion consider
employing lawyers for internal legal counsel who were not members of the
state Bar? Would large companies hire unlicensed physicians to practice
medicine on the injured contract workers or sick employees? Of course not!! I
believe the real issue is why the larger capital intensive employers have failed
abide by the statute for the last four years!
To save more money will the next exemption request be for utilizing unlicensed
electricians and pipefitters? If the legislature and governor are really for local
hire why are they exempting the licensing of engineers when ARCO is laying
off engineers who are already IIRegistered" and live in Alaska?
·
Similarly, the current exemption for JJa person who is employed by a post
secondary educational institution to teach engineering" should be repealed. The
public should not stand for unqualified and unlicensed engineers to teach
engineering. The exemption is in direct conflict with the definition of the
JJpractice of engineering" contained in the existing statute JJ(9) JJpractice of
engineering" means professional service or creative work, the adequate
performance of which requires the specialized knowledge of applied
mathematics and sciences, dealing with the design of structures, machines,
equipment, utilities systems, materials, processes, works, or projects, public or
private; the teaching of advanced engineering courses in institutions of
higher learning;" (Sec. 08.48.341) Items in BOLD are added emphasis. Its ironic
that you have to be licensed to teach preschool but not to teach engineering!
REQEIVED
APR 1 1 1995
· ARCa Alaska, Inc. .....
Post Office Box 1 003~
Anchorage, Alaska 99510-0360
Telephone 907 2761215
"þ()J£T~ ~...
.... 6r<1~ 'f-ÞI4NJiJ .....
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[:,:4;¿,t C
Daniel G. Siekkinen
Manager
Greater Pt. Mcintyre Area
April 13, 1995
David Johnston, Chairman
Oil and Gas Conservation Commission
3001 Porcupine Drive
Anchorage, AK 99501-3192
Production Allocation Hearing
Dear Mr. Chairman:
I appreciate the time you and the other commissioners took to meet with Ron Oba
and me to discuss the upcoming May 3, 1995, hearing on production allocation for
fluids from the various fields that are produced through the Lisburne Production
Center. At that meeting, it was suggested that ARCO might reserve response to
any criticisms or potential alternative actions unless and until evidence
suggesting the need for a change were presented. It was suggested that if such
evidence were presented, the hearing could be continued to a later date for
additional testimony. ARCO believes this is sound proposal, and therefore plans
on approaching the hearing in the following manner.
As the operator of the Lisburne Production Center, ARCO will testify to the
history of its efforts to seek and obtain approvals for the current methodology
from the affected Working Interest Owners, the Department of Natural Resources,
the Department of Revenue, and the Alaska Oil and Gas Conservation
Commission. ARCO will also present testimony summarizing the operation of
the methodology, which is functioning at least as well as planned. Finally, it will
testify to the results of the periodic reviews required by the various agencies as a
condition of their approvals, at which no fundamental criticisms have been
raised.
We do not anticipate that concerns, criticisms, or suggestions will be raised by any
of the affected entities. Since we received the notice, we have talked informally
with the DOR, DNR, BPX and Exxon, and none have expressed a fundamental
concern or a need for any change. If a concern is raised at the hearing, we suggest
that it would then be appropriate for all parties to be granted time to evaluate the
issues before responding. This deferral of consideration of alternatives will save
time and expense if the hearing confirms our belief that the current system and
its operation is not broken. R E (, E , V t D
APR 1 8 1995
A\aska Oii & Gas cons. Commission
Anchora: ; ~
..
,
Please let me know if this manner of preparing for the hearing is not acceptable to
the commission.
sincer1iJ.' .
/1 J¡Il;
(::-n Siekkin2n
/æ
cc: Ken Boyd, Acting Director
Division of Oil and Gas
John E. Pilkinton, Director
Oil and Gas Audit Division
Department of Revenue
Jim Branch, Manager, Production
Exxon
Al Bolea, Manager, GPMA
BPX
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EJf(ON COMPAN'f, U.S.A.
POST OFFICE BOX 196601 . ANCHORAGE. ALASKA 99519-6601· TELEPHONE (907) 561-5331
Ex h,J,J j)
PRODUCTION DEPARTMENT
ALASKA INTEREST
JAMES F. BRANCH
PRODUCTION MANAGER - ALASKA
April 28, 1995
May 3, 1995 Hearing on
Commingled Production
Mr. David W. Johnston, Chairman
Mr. Russell A. Douglass, Commissioner
Mr. Tuckerman Babcock, Commissioner
Alaska Oil & Gas Conservation Commission
3001 Porcupine Drive
Anchorage, Alaska 99501-3192
Gentlemen:
This letter is in response to the AOGCC's notice of a May 3, 1995 public hearing to address
whether measurement of produced fluids from Niakuk, pt. Mcintyre, Stump Island, West
Beach, North Prudhoe Bay State. and lisburne oil pools is appropriate to satisfy state royalty
accounting, taxation and conservation needs.
Exxon believes the current atlocation methodology using monthly well tests offers proper
precision and verification. While unique in Alaska, this methodology is a common practice in
Lower-48 operations. We believe that the widely diverse, yet significant, ownership interest in
the individual fields offers sufficient incentive for the owners to monitor the Operator's meter
calibration practices and allocation methods to ensure that revenue accounting is accurate.
Exxon's roughly one-third interest in the overall production flowing through the Lisburne
Production Center justifies close scrutiny on our part. As such, the state should have ample
assurance that the measurement and allocation procedures will be as accurate as possible.
Exxon routinely reviews the monthly allocation reports, and periodically participates in audits of
the Operator's meter calibration and allocation procedures. The most recent audit was
conducted in November 1994, by a five person team consisting of representatives from Exxon.
BP Exploration, and ARCO. The team found the Operator's procedures acceptable at
providing equitable determination of production volumes. Exxon is satisfied with the team's
findings, and believes the use of a third party to witness well tests and verify allocation
methodology would duplicate this existing audit process and is thus unnecessary.
Alternatives to the current methodology such as separate processing and measuring facilities
for each reservoir were considered at the time the new fields were developed. While separate
metering had been the more traditional method for Alaska, it could have been pursued only at
A DIVISION OF EXXON CORPORATION
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RECYCLED
..
..
Alaska Oil & Gas
Conservation Commission
2
April 28, 1995
great expense which could have made development of the fields uneconomic. The current
methodology of allocating based on well tests was therefore agreed to by all parties involved,
including the state, as the best means for metering volumes from the subject fields. This
continues to be true today.
The hearing notice suggested that unitizing all reservoirs contributing to the Lisburne
Production Center would be considered as an alternative to the current methodology. We are
unclear how this would provide any greater precision and verification of the quality and
quantity of oil and gas. Additionally, such an undertaking would be a grueling process which
would take a great deal of time and effort. Exxon recommends this option be avoided because
the effort involved would greatly exceed any benefit to the state and the producers relative to
the current process.
Exxon appreciates the opportunity to present our position to the AOGCC. Should arguments
against the current methodology be raised during the hearing, Exxon would request that the
Commission allow us time to evaluate the issues and to respond to the concerns.
c: AI Bolea, BPX
Dan G. Siekkinen, AAI
Sincerely,
IRAB
AOGCCLPC.Doc
OFFICE OF THE COMMISSIONER
Þw::¡ (~( ~ T þ!~,
TONY KNOWLES, GOVERNOR
, /" £,,~ ~;4 £
Vtf 400 WILLOUGHBY AVENUE
JUNEAU, ALASKA 99801-1796
PHONE: (907) 465-2400
FAX: (907) 465-3886
C1 3601 C STREET, SUITE 1210
ANCHORAGE, ALASKA 99503-5921
PHONE: (907) 762-2483
FAX: (907)562-4871
~~&~ΠI- ~~~~~~
DEPARTMENT OF NATURAL RESOURCES
April 26, 1995
Alaska Oil and Gas Conservation Commission
3001 Porcupine Drive
Anchorage, Alaska 99501-3192
Via Fax (276-7542) and Mail
Attn: David W. Johnston, Chainnan
Dear Mr. Johnston:
This letter responds to your letters of April 5 and April 7, 1995. The Alaska Department of
Natural Resources (ADNR) approved the current production allocation methodology that permits
commingled production at the Lisburne Production Center (LPC). The department is generally
satisfied with the operation of the current production allocation methodology, the reporting
requirements and verification opportunities for detennining the volumes of fluids produced and
processed through the LPC.
Given that the Department of Revenue, the ADNR and the Commission participate in the periodic
allocation review meetings and that the agencies have not expressed fundamental concerns with
the methodology, I do not understand the need for a public hearing on this issue and consider
preparing for such a hearing an unwise use of our limited resources. Neither I nor a
representative of the department will be attending the May 3, 1995 hearing.
Sincerely,
cc: John E. Pilkinton - ADOR
Daniel G. Siekkinen - ARCO
RECEIVED
PBU.AOGCC.LPC.Txt
APR 2 8 1995
Alaska 011 &: Gas Cons. Commission
AnchOra!ìP
10·J9LH
pp ff;r";y!"'k"d [1:'1H'i h
04-20-189:::; 10:23
807 . 3000
DNR orr I cc or .. Cm1t1 J:J:J IONCR
P.01
DF¡:lðE OF THE ODMMISSIONER
TONY KNOWLES, QOViRNOR
¿ WILLOUGHBY AVENUE
JUNEAU, ALASKA 11IM01·17N
PHONE: (907) 46$-2400
fOAX: (IIJ'I) 4ØS-IUS
a SBtJ1" STREET. SIJITE 1210
ANOHOFfAGI!, ALA$KA ."O~·~f 11
PHONE: (to'l) 1f2-2œ
FAX: (901)612-4871
DEPARTMENT OF NATURAL RESOURCES
April 26, 1995
Alaska Oil and Gas Conservation Commission
3001 PorcupÎJ1c Drive
Anchorage, Alaska 99501·3192
Via Fax (276..7542) and Mail
Attn: David W. Johnston, Chainnan
Dear Mr. 1ohnston:
This letter responds to your letters of April S and April 7, 1995. The: Alaska Department of
Natural Resources (AONR) approved the current production allocation methodology that pennits
commingled production at the Lisburne Production Center (Lpc). The department is generally
satisfied with the Opc::raLiOl1 of the currcnt production allocation methodnlogy, the reporting
requirements and verification opportunities for detennining the volumes of fluids produced and
processed through the LPC.
Qiven that the Department of Revenueþ the ADNR and the Commission participate in the periodic
allocation review rnceûngs /IJ1d that the agenoies have not expressed fonðamental concerns with
the methodology, I do not ·understand the need for a public hearing on this issue and consider
preparing for such a hearing an ·unwise,.. use of our limited resources. NehhC! I nor a
rcpresentadve of the department will he attendin¡ the May 3, 1995 ,hearing,
Sincerely,
cc: John E. Pilkinton - ADOR
Daniel G. Si~kkinen - ARCO
PBU.AOOCC.LPC.Txt
RECEIVED
10..".LH
APR 26 1-995-
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DEPARTMENT OF REVENUE
OFFICE OF THE COMMISSIONER
April. 26, 1995
Mr. Tuckerman Babcock
Commissioner
Alaska Oil and Gas Conservation Commission
3001 Porcupine Drive
Anchorage, AK 99501
Dear Mr. Babcock:
... 1>tU.r ~f:> [)11'1N1f)
-Y0NY KNOWLES, GOVERNOR
/ £,. 4;bi~ F
/ p.o. BOX 110400
/. JUNEAU, ALASKA 99811-0400
..' TELEPHONE: (907) 465-2300
FACSIMILE.' (907) 465-2389
Thank you for providing an opportunity for the Department of Revenue (OaR)
to share its perspective on the issue of production allocation at the Lisburne
Production Center (LPC). This letter constitutes our department's testimony for the
May 3 hearing. Members of our Staff will also attend to answer any questions. By
copy of this letter, I specifically delegate to John Pilkinton, Director of the Division of
Oil & Gas Audit, Roger Marks, Petroleum Economist, and Dudley Platt, Consultant,
the authority to speak for the Department of Revenue on this matter at the May 3
hearing.
DOR supports facility sharing for producing satellite fields on the North Slope.
Facility sharing significantly reduces capital costs, per-barrel operating costs,
abandonment costs and environmental costs.
Our department first became concerned with the commingling of production in
shared production facilities in 1989 as a result of legislative changes pertinent to the
production tax economic limit factor (ELF). The ELF is a fraction between zero and
one which is multiplied by the statutory severance tax rate to derive the effective tax
rate. Before 1989 the ELF was based solely on the average well productivity for the
pertinent field1. Since different fields have different per well productivity, these fields
would consequently have different ELF and tax rates. Therefore, even prior to 1989 it
would have been important to correctly account for the production from commingled
fields to properly calculate the ELF. In 1989, the Legislature changed the method for
calculating the ELF to include both total daily field productivity and average well
productivity. This change amplified the differences in tax rates between fields and
consequently increased the importance of correctly accounting for the production for
each field contributing to a comminged production stream.
1 When' we say field we are actually referring to the term "lease or property" in the
statute. That term usually means the pertinent participating area.
04-D2LH
RECEIVED
MAX: 1 1995
8Iasl<a.Oll.& Gas Cor' I' "n II"' I . '!1
..
..
Mr. Tuckerman Babcock
April 26, 1995
Page 2
Before commingled production on the North Slope began, OOR conditionally
approved a well-test-based allocation procedure. OOR recognized at that time that
we/l-test-based allocation was not perfect and that we needed to decide whether we
could accept the degree of likely imperfection. Achieving an acceptable level of
precision for the allocation methodology depended on the ability of the operators to
improve significantly on the historical accuracy of well testing at the LPC.
Because of the effect of the ELF, the fields serviced by the LPC have very
different tax rates. Currently Pt. Mcintyre's rate is near 12 percent while the other
fields serviced by the LPC have rates at or near zero. We estimate that a ten percent
allocation error at the LPC, (e.g., an error whereby ten percent of Pt. Mcintyre
production is misallocated to other fields) would cost the state $2 million annually.
We believe the royalty revenue consequences of a serious production
misallocation would be much smaller -- about 5 percent of the possible tax
consequences. This is so because the fields all have comparable royalty rates.
OOR, with outside technical contractual assistance, has developed a
surveillance tool and procedure for measuring well-by-well volumes. The AOGCC has
provided technical support in the continued development of this tool and has provided
OOR with monthly data summarized from information developed by the tool. This
surveillance procedure has allowed OOR to focus on certain still unresolved areas of
the allocation procedure.
There are two primary sources for the remaining allocation errors: 1) isolated
measuring discrepencies and 2) arithmatic allocation mistakes. The former are
troublesome but correctable with continued surveillance. The latter remain
unresolved.
Thank you for the opportunity to testify. We invite the Commission to meet with
our staff if the Commission feels it would be useful to discuss these issues further.
Sin reIY;//
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Wilson L. Condon
Commissioner
RECE\VED
MA Y - 1 \995
A.\a.ska Oil & Gas Cons. Commission
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DEPARTMENT OF NATURAL RESOURCES
DIVISION OF OIL AND GAS
(907) 762-2547
April 21,1995
ARCO Alaska, Inc.
P.O. Box 100360
Anchorage, Alaska 99510-0360
Via Fax (263-4894) and Mail
Attention: D. G. Siekkinen
Manager, Greater Pt. McIntyre Area
Subject: Prudhoe Bay Unit
Niakuk Well NK-27 Tract Operation
Dear Mr. Siekkinem
The Division of Oil and Gas has reviewed ARCO's request to produce the Niakuk NK-27 well
as a Tract Operation (TI2N - RISE, U.M., Sec. 27) within the Prudhoe Bay Unit (PBU), dated
April 21, 1995. The division approves production of the well as a Tract Operation in the PBU
subject to the following terms and conditions:
1) All production from the well shall be allocated to the lease, ADL 34629. On the
monthly royalty report, ARCO aÍ1d Exxon, as the owners of ADL 34629, shall
individually account ror the production from the well.
2) The currently approved wen test allocation methodology for measuring and allocating.
gas and hydrocarbon liquids among all the participating areas that share the Lisburne
Production Center (LPC) is acceptable and satisfactory for royalty purposes and for
allocating gas and hydrocarbon liquids among the PAs and this Tract Operation that will
share the LPC facilities. As with the currently approved allocation methodology, the
division reserves the right to review and revise, if neëessary, the tract well test allocations
to insure compliance with the approved methodology.
RECEIVED
APR 2 5 1995
Alaska au & Gas Cons. Commission
Anch~~ge
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April 21, 1995
Page 2
3) A minimum of two well tests per month will be performed to determine the monthly
production from the NK-27 Well. The individual well test data for each month of tract
production, and the monthly production (oil, gas and water) allocated to the tract should
be separately reported as part of the monthly Greater Pt. McIntyre Area allocated
production report submitted to the division.
4) A gas disposition and reserves debit report that accounts for the gas produced from
each participating area sharing the LPC and all utilization of that gas (fuel, sales,
reinjection, etc.) is subrrJtted to the Division with the monthly production allocation
report. Instead of separately accounting for the NK-27 Tract Operation gas within the
monthly gas reserves and debit report, the Division will permit the gas produced and
allocated to the NK-27 Well to be part of the monthly Niakuk Participating Area gas
reserves and debit report. The intent is to simplify the monthly gas volume accounting
report during the approval period of the NK-27 Tract Operation.
5) Any deductions from the state's royalty value or share of oil produced from the NK-
27 Tract Operation are governed by the 1980 Prudhoe Bay Settlement Agreement. The
royalty value of "NGLs" and gas and deductions from the state's royalty value or share
of "NGLs" and dry gas allocated to the NK-27 Tract Operation are governed by ARCO's
and Exxon's ANS Gas Royalty Settlement Agreement. The royalty value of oil from the
Tract Operation is governed by ARCO's and Exxon's ANS Royalty Litigation Settlement
Agreement.
6) Approval of the NK-27 Tract Operation is given for a period of twelve months
beginning April 21, 1995. A status report for the activities conducted under this tract
operation approval shall be filed with the divisiori every four months.
7) Should the NPA be expanded to include all or portions of the NK-27 Tract Operation
acreage, no reallocation of the royalty share of production allocated to the lease prior to
the effective date of·the revision of the participating area will be permitted.
enneth A. Boyd
Acting Director
cc: David Johnston - AOGCC
John E. Pilkinton - ADOR
PBU.NK27TractOps.txt
p.
.
. ¡<.~ ~r¡. 14-
Lisburne/Point Mcintyre/West Beach
Allocation Methodology
1. Conduct well tests to determine production rates for each well.
Criteria for determining what wells to test:
· Known well performance
· Significant Events
Pre and post well work tests
Diagnostic work (Le. temperature and pressure changes)
Tests for engineering purposes
· Date of last test
2- t,...S eU .t~ ~s
~ V'-'\,A'l~
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--
2. Review well tests for validity.
· How does this well test compare with past well tests for this well
· Was the stabilization period long enough
· Was the test duration long enough
· Did the flowing tubing pressure change significantly during the test
· Did the lift gas rate change during the test
3. Review the significant events for each well. .
· Examine the event history for shutins. openings. gas lift gas changes and choke
changes.
· Examine the drill site operator shift change notes for why a well was shutin and
other items of interest that might have an impact on the oil. water and gas rates of
the wells. This includes, flowing tubing pressure and temperature trends. hot
oiling, hot gassing, methanol treatments. LPC back pressure, field prorations, etc.
4. Calculate each well's theoretical monthly production by combining
well test rates with significant events for that well.
Allocating with no significant events:
· Allocate from the beginning of one well test to the beginning of the next well test.
Allocating with significant events:
· Instead of extrapolating as a well is shutin or extrapolating for flush production
when a well is brought online, it is assumed that the last well test rates are
constant from the beginning of the last well test until the end of the event and that
the current well test rates are constant from the end of the event until the
beginning of the next well test or event.
.
5. Sum the theoretical monthly production volumes for all wells in all
fields.
I
.
.
6. Calculate an allocation factor which compare's the sum of theoretical
monthly production volumes for all wells in all fields to the "Total
Sales" volume as determined by the critical meters.
Allocation Factor
=
"Total Sales" Volume
Sum Of Theoretical Monthly
Production Volumes For All Wells
7. Calculate each well's allocated monthly production volume as:
Allocated Production
Volume
=
Theoretical Production Volume X
Allocation Factor
8. Sum allocated production volumes for each well In each field to
determine the amount of production derived from each field.
I
Allocation Factor Calculations
çxf+~'¡f- I
Allocation Factor =
ActuiProduced Volume
Theoretical Volume (1: Well Tests)
.
TAPS Volume - NGL Volume - TAPS BS&W-
Exploratory Fluids + Unrecoverable Oil -
Oil Factor = I i + i nk M v
1: Well Test Oil Rates
Injected Water Volume - External Water +
Water Factor = TAPS BS&W ±-.Slop Oil.Ismk..Movement
1: Well Test Water Rates
.
Gas Factor
-
LPC Fuel + Injected Gas + OS Fuel -
DS Lift Gas Usage +NGL Shrinkage +
. - B el
I Wells Test Gas Rates
II.
.
.
~f\~/\~ 5'
Greater Point Mcintyre Area Monthly Average Allocation Factors
~ ~ ~ ~ ~ ~ ~ ~ ~ Ë X X · ¡ ¡I· Ë · · · ~ ~ ~
S 3 ~ ~ S S ~ ~ ~ ~ ~ ~ S ~ ~ ~ S m ~ ~ ~ ! ~ ~
~ ~ ~ ~ ~ ~
À
Oil
.
Water
1.2500
1.2000
1.1500
1.1000
1.0500
1.0000
0.9500
0.9000
I ! !
~
I
Monthly Averages
Total
011 Water Gas Llauid
ADr-93 1.0203 0.9636 1.0217 1.0066
May-93 1.0358 1.0052 1.0202 1.0283
Jun-93 1.0387 0.9186 1.0176 1.0103
Jul-93 1.0251 0.9937 1.0411 1.0184
AUQ-93 1.0350 0.9935 1.0258 1.0261
Sep-93 1.0246 1.0641 1.0130 1.0330
Oct-93 1.0152 1.0115 1.0068 1.0150
Nov-93 1.0062 1.0089 1.0064 1.0064
Dec-93 1.0140 1.0873 0.9854 1.0178
Jan-94 1.0179 1.0285 0.9746 1.0186
Feb-94 1.0086 1.0733 0.9622 1.0130
Mar-94 1.0020 1.0894 0.9724 1.0084
Apr-94 0.9978 1.1283 0.9659 1.0079
May-94 0.9976 1.0915 0.9718 1.0049
Jun-94 1.??oo 1.0119 0.9777 1.0010
Jul-94 1.0097 1.1455 0.9989 1.0207
Aua-94 1.0092 0.9482 1.0068 1 .0039
Sep-94 1.0063 1.0239 0.9848 1.0072
Qct-94 1.0025 1.0385 0.9712 1.0045
Nov-94 1.0035 1.0790 0.9864 1.0090
Dec-94 1.0067 1.0292 0.9954 1 .0084
Jan-95 1.0104 1.0859 0.9916 1.0158
Feb-95 1.0091 1.1384 0:9913 1.0193
Mar-95 1.0125 1 .2405 1.0120 1.0333
III
.
Gas
~ Total Liquid I
Cumulative Averages Since 10192
Total
011 Water Gas LiQuid
1.0375 0.9885 1.0166 1.0256
1.0373 0.9906 1.0171 1.0259
1 .0373 0.9885 1.0171 1.0254
1.0360 0.9890 1.0195 1.0247
1.0359 0.9893 1.0200 1.0249
1.0351 0.9942 1.0195 1.0254
1.0314 0.9950 1.0186 1.0238
1.0254 0.9959 1.0177 1.0202
1.0231 1.0015 1.0154 1.0198
1.0223 1.0032 1.0127 1.0196
1 .0206 1.0073 1 .0096 1.0188
1.0183 1.0128 1.0073 1.0176 I
1.0161 1.0203 1.0051 1.0166
1.0142 1.0251 1.0034 1.0155
1.0128 1.0242 1.0021 1.0141
1.0126 1.0313 1.0020 1.0147
1.0123 1.0261 1.0022 1.0138
1.0118 1.0260 1.0014 1.0133
1.0111 1.0265 1.??oo 1.0126
1.0105 1.0291 0.9994 1.0124
1.0103 1.0291 0.9993 1.0121
1.0103 1.0319 0.9990 1.0123
1.0102 1.0372 0.9987 1.0127
1.0103 1.0492 0.9992 1.0140
100.0
90.0
80.0
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- 70.0
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PHASE DYNAMICS METER VS. SHAKEOUTS
. ------
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--- --.-
50.0 - -~------ ---
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o
.u..~__.... _ ......_._ ...
...---- ..----.-.-.. .". --_._---
40.0 ...--."---- -~--.-
------.-.-- --_.- -.---.-.--..------ -". .."_. .....-..
- ________._____'__ __....__._ _...___ _.... ._" .__.n
__"F .-.--__ - _ ________ ._____. __.____.... '... ... .._. _ ___or
- -------
--~-_. --'-".-'--- ----------.-- .-.-----.-
.---.---- -------... ------_. -------- .---------.-..---- --.-------.---.."-- --,.--
-.. ...----___ --.._._ ___.___ ___·_4"_____ ___...__ _ __...__" ___.__,_~.__ ..____ _..__.______ __
0.0
0.0
10.0
20.0
30.0
30.0
20.0
10.0
40.0
50.0
60.0
70.0
80.0
SHAKEOUT we (%)
~_.
] 1993
. - -- ...--..
. 1994
/\ 1 ST QTR 19.95 1.
-.--.-----.--------.---- --
nz:
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100.0
CJA 2/28/9~
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#9
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ALASKA OIL AND GAS CONSERVATION COMMISSION
NAME & COMPANY
(PLEASE PRINT)
(2IJ59,/ ¡Y1 .:;"f)
DL1 D I.K:1 PC/Jr-rr
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Commingling Production
Pre-Hearing - May 3, 1995
SIGN IN PLEASE
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EJf(ON COMPANY: U.S.A.
POST OFFICE BOX 196601' ANCHORAGE, ALASKA 99519-6601' TELEPHONE (907) 561-5331
PRODUCTION DEPARTMENT
ALASKA INTEREST
JAMES F. BRANCH
PRODUCTION MANAGER - ALASKA
April 28, 1995
May 3, 1995 Hearing on
Commingled Production
Mr. David W. Johnston, Chairman
Mr. Russell A. Douglass, Commissioner
Mr. Tuckerman Babcock, Commissioner
Alaska Oil & Gas Conservation Commission
3001 Porcupine Drive
Anchorage, Alaska 99501-3192
RECEIVED
APR 2 8 1995
Alaska Oil & Gas Cons. Commission
Anchorél '1 -
Gentlemen:
This letter is in response to the AOGCC's notice of a May 3, 1995 public hearing to address
whether measurement of produced fluids from Niakuk, Pt. Mcintyre, Stump Island, West
Beach, North Prudhoe Bay State and Lisburne oil pools is appropriate to satisfy state royalty
accounting, taxation and conservation needs.
Exxon believes the current allocation methodology using monthly well tests offers proper
precision and verification. While unique in Alaska, this methodology is a common practice in
Lower-48 operations. We believe that the widely diverse, yet significant, ownership interest in
the individual fields offers sufficient incentive for the owners to monitor the Operator's meter
calibration practices and allocation methods to ensure that revenue accounting is accurate.
Exxon's roughly one-third interest in the overall production flowing through the Lisburne
Production Center justifies close scrutiny on our part. As such, the state should have ample
assurance that the measurement and allocation procedures will be as accurate as possible.
Exxon routinely reviews the monthly allocation reports, and periodically participates in audits of
the Operator's meter calibration and allocation procedures. The most recent audit was
conducted in November 1994, by a five person team consisting of representatives from Exxon,
BP Exploration, and ARCO. The team found the Operator's procedures acceptable at
providing equitable determination of production volumes. Exxon is satisfied with the team's
findings, and believes the use of a third party to witness well tests and verify allocation
methodology would duplicate this existing audit process and is thus unnecessary.
Alternatives to the current methodology such as separate processing and measuring facilities
for each reservoir were considered at the time the new fields were developed. While separate
metering had been the more traditional method for Alaska, it could have been pursued only at
A DIVISION OF EXXON CORPORATION
@
RECYCLED
.
.
Alaska Oil & Gas
Conservation Commission
2
April 28, 1995
great expense which could have made development of the fields uneconomic. The current
methodology of allocating based on well tests was therefore agreed to by all parties involved,
including the state, as the best means for metering volumes from the subject fields. This
continues to be true today.
The hearing notice suggested that unitizing all reservoirs contributing to the Lisburne
Production Center would be considered as an alternative to the current methodology. We are
unclear how this would provide any greater precision and verification of the quality and
quantity of oil and gas. Additionally, such an undertaking would be a grueling process which
would take a great deal of time and effort. Exxon recommends this option be avoided because
the effort involved would greatly exceed any benefit to the state and the producers relative to
the current process.
Exxon appreciates the opportunity to present our position to the AOGCC. Should arguments
against the current methodology be raised during the hearing, Exxon would request that the
Commission allow us time to evaluate the issues and to respond to the concerns.
c: AI Bolea, BPX
Dan G. Siekkinen, AAI
Sincerely,
¡RAB
AOGCCLPC.Doc
RECEIVED
APR 2 8 1995
Alaska Oil & Gas Cons. Commission
Anchor;: ¡
#7
.
.
TONY KNOWLES, GOVERNOR
OFFICE OF THE COMMISSIONER
P.O. BOX 110400
JUNEAU, ALASKA 99811-0400
TELEPHONE: (907) 465-2300
FACSIMILE: (907) 465-2389
DEPARTMENT OF R~VENUE
April. 26, 1995
Mr. Tuckerman Babcock
Commissioner
Alaska Oil and Gas Conservation Commission
3001 Porcupine Drive
Anchorage, AK 99501
Dear Mr. Babcock:
Thank you for providing an opportunity for the Department of Revenue (DOR)
to share its perspective on the issue of production allocation at the Lisburne
Production Center (LPC). This letter constitutes our department's testimony for the
May 3 hearing. Members of our Staff will also attend to answer any questions. By
copy of this letter, I specifically delegate to John Pilkinton, Director of the Division of
Oil & Gas Audit, Roger Marks, Petroleum Economist, and Dudley Platt, Consultant,
the authority to speak for the Department of Revenue on this matter at the May 3
hearing.
DOR supports facility sharing for producing satellite fields on the North Slope.
Facility sharing significantly reduces capital costs, per-barrel operating costs,
abandonment costs and environmental costs.
Our department first became concerned with the commingling of production in
shared production facilities in 1989 as a result of legislative changes pertinent to the
production tax economic limit factor (ELF). The ELF is a fraction between zero and
one which is multiplied by the statutory severance tax rate to derive the effective tax
rate. Before 1989 the ELF was based solely on the average well productivity for the
pertinent field1. Since different fields have different per well productivity, these fields
would consequently have different ELF and tax rates. Therefore, even prior to 1989 it
would have been important to correctly account for the production from commingled
fields to properly calculate the ELF. In 1989, the Legislature changed the method for
calculating the ELF to include both total daily field productivity and average well
productivity. This change amplified the differences in tax rates between fields and
consequently increased the importance of correctly accounting for the production for
each field contributing to a comminged production stream.
1 When we say field we are actually referring to the term "lease or property" in the
statute. That term usually means the pertinent participating area.
RECEIVED
04-D2LH
81as))a. .011.& Gas Cons. Commissil1ln
.
.
Mr. Tuckerman Babcock
April 26, 1995
Page 2
Before commingled production on the North Slope began, DOR conditionally
approved a well-test-based allocation procedure. DOR recognized at that time that
well-test-based allocation was not perfect and that we needed to decide whether we
could accept the degree of likely imperfection. Achieving an acceptable level of
precision for the allocation methodology depended on the ability of the operators to
improve significantly on the historical accuracy of well testing at the LPC.
Because of the effect of the ELF, the fields serviced by the LPC have very
different tax rates. Currently pt. Mcintyre's rate is near 12 percent while the other
fields serviced by the LPC have rates at or near zero. We estimate that a ten percent
allocation error at the LPC, (e.g., an error whereby ten percent of Pt. Mcintyre
production is misallocated to other fields) would cost the state $2 million annually.
We believe the royalty revenue consequences of a serious production
misallocation would be much smaller -- about 5 percent of the possible tax
consequences. This is so because the fields all have comparable royalty rates.
DOR, with outside technical contractual assistance, has developed a
surveillance tool and procedure for measuring well-by-well volumes. The AOGCC has
provided technical support in the continued development of this tool and has provided
DOR with monthly data summarized from information developed by the tool. This
surveillance procedure has allowed DOR to focus on certain still unresolved areas of
the allocation procedure.
There are two primary sources for the remaining allocation errors: 1) isolated
measuring discrepencies and 2) arithmatic allocation mistakes. The former are
troublesome but correctable with continued surveillance. The latter remain
unresolved.
Thank you for the opportunity to testify. We invite the Commission to meet with
our staff if the Commission feels it would be useful to discuss these issues further.
Sin reIY://
~¡X,_t!T/
Wilson L. Condon
Commissioner
----
RECE\VED
MAY ~ 1 1995
Alaska Oil & Gas Cons. Commission
Anchora· ~'
#6
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DEPARTMENT OF NATURAL RESOURCES
¡
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TONY KNOWLES, GOVERNOR
~ WILLOUGHBY AVENUE
JUNEAU, ALASKA 99801-1796
PHONE: (907) 465-2400
FAX: (907) 465-3886
t:1 3601 C STREET, SUITE 1210
ANCHORAGE, ALASKA 99503-5921
PHONE: (907) 762-2483
FAX: (907)562-4871
OFFICE OF THE COMMISSIONER
I
}
i
r
i
April 26, 1995
Alaska Oil and Gas Conservation Commission
3001 Porcupine Drive
Anchorage, Alaska 99501-3192
Via Fax (276-7542) and Mail
Attn: David W. Johnston, Chainnan
Dear Mr. Johnston:
This letter responds to your letters of April 5 and April 7, 1995. The Alaska Department of
Natural Resources (ADNR) approved the current production allocation methodology that permits
commingled production at the Lisburne Production Center (LPC). The department is generally
satisfied with the operation of the current production allocation methodology, the reporting
requirements and verification opportunities for determining the volumes of fluids produced and
processed through the LPC.
Given that the Department of Revenue, the ADNR and the Commission participate in the periodic
allocation review meetings and that the agencies have not expressed fundamental concerns with
the methodology, I do not understand the need for a public hearing on this issue and consider
preparing for such a hearing an unwise use of our limited resources. Neither I nor a
representative of the department will be attending the May 3, 1995 hearing.
Sincerely,
cc: John E. Pilkinton - ADOR
Daniel G. Siekkinen - ARCO
RECEIVED
PBD.AOGCC.LPC.Txt
APR 2 8 \995
Alaska 011 &. Gas Cons. Commission
Anchora; . '"
10-J9LH
#5
ARca Alaska, Inc.
Post Office Box 1 00360
Anchorage, Alaska 99510-0360
Telephone 907 2761215
.
qq-.
ð-() i'h 1\'í V' I ~
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~~
,.....
Daniel G. Siekkinen
Manager
Greater Pt. Mcintyre Area
April 13, 1995
David Johnston, Chairman
Oil and Gas Conservation Commission
3001 Porcupine Drive
Anchorage, AK 99501-3192
Production Allocation Hearing
Dear Mr. Chairman:
I appreciate the time you and the other commissioners took to meet with Ron Oba
and me to discuss the upcoming May 3, 1995, hearing on production allocation for
fluids from the various fields that are produced through the Lisburne Production
Center. At that meeting, it was suggested that ARCO might reserve response to
any criticisms or potential alternative actions unless and until evidence
suggesting the need for a change were presented. It was suggested that if such
evidence were presented, the hearing could be continued to a later date for
additional testimony. ARCO believes this is sound proposal, and therefore plans
on approaching the hearing in the following manner.
As the operator of the Lisburne Production Center, ARCO will testify to the
history of its efforts to seek and obtain approvals for the current methodology
from the affected Working Interest Owners, the Department of Natural Resources,
the Department of Revenue, and the Alaska Oil and Gas Conservation
Commission. ARCO will also present testimony summarizing the operation of
the methodology, which is functioning at least as well as planned. Finally, it will
testify to the results of the periodic reviews required by the various agencies as a
condition of their approvals, at which no fundamental criticisms have been
raised.
We do not anticipate that concerns, criticisms, or suggestions will be raised by any
of the affected entities. Since we received the notice, we have talked informally
with the DOR, DNR, BPX and Exxon, and none have expressed a fundamental
concern or a need for any change. If a concern is raised at the hearing, we suggest
that it would then be appropriate for all parties to be granted time to evaluate the
issues before responding. This deferral of consideration of alternatives will save
time and expense if the hearing confirms our belief that the current system and
its operation is not broken. R E ~ E , V ED
APR 1 8 1995
ÞJaska Oü & Gas Cons. Commission
Anchora r\
-.~
.
.
Please let me know if this manner of preparing for the hearing is not acceptable to
the commission.
S in1JLerel' ,
@<-
! )
Dan Siekkinen
fa:;
cc: Ken Boyd, Acting Director
Division of Oil and Gas
John E. Pilkinton, Director
Oil and Gas Audit Division
Department of Revenue
Jim Branch, Manager, Production
Exxon
Al Bolea, Manager, GPMA
BPX
#4
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April 9, 1995
David W. Johnston
r An"1n"11 C C1 An Dr
.........'\...E..I...I..L.i.i...L.I..~ü...i.\...J'......&.........L
Alaska Oil & Gas Conservation Commission
3001 Porcupine Drive
Anchorage, Alaska 99501-3192
Subject: Senate Bill 99 & House Bill 46 - "An Act relating to the
practice of architectl.lre, enghleering, and land surveying."
Dear Mr. Johnston,
As a Registered Engineer and Chairman of the AOGCC, you may have a
keen interest in the above bills which are currently moving quiddy
through the Alaska Legislature with little public hearing or testimony. In
1990, the Legislature repealed a then existing exemption which allowed
large utilities and resource development companies to avoid utilizing
engineers who were licensed by the state as "Registered Engineers". The
utilities and resource companies have failed to comply with the new
statutes and are now mounting a campaign to change the law so they are
again exempted from having to utilize licensed engineers.
The safety and welfare of Alaskan's is impacted by these Bills. For
example, monthly oil and gas production is reported to the State by the
producers. This includes commingled oil production and natural gas
liquids. As you know commingled production allocation is a calculated,
not measured, volume. It is these production calculations and subsequent
reports which are used to determine royalty and severance liabilities to
the State. Senate Bill 99 would allow for these production calculations to
be done not only by unlicensed engineers but potentially by la",-yers,
accountants or high school interns. The next time a producer gives
testimony to the Commissioner ask if the engineering calculations and
plans were reviewed by a Registered Engineer!
This proposed legislation is bad public policy and anti-local hire. I don't
understand why I need a Registered Engineer to approve a water well plan
for my cabin but no such approvals are necessary to drill an oil well or
change it from production to injection.
Sincerely,
(j~ Bitizul/am:I 0/'~
RE(EIVED
APR 1 1 1995
Alaska OU & Gas Cons. Commission
Anchorage
.
.
SB 99 & HB 46
"An Act relating to the practice of architecture,
engineering, and land surveying."
Occupational licensing helps to ensure that only "qualified" persons practice
and/ or offer services to the public. Engineering has fallen into the category of
licensing since a rash of boiJer explosions in schools and public buiJdings in the
1800's started to maim and kill hundreds of people every year. Excluding a
person who "practices engineering involved in the operation of the employers
business only" (Sec. 3. 08.48.331) defeats the purpose of licensing the occupation.
This wording would exclude the Alaska Railroad, gas and electric utilities, the
phone companies, mining and other resource production companies from
having to utilize licensed engineers. Consider the following cases which all
happen on private property (owned or leased); 1) a railroad bridge fails and
toxins are released into a local ,vater supply, 2) power to the cirý is interrupted
for over 12 hours due poor equipment design causing hospitals to complete
surgeries and maintain life support systems using emergency power (if the
emergency power systems work), 3) seven people including one employee die
from hydrogen sulfide poisoning due to improper material selection on a valve,
and 4) a Teamster is severely burned in a fire caused by overloaded electrical
circuits while staying at a North Slope camp. Are these cases real or
hypothetical?
Consider this: Would the large companies promoting this exclusion consider
employing lawyers for internal legal counsel who were not members of the
state Bar? Would large companies hire unlicensed physicians to practice
medicine on the injured contract workers or sick employees? Of course not!! I
believe the real issue is why the larger capital intensive employers have failed
abide by the statute for the last four years!
To save more money will the next exemption request be for utilizing unlicensed
electricians and pipefitters? If the legislature and governor are really for local
hire why are they exempting the licensing of engineers when ARCa is laying
off engineers who are already "Registered" and live in Alaska?
Similarly, the current exemption for "a person who is employed by a post
secondary educational institution to teach engineering" should be repealed. The
public should not stand for unqualified and unlicensed engineers to teach
engineering. The exemption is in direct conflict with the definition of the
"practice of engineering" contained in the existing statute "(9) "practice of
engineering" means professional service or creative work, the adequate
performance of which requires the specialized knowledge of applied
mathematics and sciences, dealing with the design of structures, machines,
equipment, utilities systems, materials, processes, works, or projects, public or
private; the teaching of advanced engineering courses in institutions of
higher learning;" (Sec. 08.48.341) Items in BOLD are added emphasis. Its irorÜc
that you have to be licensed to teach preschool but not to teach engineering!
RE(EIVED
APR 11 1995
Alaska Oil & Gas Cons. Commission
An"h, . {.
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ALASIiA. OIL AND GAS
CONSERVATION COJDIISSION
..TONY KNOWLES, GOVERNOR
3001 PORCUPINE DRIVE
ANCHORAGE. AlASKA 99501-3192
PHONE: (907) 279-1433
FAX: (907) 276-7542
April 7, 1995
Wilson L. Condon, Commissioner
Department of Revenue
P.O. Box 110400
Juneau,AJaska 99801-1796
Dear Commissioner Condon:
The Commission previously wrote you requesting testimony in our commingling/allocation
hearing schedule for May 3, 1995. The Commission wants to assure proper allocation and
verification to protect state interests.
A possible alternative you may wish to present at hearing is for state agencies to combine
resources and jointly develop an oversight program. Currently, each agency devotes some
staff time and money to reviewing industry's reports. Unfortunat~ly, each agency is spread
too thin for any to do an adequate job. This appears clear from previous meetings, where
your staff has expressed concern with the adequacy of state oversight.
If resources can be combined to assure proper oversight and satisfy agency concerns, then
it may not be necessary for the Commission to pursue incremental funding, or implement
one of the three alternatives outlined in our hearing notice. Such an effort, if successful,
would be fiscally responsible and compliment sound resource management.
We would be pleased to discuss this idea with you further should you desire.
David W. Jo
Chairman
@ ~ fÄ\ "-1::"1 Œ·¡<~
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TONY KNOWLES, GOVERNOFJ
AlASKA OIL AlU) GAS
CONSERVA.TION COMMISSION
3001 PORCUPINE DRIVE
ANCHORAGE. ALASKA 99501-3192
PHONE: (907) 279-1433
FAX: (907) 276-7542
April 7, 1995
John Shively, Commissioner
Department of Natural Resources
400 Willoughby Ave.
Juneau, AJaska 99801-1796
Dear Commissioner Shively:
The Commission previously wrote you requesting testimony in our commingling/allocation
hearing schedule for May 3, 1995. The Commission wants to assure proper allocation and
verification to protect state interests.
A possible alternative you may wish to present at hearing is for state agencies to combine
resources and jointly develop an oversight program. Currently, each agency devotes some
staff time and money to reviewing industry's reports. Unfortunately, each agency is spread
too thin for any to do an adequate job. This appears clear trom previous meetings, where
your staff has expressed concern with the adequacy of state oversight.
If resources can be combined to assure proper oversight and satisty agency concerns, then
it may not be necessary for the Commission to pursue incremental funding, or implement
one of the three alternatives outlined in our hearing notice. Such an effort, if successful,
would be fiscally responsible and compliment sound resource management.
We would be pleased to discuss this idea with you further should you desire.
#2
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ALASfiA OIL AM) GAS
CONSERVATION comnSSION ,
TONY KNOWLES. GOVERNOR
3001 PORCUPINE DRIVE
ANCHORAGE, AI.ASI<A 99501-3192
PHONE: (907) 279-1433
FAX: (907) 276-7542
AprilS, 1995
John Shively
Commissioner
Department of Natural Resources
400 Willoughby Avenue
Juneau,AK 99801
Dear Commissioner Shively:
The Alaska Oil and Gas Conservation Commission has scheduled a hearing on
commingled production on May 3, 1995. A public notice is attached to this letter.
The Commission requests your presence or your designee with written authority to speak
for the Department of Natural Resources under oath. The reason the Commission makes
this request is to obtain the royalty owner's sworn testimony regarding its satisfaction with
the allocation, reporting requirements and verification opportunity for determining the
quantity and quality of hydrocarbons produced by the five fields whose production is
commingled and processed at the Lisburne Production Center.
If you will not be able to attend, please let us know by April 21, 1995 who you will
designate to represent the Department of Natural Resources at this hearing.
#1
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Diana Fl@ek 04-04-95
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STATE OF ALASKA
ADVERTISING .
ORDER
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AOGCC
3001 Porcupine Urive
Ån~horaU0, AK 995Q1
T
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C 15941 N Eagle River Loop Road
8 Eagle River, AK 99571-7499
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UNITt:D 3T ~TE'G CF AMERICt-.
REMINDER-
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AFFI DA VITOF: PUBLICATION
STATE OF A/@KCJ...-.- sa
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&d 1)' o.rct'fJ-L DIVISION. I ;:~~~; ~;~~. ;~.;;;~ .;~;~ ~;;;;~~;T 01: PUBLICATION
I MUST BE SUSMITTED WITH THE INVQICI:.
SEFORE ME, THE UNDERSIGNED, A NOTAF., pJ}~I. r. !"!:f~ ')W I
~o ~~ e:!!c- r -' . ATTACH PROOF OF puaLlCU,O!l HERE.
BEING FJRST DULY $Wv:'i~,~~~:-':¡P:~:, i:6 LAW, S/·,". . T""'J~'~ ~
HE/SHE IS THE __ ~->--.__OF (!LtC} f é~ L - <..~L. m-1 :s,~
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PUBLISHED AT._io.~l.9. .._e~1- __ _ _ IN SAID Oh.· .:- :
.._ AND STATE OF AL..- ANt) THAT THe
INVOICE MUST BE IN TRIPU~AT¡:A.N!:I MU~T REFERENCE
PERSONALL. Y AP¡: =ARED
ADVERT/SEMEN'f, af: W:'II~t1 ~... ¡; Ái\ N~ED ¡õ Å iñü¡::COI'Y, WAi:J
PUBLISHED IN SAID PUBLICATION 01; ;-,..[ _-.2,t/\ __ Dµ'! 0l~ ¡
I A(û t 19ßr: AND THr:nFAF""(;p ¡C,::,: ·-1-- !
I CONSECUTIVE DA YS, THE LAST PUBLICATION APPEARING ON THE I
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RATE CHARGED THEREON IS NOT IN EXCESS OF THE .RATs..Jmm~
~~'''~~ M:'fq~
CHARGED PAIV TE ;7D~""~~e._ O.iN2,-, . ~ t~9.j'''t('"'.!!.t~~
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THlo-LlDAyor ¡e~~t~)J (:}J! LI\~.iF
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l NOTARY PU IcrFÇr\ rA ¡E ü¡': _(1_ j'/~.{tQF~\..~\~
MY COMMISSION è.XPI....~ij ." N.ÔTARY PUSiIC IN AND FORm-_U~~Ii\\\\W
02.901 (Flev.6-85) . ---' -. - -n-tF-AlASKArMlf &ÐMMISSI9N CXPIReS . - .
MARCH 12TH 1997.
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-__.._.1
_DAY OF ___.
PUBLISHER
.
990-Legal Notice
NOTICE OF PUBLIC HEARING
STATE OF ALASKA
ALASKA OIL AND GAS
CONSERVATION COMMISSION
Re: Commingled Production
The Alaska Oil and Gas ConselVa-
tion Commission, acting on its own
motion, will hold a hearing on May 3,
1995 beginning at 1:30 pm at 3001
Porcupine Drive, Anchorage, Alaska.
The hearing will address whether
measurement of produced fluids from
Niakuk, PI. Mcintyre, Stump Island,
West Beach. North Prudhoe Bay State
and Lisburne oil pools is appropriate to
satisty state royalty accounting, taxa-
tion and conselVation needs.
The Commission will consider
whether current allocation methodol-
ogy using monthly well test offers
proper precision and verification op·
portunity. The Commission must be
assured that existing methodology
can determine the quality and quantity
of oil and gas.
.
#14697
STOF 0330
AO-02-5-14-43
$58.00
AFFIDA vir OF PUBLICATION
STATE OF ALASKA.
THIRD JUDICIAL DISTRICT.
Notice 01 Public Hearing
STATE OF ALASKA
Alaska 011 and Gas
onservo .0
S0
March 31, 1995
R E: Co roduction
Alaska Oil and Gas
Conservation Commission, oct·
ing on its own motion, will
hold 0 hearing on May 3, 1995
beginning at 1:30 pm at 3001
Porcupine Drive, Anchorage,
Alaska. The hearing wIll ad·
dress whether measurement 01
produced fluids from Niakuk,
Pt. Mclntrye, Stump Island,
West Beach, North Prudhoe
Boy State and Lisburne oil
pools is ~ppropriate to satisfY
state royalty accounting, taxa.
tion and conservation needs.
The Commission will consid·
er whether current allocation
methodology using monthly
well tests offers proper preci·
sian and yerificotion opportu'
nlty. The Commission must be
assured that existing method·
ology con determine the quail·
ty and quonllly of 011 and gas.
The Commission will consld·
er alternatives to current
methodology Including:
1. Regarding the mineral
interest owners and royalty
owners to hire 0 Commis-
sion·approved third party to
witness well tests and verify
aliocation methodology.
2. Requiring separate pro·
cessing and measuring facil·
Ities for each reservoir.
3. Utilizing 011 reservoirs
t contributing to 0 single pro·
I cessing facility. .
! The Commission will consider I
testimony from 011 interested
parties. If yoU ore 0 person
I with 0 disability who may need
i 0 special modification In order
'to comment on the proposed
regulations or to attend the
public hearing, please contact
Oiono Fleck at 279· 1433 no later
than April 27, 1995.
IslTuckermon Babcock
Commissioner
!,ub: __March 31, 1995
Eva M. Kaufmann
...................................................
being first duly sworn on oath
deposes and says that he/she ;s
an advertising representative of
the Anchorage Daily News, a
daily newspaper. That said
newspaper has been approved
by the Third Judicial Court.
Anchorage. Alaska. and it now
and has been published in the
English language continually as a
daily newspaper in Anchorage.
Alaska. and it is now and during
all said time was printed in an
office maintained at the aforesaid
place of publication of said
newspaper. That the annexed is
a copy of an advertisement as it
was published in regular issues
(and not in supplemental form) of
said newspaper on
and that such newspaper was
regularly distributed to its
subscribers during all of said
period. That the full amount of
the fee charged for the foregoing
publication is not in excess of
the rate charged private
individuals.
signed 6-n ~ ~~
Subscribed and sworn to before
me thi'!J.31.Cf!?o?-!J];:u.~
Q5
o H~0 {.udJm;dû;
~;:~:a In and for
the State of Alaska.
Third Division.
Anchorage. Alaska
MY COMMISSION EXPIRES
MY COMMISSION EXPIRE$
............ ..J.lnY. .Z~...I.q96............ 19. .....
