STATE OF ALASKA

OIL AND GAS CONSERVATION COMMISSION
3001 Porcupine Drive
Anchorage, Alaska 99501-3192

Re:The Application of ARCO Alaska , Inc. and BP           ) Conservation Order No. 341B
   Exploration (Alaska) Inc. requesting administrative    )
    changes to Conservation Order 341A, Rules 6(a) and    ) Prudhoe Bay Field
    6(b) regarding annual pressure surveys in the Prudhoe ) Prudhoe Oil Pool
    Oil Pool.                                             )
                                                            November 17, 1995

IT APPEARING THAT

  1. By letter dated October 3, 1995, ARCO Alaska, Inc. and BP Exploration (Alaska), Inc. requested changes to Rule 6 (a) and 6 (b).
  2. The Commission reviewed the request and available data and proceeded administratively to change Rule 6 (a) and (b).
  3. Changes to Rule 6(a) and 6(b) were consolidated with Rules previously approved for the Prudhoe Oil Pool in Conservation Order 341A (consolidated).

Findings:

  1. Conservation Order 341A Rule 6(e) provides Commission the means to administratively approve time extensions and waive requirements of Rule 6 and may administratively order additional surveys under part (b).
  2. Surveys are currently required in each new well prior to regular production. Rule 6(b) requires a minimum of 95 and 87 (182 total) surveys for the WOA and EOA respectively. The minimums were established in 1986.
  3. Nearly 5300 pressure surveys have been conducted in the Prudhoe Oil Pool since production began in 1977. Since the minimum requirements were established in 1986, approximately 2400 survey have been done through 1994, an average of 267 per year.
  4. The number of surveys run each year may be determined based on data needs or may be set arbitrarily.
  5. Development drilling typically occurs consecutively on a pad and numerous initial pressure surveys may be concentrated near that pad.
  6. Data concentrated near one pad may be redundant and waste opportunities to learn about other areas of the reservoir.
  7. Reservoir management and technical considerations provide justification for determining the number of pressure surveys to run in any given time period in a mature or developing oil or gas pool.
  8. As a reservoir matures, the data requirements change and more or less data may be required to adequately monitor reservoir mechanisms.
  9. Consolidation of changes to Rule 6(a) and (b) into the previous version of Conservation Order 341A will keep all pertinent orders affecting management of the Prudhoe Oil Pool in one Conservation Order.
  10. The operators periodically plan reservoir surveillance activity in order to budget time, manpower and resources.
  11. The operators expect the number of surveys required to decrease with time in the mature areas of the pool.

Conclusions

  1. Conservation Order 341A Rule 6(e) allows the Commission to waive requirements of Rule 6 by administrative approval. In addition, Rule 6(e) allows the Commission to require more surveys by administrative order.
  2. Prescribing a specific number of pressure surveys to run on an annual basis may cause waste of resources and provide redundant information in some areas of the reservoir.
  3. Reservoir management and technical requirements should be prime considerations for design of a pressure surveillance program in a mature reservoir.
  4. A pressure survey plan shall be submitted to the Commission annually in conjunction with the Annual Prudhoe Oil Pool Surveillance Report required by Conservation Order 341A, Rule 11.
  5. Consolidation of changes in Rule 6(a) and 6(b) with the Rules previously issued under Conservation Order 341A will not promote waste, harm ultimate recovery nor jeopardize correlative rights.
  6. Consolidation will prevent proliferation of multiple Orders governing management of the same pool.

NOW, THEREFORE, IT IS ORDERED THAT the changes to Rule 6(a) and 6(b) and the rules previously adopted under Conservation Order 341A hereinafter set forth apply to the following described area referred to in this order as the affected area:

UMIAT MERIDIAN

       

T. 10N.,

R. 12E.,

Sections:

1, 2, 3, 4, 10, 11, 12

       

T. 10N.,

R. 13E.,

 

1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 24

       

T. 10N.,

R. 14E.,

 

1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 36

       

T. 10N.,

R. 15E.,

 

all

       

T. 10N.,

R. 16E.,

 

5, 6, 7, 8, 17, 18, 19, 20, 29, 30, 31

       

T. 11N.,

R. 11E.,

 

1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 24, 25

       

T. 11N.,

R. 12E.,

 

all

       

T. 11N.,

R. 13E.,

 

all

       

T. 11N.,

R. 14E.,

 

all

       

T. 11N.,

R. 15E.,

 

all

       

T. 11N.,

R. 16E.,

 

17, 18, 19, 30, 31, 32

       

T. 12N.,

R. 10E.,

 

13, 24,

       

T. 12N.,

R. 11E.,

 

15, 16, 17, 18, 19, 20, 21, 22, 25, 26, 27, 28, 29, 30, 32, 33, 34, 35, 36

       

T. 12N.,

R. 12E.,

 

23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36

       

T. 12N.,

R. 13E.,

 

19, 20, 21, 22, 23, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36

       

T. 12N.,

R. 14E.,

 

25, 26, 27, 28, 29, 31, 32, 33, 34, 35, 36

       

T. 12N.,

R. 15E.,

 

25, 26, 27, 28, 29, 30 ,31 ,32, 33, 34, 35, 36

(Source: C. O. 145, page 7, expansions/contractions of initial participating area based on November 20, 1987 letter, Wade and Nelson to Eason, Re: Prudhoe Bay Unit Exhibits, Exhibit C, Part I Oil Rim Participating Area and Part II Gas Cap Participating Area.)

Rule 1 Pool Definition and Changing the Affected Area (ref. C.O. 145)

(a) The Prudhoe Oil Pool is defined as the accumulations of oil that are common to and which correlate with the accumulations found in the Atlantic Richfield - Humble Prudhoe Bay State No. 1 well between the depths of 8,110 feet and 8,680 feet.
(Source: C.O. 145, Rule 1)

(b) The Commission may adjust the description of the affected area to conform to future changes in the initial participating area by administrative approval.
(Source: C. O. 145, Rule 12)

Rule 2 Well Spacing (ref. C.O. 145, 174)

There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area.
(Source: C.O. 174, Rule 2)

Rule 3 Casing and Cementing Requirements (ref. C.O. 145, 238)

(a) Conductor casing shall be set at least 75 feet below the surface and sufficient cement shall be used to fill the annulus behind the pipe to the surface. Rigid high density polyurethane foam may be used as an alternate to cement, upon approval by the Commission. The Commission may also administratively approve other sealing materials upon application and presentation of data which show the alternate is appropriate based on accepted engineering principles. (Source: C.O. 238, Rule 3a)

(b) Surface casing to provide proper anchorage for equipment, to prevent uncontrolled flow, to withstand anticipated internal pressure, and to protect the well from the effects of permafrost thaw-subsidence or freeze-back loadings shall be set at least 500 feet, measured depth, below the base of the permafrost but not below 5000 feet true vertical depth. Sufficient cement shall be used to fill the annulus behind the casing to the surface. The surface casing shall have minimum axial strain properties of 0.5% in tension and 0.7% in compression. (Source: C.O. 238, Rule 3b)

(c) Alternate casing programs may be administratively approved by the Commission upon application and presentation of data which show the alternatives are appropriate, based upon accepted engineering principles.
(Source: C.O. 238, Rule 3c)

Rule 4 Blowout Prevention Equipment and Practice (ref. C.O. 145)

(a) The use of blowout prevention equipment shall be in accordance with good established practice and all equipment shall be in good operating condition at all times. All blowout prevention equipment shall be adequately protected to ensure reliable operation under the existing weather conditions. All blowout prevention equipment shall be checked for satisfactory operation during each trip.
(Source: C.O. 145, Rule 4a)

(b) Before drilling below the conductor string, each well shall have installed at least one remotely controlled annular type blowout preventer and flow diverter system. The annular preventer installed on the conductor casing shall be utilized to permit the diversion of hydrocarbons and other fluids. This low pressure, high capacity diverter system shall be installed to provide at least the equivalent of a 6-inch line with at least two lines venting in different directions to insure downwind diversion and shall be designed to avoid freeze-up. These lines shall be equipped with full-opening butterfly type valves or other valves approved by the Commission. A schematic diagram, list of equipment, and operational procedure for the diverter system shall be submitted with the application Permit to Drill or Deepen (Form 10-401) for approval. The above requirements may be waived for subsequent wells drilled from a multiple drill site. (Source: C.O. 145, Rule 4b)

(c) Before drilling below the surface casing all wells shall have three remotely controlled blowout preventers, including one equipped with pipe rams, one with blind rams and one annular type. The blowout preventers and associated equipment shall have 3000 psi working pressure and 6000 psi test pressure. (Source: C.O. 145, Rule 4c)

(d) Before drilling into the Prudhoe Oil Pool, the blowout preventers and associated equipment required in (c) above shall have 5000 psi working pressure rating and 10,000 psi test pressure rating. (Source: C.O. 145, Rule 4d)

(e) The associated equipment shall include a drilling spool with minimum three-inch side outlets (if not on the blowout preventer body), a minimum three-inch choke manifold, or equivalent, and a fill-up line. The drilling string will contain full-opening valves above and immediately below the kelly during all circulating operations with the kelly. Two emergency valves with rotary subs for all connections in use will be conveniently located on the drilling floor. One valve will be an inside blowout preventer of the spring-loaded type. The second valve will be of the manually-operated ball type, or any other type which will perform the same function. (Source: C.O. 145, Rule 4e)

(f) All ram-type blowout preventers, kelly valves, emergency valves and choke manifolds shall be tested to required working pressure when installed or changed and at least once each week thereafter. Annular preventers shall be tested to 50% recommended working pressure when installed and once each week thereafter. Test results shall be recorded on written daily records kept at the well. (Source: C.O. 145, Rule 4f)

Rule 5 Automatic Shut-in Equipment (ref. C.O. 145, 333, 363)

(a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead and shutting down any artificial lift system where an over pressure of equipment may occur.

(b) The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the well head and at the manifold building.

1. Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated.

2. A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for Commission inspection on request.

(c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS is in proper working condition.

(d) The SVSSafety valve systems must be maintained in working condition at all times unless the well is shut in and secured, or the well is being operated in conformance with other sections of this rule.

(e) Upon proper application or its own motion, the Commission may administratively waive or amend the requirements of this rule as long as the change does not promote waste, jeopardize correlative rights or compromise ultimate recovery, and is based on sound engineering principles.

(f) Nothing in this rule precludes the installation of a SSSV in wells designated by the operator. If a SSSV is installed, it must be maintained in working order and is subject to performance testing as part of the SVS.

Rule 6 Pressure Surveys (ref. C.O. 145, 165, 192, 208, 213, 220, AA 220.1, 341B)

(a) Prior to regular production, a static bottom hole or transient pressure survey shall be taken on at least one in three wells drilled from a common drilling site. (Source: C.O. 220, Rule 1, C.O. 341B)

(b) An annual pressure surveillance plan shall be submitted to the Commission in conjunction with the Annual Prudhoe Pool Reservoir Surveillance Report by April 1, each year. The plan will contain the number of pressure surveys anticipated for the next calendar year and be subject to approval by the Commission by May1. These surveys are needed to effectively monitor reservoir pressure in the Prudhoe Oil Pool. The surveys required in (a) of this rule may be used to fulfill the minimum requirements. (Source: C.O. 220, Rule 6, C.O. 341B)

(c) Data from the surveys required in (a) and (b) of this rule shall be filed with the Commission by the last day of the month following the month in which each survey is taken. Form 10-412, Reservoir Pressure Report, shall be used to report the data from these surveys. Data submitted shall include rate, pressure, time, depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall-off test, a multi-rate test or an interference test are acceptable. Other quantitative methods may be administratively approved by the Commission. (Source: C.O. 220, Rule 7)

(d) Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (c) of this rule.
(Source: C.O. 220, Rule 8)

(e) By administrative approval the Commission may grant time extensions and waive requirements of this rule, and by administrative order the Commission may require additional pressure surveys in (b) of this rule. (Source: C.O. 220, Rule 5)

Rule 7 Gas-Oil Contact Monitoring (ref. C.O. 145, 165, 192, 208, 213, AA 213.39)

(a) Prior to initial sustained production, a cased or open hole neutron log shall be run in each well. (Source: C.O. 165, Rule 9a) This requirement is waived for waterflood/EOR areas encompassed by the expanded Prudhoe Bay Miscible Gas Project outlined in C.O. 290, and for those areas not expected to have significant GOC movement or gas encroachment from the gravity drainage area defined by the Commission through Administrative Approval. (Source: AA 213.39, excerpts from paragraph 1)

(b) A minimum of 40 repeat cased hole neutron log surveys shall be run annually.
(Source: C.O. 208, Rule 4)

(c) The neutron logs run on any well and those required in (a) and (b) of this rule shall be filed with the Commission by the last day of the month following the month in which the logs were run. (Source: C.O. 165, Rule 9d)

(d) By administrative approval, the Commission may delay, modify or waive the logging requirements of this rule or may require additional wells to be logged.
(Source: C.O. 213, Rule 3)

Rule 8 Productivity Profiles (ref. C.O. 145, 165, 192, 208, 213, AA 213.40)

(a) A spinner flow meter or tracer survey shall be run in each well during the first six months the well is on production. (Source: C.O. 165, Rule 11a) This requirement is waived for wells completed with a single perforated interval, or with perforations in a single reservoir zone including highly deviated (greater than 65 degrees) and horizontal wells. (Source: AA 213.40 paragraph 3)

(b) Follow-up surveys shall be performed on a rotating basis so that a new production profile is obtained on each well periodically. Nonscheduled surveys shall be run in wells which experience an abrupt change in water cut, gas-oil ratio, or productivity.
(Source: C.O. 165, Rule 11b)

(c) The complete spinner flow meter or tracer data and results shall be recorded and filed with the Commission by the last day of the month following the month in which each survey is taken. (Source: C.O. 165, Rule 11c)

(d) The Commission may administratively approve alternate methods and time periods in the enforcement of this rule provided that the data obtained is appropriate for monitoring the Prudhoe Oil Pool or may waive the requirements of (a), (b) and (c). By administrative order the Commission may specify additional surveys other than the surveys submitted under (a), (b) and (c) of this rule. (Sources: C.O. 208, Rule 8 and C.O. 213, Rule 2)

Rule 9 Pool Off-Take Rates (ref. C.O. 145, 214)

The maximum annual average oil offtake rate is 1.5 million barrels per day plus condensate production. The maximum annual average gas offtake rate is 2.7 billion standard cubic feet per day, which contemplates an annual average gas pipeline delivery sales rate of 2.0 billion standard cubic feet per day of pipeline quality gas when treating and transportation facilities are available. Daily offtake rates in excess of these amounts are permitted only as required to sustain these annual average rates. The annual average offtake rates as specified shall not be exceeded without the prior written approval of the Commission.

Annual average offtake rates mean the daily average rate calculated by dividing the total volume produced in a calendar year by the number of days in the year. However, in the first calendar year that large gas offtake rates are initiated, following the completion of a large gas sales pipeline, the annual average offtake rate for gas shall be determined by dividing the total volume of gas produced in the calendar year by the number of days remaining in the year following initial delivery to the large gas sales pipeline.

Rule 10 Facility Gas Flaring (ref. C. O. 145, 145A, 197, 219)

(a) The venting or flaring of gas is prohibited except as may be authorized by the Commission in cases of emergency or operational necessity. However, upon application by the operators, the venting or flaring of gas may be authorized by the Commission to permit testing of wells in areas of the pool where access to pool gas gathering facilities is not prudent. (Source: C.O. 197)

(b) The flaring of gas is approved to maintain safety flares and to permit purging of the gas handling equipment at the rates specified for the following facilities. The daily average rate shall be calculated on a monthly basis.

Facility Approved Rate
Gathering Center No. 1 1,100 MCF/D
Gathering Center No. 2 1,100 MCF/D
Gathering Center No. 3 1,100 MCF/D
Flow Station No.1 1,000 MCF/D
Flow Station No.2 1,000 MCF/D
Flow Station No.3 1,000 MCF/D
Field Fuel Gas Unit & Central Compressor Plant 1,000 MCF/D
Central Gas Facility 3,000 MCF/D
(Source: C.O. 219, Rule 1)

(c) After the commencement of any flaring incident at any facility arising from an emergency or operational necessity, the Operator shall take the following action:

1. Initiate appropriate action and procedures so that flaring can be terminated as soon as reasonably possible and the flaring can be minimized during the flaring period.

2. Production shall be curtailed to minimize flaring as soon as reasonably possible. (Source: C.O. 145A, Rule 2)

(d) Flaring as a result of an emergency or operational necessity shall not be permitted longer than a total of twelve (12) hours after the commencement of each such incident without approval of the Commission or its designated representative.
(Source: C.O. 145A, Rule 3)

(e) Upon the request of the Operator to flare for more than a total of twelve (12) hours, a member of the Commission or its designated representative may verbally approve the request for a period not to exceed five (5) days beyond the twelve (12) hour period provided for in (d) above. The following information shall be given to the Commission or its designated representative upon request for such approval:
(Source: C.O. 145A, Rule 4)

1. The facility at which the flaring is occurring.

2. Description of the flaring incident and cause.

3. Time of commencement.

4. Estimated time of termination.

5. Volume of gas flared.

6. Estimate of gas volume to be flared.

7.Action being taken to minimize and eliminate flaring.

(f) A request in writing must be submitted by the Operator in order to obtain written administrative approval to flare beyond the period provided in (e) above.
(Source: C.O. 145A, Rule 5)

(g) On a monthly basis the Operator shall submit a written report to the Commission on all flaring incidents that result from an emergency or operational necessity. The report shall be due by the 20th day of the month following the reporting month. The report shall contain the following information for each flaring incident:

1. The facility at which the flaring occurred.

2. Time of commencement and termination of flaring.

3. Description of the flaring incident and cause.

4. Volume of gas flared.

5. Action taken to eliminate the cause for the flaring incident.
(Source: C.O. 145A, Rule 6)

(h) Following a ten (10) day notice to the operator of any production facility the Commission may change the volumes of gas allowed to be flared for safety.
(Source: C.O. 145A, Rule 7)

Rule 11 Annual Surveillance Reporting (ref. C.O. 165, 186, 195, 208, 223, 224, 279, AA 279.1)

(a) An annual Prudhoe Oil Pool surveillance report will be required by April 1 of each year. The report shall include but is not limited to the following:

1. Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters.

2. Voidage balance by month of produced fluids, oil, water and gas, and injected fluids, gas, water, low molecular weight hydrocarbons, and any other injected substances (which can be filed in lieu of monthly Forms 10-413 for each EOR project). (Source C.O. 279, Rule 7 and AA 279.1 excerpt from paragraph 3)

3. Analysis of reservoir pressure surveys within the field.

4. Results and where appropriate, analysis of production logging surveys, tracer surveys and observation well surveys.

5. Results of gas movement and gas-oil contact surveillance efforts including a summary of wells surveyed and analysis of gas movement within the reservoir. The analysis shall include map(s) and/or tables showing the locations of various documented gas movement mechanisms as appropriate.
(Source: C.O. 279, Rule 7)

(b) Upon its own motion or upon written request, the Commission may administratively amend this rule so long as the change does not promote waste nor jeopardize correlative rights and is based on sound engineering principles.
(Source: C.O. 279, Rule 8)

Rule 12 Prudhoe Bay Miscible Gas Project (PBMGP) (ref. C.O. 195, 290)

(a) Expansion of the PBMGP and infill expansion of miscible gas injection in the NWFB is approved for the 59,740 acre portion of the Prudhoe Oil Pool defined in the record. (Source: C.O. 290, Rule 1, AA 290.1)

(b) An annual report must be submitted to the Commission detailing performance of the PBMGP and outlining compositional information for the current miscible injectant (MI) necessary to maintain miscibility under anticipated reservoir conditions. (Source: C.O. 290, Rule 2)

(c) The operator will maintain a pressure differential of at least 250 psi between the minimum miscibility pressure (MMP) of the MI and the prevailing reservoir pressure at the time of injection. This differential is based on a projected prevailing reservoir pressure decline of no more than 30 psi/year over the life of the project. (Source: C.O. 290, Rule 4)

(d) The operators are directed to continue investigating options to mitigate pressure decline and to provide an annual progress report to the Commission.
(Source: C.O. 290, Rule 5)

(e) Upon its own motion or upon written request, the Commission may amend this rule by administrative action if the change does not promote waste, violate correlative rights, nor jeopardize ultimate recovery, and is based on sound engineering principles. (Source: C.O. 290, Rule 6)

Rule 13 Waiver of GOR Limitation (ref. 8/22/86 letter)

The Commission waives the requirements of 20 AAC 25.240(b) for all oil wells in the Prudhoe Oil Pool of the Prudhoe Bay Field so long as the gas from the wells is being returned to the pool, or so long as the additional recovery project is in operation.
(Source: Letter 8/22/86, L. Smith to Heinze/Nelson, paragraph 3)

Rule 14 Waiver of "Application for Sundry Approval" Requirement for Workover Operations (ref. C.O. 258)

The requirements of 20 AAC 25.280(a) are waived for development wells in the Prudhoe Oil Pool of the Prudhoe Bay Field. (Source: C.O. 258)

Rule 15 Waterflooding (ref. 3/20/81 letter Hamilton to Nelson/Norgaard)

The commission approves the December, 1980 additional recovery application for water-flooding in the Prudhoe Oil Pool subject to the requirements listed in Rule 11 above.

Any proposed changes must be submitted to the Commission for approval.
(Source: Letter 3/20/81, Hamilton to Nelson/Norgaard)

Rule 16 Orders Revoked

The following Conservation Orders and associated Administrative Approvals and letter approvals are hereby revoked. Conservation orders 78, 83B, 85, 87, 88, 96, 97, 98B, 117, 117A, 118, 130, 137, 138, 139, 140, 141, 143, 145, 145A, 148, 155, 160, 164, 165, 166, 167, 169, 174, 178, 180, 181, 183, 184, 185, 186, 188, 189, 192, 194, 195, 195.1, 195.2, 195.4, 197, 199, 200, 204, 208, 213, 214, 219, 220, 223, 224, 238, 258, 259, 279, 290 and 333, 341, 341A and March 20, 1981 and August 22, 1986 letter approvals.The hearing records of these orders are made part of the record for this order.

DONE at Anchorage, Alaska and dated November 17, 1995.

David W. Johnston, Chairman

Russell A. Douglass, Commissioner

Tuckerman Babcock, Commissioner

Conservation Order Index