STATE OF ALASKA

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

Re:The Application of BP Exploration (Alaska) Inc.        ) Conservation Order No. 329A
   requesting a change to Rule 10, Conservation Order     ) Prudhoe Bay Field
   329 governing maximum production rate.                 ) Niakuk Oil Pool

                                                            June 4, 1996

IT APPEARING THAT:

  1. By letter received January 23, 1996, BP Exploration (Alaska) Inc. (BPXA) requested a change to Rule 10, Conservation Order 329.

  2. Notice of opportunity for public hearing to be held February 26, 1996, was published in the Anchorage Daily News on January 27, 1996.

  3. Comments on the application were received from ARCO Alaska, Inc., Exxon Company, USA and Department of Natural Resources, Division of Oil and Gas.

  4. There were no protests or requests for public hearing.

  5. The Commission issued Administrative Approval No. 329.04 on February 22, 1996, which allowed temporary waiver of Rule 10 for 120 days or until Rule 10 is changed, to allow BPXA time to prepare data and evaluate studies supporting their request to change the production limit.

  6. On April 26, 1996 BPXA submitted additional data and information supporting its application.

Findings:

  1. BPXA anticipated that facility constraints, gas-oil ratio (GOR) and other performance measures would limit pool production rates to no more than 23,000 BPD when it submitted its original development plans for the Niakuk Pool.

  2. Since the Niakuk Pool rules were adopted, the Lisburne Production Center facility capacity has increased from 135,000 BPD to over 210,000 BPD on peak production days.

  3. Reservoir performance has been better than originally anticipated and the pool is larger than anticipated at the time pool rules were adopted.

  4. Waterflood operations started in April 1995 with reservoir response evident in oil rate increase, water production increase and GOR decrease.

  5. Pressure measurements show reservoir pressure above bubble point and generally trending upward since waterflood started.

  6. Results of operator model studies in the various reservoir segments indicate that ultimate recovery will not be diminished by increasing offtake rate beyond 23,000 BDP for the pool.

  7. The operator expects to drill additional infill wells to capture reserves more efficiently.

Conclusions

  1. Results of model studies indicate ultimate recovery will not be diminished by increasing pool offtake rate.

  2. Pressure and GOR trends indicate that pool response to waterflood is beneficial.

  3. There are no technical reasons for restricting offtake rate from the pool.

  4. The owners and operators of pools producing to the Lisburne Production Center have agreed to use well performance characteristics such as GOR and water production to maximize oil production rate while managing facility gas and water handling constraints.

  5. Eliminating the rate restriction in Rule 10 will not cause waste, jeopardize correlative rights and will not compromise maximum recovery.

NOW, THEREFORE, IT IS ORDERED THAT the plan of development submitted by BP Exploration (Alaska) Inc. is approved, subject to rules hereinafter set forth and state-wide requirements under 20 AAC 25, for the following affected area.

Umiat Meridian

T12N R15E Section 23 S/2

Section 24 SW/4

Section 25 All

Section 26 All

Section 36 NE/4

T12N R16E Section 28 All

Section 29 All

Section 30 All

Section 31 N/2

Section 32 N/2

Rule 1 Field and Pool Name

The field is the Prudhoe Bay Field. Hydrocarbons underlying the affected area and contained within the Kuparuk River Formation constitute a single associated gas and oil reservoir called the Niakuk oil pool.

Rule 2 Pool Definition

The Niakuk oil pool is defined as the accumulation of oil and gas that correlates with the interval between 12,318 feet and 12,942 feet measured depth in the Niakuk 6 well.

Rule 3 Well Spacing

Upon application of the operator, the Commission may administratively approve the drilling of any well to a bottom hole location greater than 500 lineal feet from the external boundary of the affected area. No well bore may be open to the Niakuk oil pool within 500 feet of the external boundary of the affected area nor within 1000 feet of another well capable of producing from the same pool.

Rule 4 Casing and Cementing

a. A conductor casing shall be set at least 75 feet below the surface. If cemented, cement to surface shall be verified by visual inspection.

b. Surface casing shall be set at least 500 feet MD below the base of the permafrost but not below 5000 feet TVD subsea.

c. Surface casing must have minimum axial strain properties of .5% in tension and .7% in compression to withstand forces generated by thaw subsidence and freeze back in permafrost.

Rule 5 Automatic Shut In Equipment

a. Upon completion, each well shall be equipped with:

i. a fail-safe automatic surface safety valve (SSV) capable of preventing uncontrolled flow.

ii. a fail-safe automatic subsurface safety valve (SSSV), unless other types of subsurface valve are approved by the Commission, shall be installed in the tubing string below the base of the permafrost and be capable of preventing uncontrolled flow.

b. A well that is not capable of unassisted flow of hydrocarbons, as determined by a "no flow" performance test witnessed by a Commission representative, is not required to have fail-safe automatic SSSV's.

c. Safety valves may be temporarily removed for not more than 15 days as part of routine well operations or repair without specific notice to, or authorization by the Commission. The SSV and SSSV may not be simultaneously out of service without specific authorization from the Commission.

i. Wells with SSV's or SSSV's removed shall be identified by a sign on the wellhead stating that the valve has been removed and the date of removal.

ii. A list of wells with SSV's or SSSVs removed, removal dates, reasons for removal, and estimated re-installation dates must be maintained current and available for Commission inspection on request.

d. The Low Pressure Sensor (LPS) systems shall not be deactivated except during repairs to the LPS, while engaged in active well work or if the pad is manned. If the LPS cannot be returned to service within 24 hours, the well must be shut-in at the well head and at the manifold building.

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

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

Rule 6 Surface Commingling and Common Facilities

a. Production from the Niakuk oil pool may be commingled on the surface with production from other pools for processing at the LPC prior to custody transfer.

b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the Commission monthly in both computer file and report formats.

i. Conduct well tests to determine production rates for each well.

ii. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production.

iii.Sum the TMP volume for all wells in all pools.

iv. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e., metered/TMP)

v. Calculate each well's actual monthly production (AMP) volume as:

AMP = TMP x Allocation Factor

c. NGL's will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the Commission.

d. Each producing well will be tested at least twice each month. Wells that have been shut in and cannot meet the twice monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing.

e. Optimum test duration and stabilization time will be determined on a well by well basis by the operator.

f. Water volumes will be determined by API/MPMS approved methods, or the use of industry proven, on-line water cut measurement devices approved by the Commission.

g. API gravity will be determined for each producing well annually by an API/MPMS approved method.

h. Gas samples will be taken and analyzed for composition from each non gas lifted producing well yearly.

i. Quarterly allocation process reviews will be held with the Commission.

j. This rule may be revised or rewritten after an evaluation period of at least one year.

Rule 7 Production Anomalies

In the event of oil production capacity proration at or from the LPC, all commingled pools produced at the LPC will be prorated by an equivalent percentage of oil production recognizing mechanical limitations and operational constraints.

Rule 8 Reservoir Pressure Monitoring

a. Prior to regular production, a pressure survey shall be taken on each well to determine the reservoir pressure.

b. A minimum of one bottom hole pressure survey per producing governmental section shall be obtained annually. The surveys in part 'a' of this rule may be used to fulfill the minimum requirements.

c. The datum for all surveys is 9200' TVDss.

d. Pressure surveys will be either a pressure buildup, pressure falloff, RFT, or static bottom hole pressure after the well has been shut in for an extended period.

e. The pressure surveys will be reported to the Commission quarterly on form 10-412, Reservoir Pressure Report. All data necessary for complete analysis of each survey need not be submitted with the form 10-412 but must be submitted upon request.

f.Results and data from any additional reservoir pressure tests, surveys or special monitoring techniques shall be submitted in accordance with part 'e' of this rule.

Rule 9 Niakuk Oil Pool Annual Reservoir Report.

A surveillance report will be required within one year of regular production and annually thereafter. The report shall include but is not limited to the following:

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

b. Voidage balance by month of produced fluids and injected fluids.

c. Analysis of reservoir pressure surveys within the pool.

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

e. Results of any special monitoring.

f. Future development plans.

Rule 10 Offtake rate. Repealed June 4, 1996.

Rule 11 Additional Recovery Project

Within one year of regular production, a waterflood or other Commission approved secondary recovery project must commence.

Rule 12 Administrative Action

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

DONE at Anchorage, Alaska and dated June 4, 1996.

David W. Johnston, Chairman

Tuckerman Babcock, Commissioner

Conservation Order Index