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Home My WebLink About1998 Tarn Oil PoolARCO Alaska, Inc.' ` Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 " Steven V. Bross Supervisor Greater Kuparuk Area Satellite Development ATO 1148 l� Phone 265-6083 �1 Fax 265-6133 April 1, 1999 Mr. Robert Christenson, Commissioner Alaska Oil and Gas Conservation Commission �� D 3001 Porcupine Drive t� Anchorage, Alaska 99501 Re: 1998 Tarn O' Pool Annual Reservoir Surveillance Report Dear Mr. Christenson: In compliance with Rule 11, Conservation Order No. 430 and Rule 9, Area Injection Order No. 16, ARCO Alaska, operator of the Kuparuk River Field, is hereby submitting the annual report on the Tarn Oil Pool. This report documents the required information pertinent to the field development and enhanced recovery operations from January through December 1998. The following is an outline of the information provided: a. A summary of the enhanced recovery project (Attachment 1). b. Voidage balance, by month, of produced and injected fluids (Attachment 2, Attachment 3). c. Analysis of reservoir pressure surveys taken in 1998 (Attachment 4). d. Results of production surveys, and any special surveys, taken on the Tarn Oil Pool in 1998 (Attachment 5). e. Results of any special monitoring (Attachment 6) f. Evaluation of well testing and allocation (Attachment 7). g. Future development plans (including a review of the annual plan of operations and development, item "h" in the rules) (Attachment 8). If you have any questions concerning this data, please contact Mike Beck at (907) 276-1215 x7285. Sincer , Steve Bross GKA Satellite Development Supervisor ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany Attachment 1 Tarn Oil Pool 1998 Annual Reservoir Surveillance Report Summary of the Enhanced Recovery Project Background In 1998 AAI requested and received approval for formation of the Tarn Oil Pool in the Kuparuk River Unit, approval of an Area Injection Order for Tarn, expansion of the Kuparuk River Unit and formation of the Tarn Participating Area. The Tarn Pool Rules and Area Injection Order were approved on July 20th and July 28th, respectively. The Unit Expansion and Participating area were approved effective July 1, 1998. Progress of FOR Project Development and exploration activities in 1998 followed the plans described in the Pool Rules, Area Injection Order, Unit Expansion, and Participating Area (PA) applications. Below is listing of key accomplishments related to the Tarn Pool and PA in 1998. 1. Initiated and completed installation of roads, pads, pipelines and powerlines associated with the two drill site (DS) development as described in the 1998 Plan of Development. 2. Initiated drilling on DS 2N in April 1998. By year-end 1998, twenty-two wells had been drilled (fifteen on DS 2N and seven on DS 2L). 3. Initiated production from DS 2N in July 1998. 4. Initiated injection of MI (Miscible Injectant) at DS 2N in November 1998. 5. Initiated production from DS 2L in December 1998. 6. Wells were drilled from DS 2L that penetrated the prospective Arete and Iceberg plays described in the 1998 plans. 7. Shot additional 3-D seismic in the southern portion of the Tarn Unit Expansion Area. Below is a listing of the most important new findings derived from the 1998 Tarn development efforts: 1. Early drilling and production information demonstrated the presence of an area of thick, high quality reservoir pay in the western portion of the 2N development lobe. Pay thicknesses in these wells (2N-329, 2N-313, 2N-341, 2N-323) were on the order of 130'-1 50'with estimated average permeabilities of 30-50 and as compared to the pre -drill estimate of about 10 and average permeability. The productivity of these wells proved to be quite high with initial production rates on the order of 6000 BOPD each and sustained production rates of 3000-4000 BOPD each. 2. The well logs, production performance and pressure data associated with wells 2N-319, 2N-345, 2N-339, 2N-337A and 2N-335 suggest that these wells are not well connected to the high rate area of the lobe described above. These wells have lower quality pay and seem to be more compartmentalized than other DS 2N wells. While the initial rates on some of these wells were as high as 2000 BOPD, they all declined very quickly to less than 1000 BOPD and have been difficult to keep on line without artificial lift capabilities. 3. The penetrations into the Arete and Iceberg features were unsuccessful in finding commercial hydrocarbons. Both wells were ultimately completed in the Bermuda interval. 4. The sidetrack of the Arete well (2L-329A) was completed in the updip area of the 2L Bermuda development lobe. On test, 2L-329A produced only gas pointing to the existence of a small gas cap in the DS 2L Bermuda lobe. The location of the gas -oil contact is estimated to be at 5141' ss. 5. The Accuflow test equipment as initially installed proved to be undersized for the well rates encountered at DS 2N. Well testing was accomplished through use rental test equipment until December when a new Accuflow skid was installed. The DS 2L Accuflow has also been modified to ensure its capability to effectively test the DS 2L wells. 6. Paraffin deposition in wellbores, surface lines and facilities has proved to be an operational challenge. The low rate wells are particularly susceptible to paraffin buildup in their wellbores. The main techniques employed to combat this problem are (wellbore and surface line) hot oil treatments and (wellbore) wireline paraffin cutting. Reservoir Management Summary Tarn came on-line in July of 1998 and produced 3.5 million barrels of oil and 4.5 billion cubic feet of gas by year-end 1998. Injection of MI did not begin until November, and consequently only 1.2 BCF of MI was injected in 1998. In February 1999, reservoir injection was at 132% of reservoir withdrawals on DS 2N where most of the 1998 voidage occurred. Early performance from wells in the high quality "channel" area of DS 2N typically showed a rather steep oil decline rate with and increasing GORs. However, in the first quarter of 1999, these wells' rates have stabilized or shown small increases and GORs have shown marked decreases indicating that MI injection is re -pressuring the reservoir. The lower rate "compartmentalized" wells on DS 2N have not yet exhibited a discernible response to offset injection. These wells are either geologically disconnected from the better quality pay in the "channel" area, or connected via a tortuous flow path. This is confirmed by static pressure measurements that show that the reservoir pressure declines rapidly during production periods and slowly re -pressures during extended shut-in periods. (Decreases of 400-900 psi were observed in wells in this area over a period of just four months.) Wells in this area are currently only periodically produced. Plans are to convert one or more of the producers in this area to injection in 1999. There is insufficient data to draw conclusions at this time regarding well performance and/or flood performance on IDS 2L. Q cz 0) 0 Attachment 2 Tarn Oil Pool 1998 Annual Reservoir Surveillance Report Produced Fluid Volumes OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR STB MSCF BBL STB MSCF BBL 1 1998 0 0 0 0 0 0 2 1998 0 0 0 0 0 0 3 1998 0 0 0 0 0 0 4 1998 0 0 0 0 0 0 5 1998 0 0 0 0 0 0 6 1998 0 0 0 0 0 0 7 1998 267127 229522 1319 267127 229522 1319 8 1998 477544 520071 1575 744671 749593 2894 9 1998 638274 683070 856 1382945 1432663 3750 10 1998 736382 930683 34 2119327 2363346 3784 11 1998 724613 1030516 1835 2843940 3393862 5619 12 1998 690507 1082565 940 3534447 4476427 6559 1998 TOTAL 3534447 4476427 6559 Attachment 3 Tarn Oil Pool 1998 Annual Reservoir Surveillance Report Injected Fluid Volumes WATER GAS NGLS CUM WATER CUM GAS CUM NGLS MO YR STB MSCF MSCF STB MSCF MSCF 1 1998 0 0 0 0 0 0 2 1998 0 0 0 0 0 0 3 1998 0 0 0 0 0 0 4 1998 0 0 0 0 0 0 5 1998 0 0 0 0 0 0 6 1998 0 0 0 0 0 0 7 1998 0 0 0 0 0 0 8 1998 0 0 0 0 0 0 9 1998 0 0 0 0 0 0 10 1998 0 0 0 0 0 0 11 1998 0 0 78408 0 0 78408 12 1998 0 0 1116496 0 0 1194904 1998 TOTAL 0 0 1194904 Attachment 4 Tarn Oil Pool 1998 Annual Reservoir Surveillance Report Reservoir Pressure Surveys Tarn reservoir pressure is referenced to a depth of 5200' ss. Production commenced at 2N pad in July of 1998. Initial reservoir pressure measurements ranged from 2300-2350 psi . Well 2N-331, perforated in November, had the lowest initial pressure of 2230 psi. Production commenced at 2L pad in December of 1998. Consistent with 2N pad, the range on initial reservoir pressure measurements was 2330-2385 psi. A pressure survey obtained in production well 2N-345 after a 5 day shut-in indicated a pressure of -1335 psi after approximately 4 months of production. A subsequent survey after the well had been shut-in for -30 and 60 days indicated a static pressure of -1720 and 1990 psi, respectively. A 21 day pressure build up test on Well 2N-337A showed a final pressure of -1960 psi. Also attached is a listing of all 1998 data. ^0^ C 0 Acc !W V cu L cn L •`O m cc co a a) a) r C L N C O m N O U rn c m E - ro a t rn N N E m 9 m E E r m V C C m � V � @ m J N C L C L lU0 m _� ❑ � 3 a m a o m U m U m CO Y U C o v E c m m = m = m m m E m o 3 c m m m a m a x m t m m N j m m m m m N N m y m din Z NO m fn N m m m n a a a n n n n o. n o. C C m m C C C c C c A CO T E O C c m n C n C N N m R Y m Y y6 Y N Y Ytl Y m cY D 0 m m N m D "' m m fM1 m N c0 �y 0 C N j m m `p a a a a a a a a E a m E ELL a d a L„a m m m m m m m m m p m m J (n r = m m m m Y J m = LL m m = � m 9 A tn O � O M M M L � 0. Qo 0. a+ a � n O W W N W W N W O OI N N M W O N O r r m V W N cnM (d m N O N N N M N M M N O M N W N N m N N N N N R N N m m I N N N N N N N W V m N N N N N N O N N � N N N N N N N y Y a O q W n OI M N m O v o tD M m W Ol rn N R R V W M v o a m W W rn W rn rn V K m m m m W W m W N t0 rn r W W W m N N N N v N N N N O O M M M M 9 a m Q C� C O W W V M m m to r N N N n W N W m 0 M M V W O N F m N N M N N M M O N O N I� O) N N m m m N M V N W V I� V' M W v W O V m W V M n M h V O w W N N N 1� M aN V Y N N N N N N N N N N u E Q� N t� I� m m O O M O V M O O V V V N V a a W m W O O O N N 8 F W � m m m � n m rn m rn rn n m rn rn � rn rn n n a n n m W 0 cn l6 N N 7@ N N ttl N t6 N N N t0 N ttl N t6 ttl ltl N N N N y N C C C '_ '_ '_ '_ .0 C C .0 C O) C a C m C ^ W N C v - - _ = S _ _ U U U N m U N U N U N N U Y m N U m Y U ❑ U ❑ U U y LL LL LL m LL LL LL lL m 'O J� LLp m m 'O m LL m m 'O J@ p LL m LL LL m m Z m LL LL. m D m Y V m LL a 3 3 3 3 3� 3 A m ��v m m E m m �ma m m E m m �1 m m 3� m m m m �� m m m m mt� m m m ttJ E tEJ E tt tt EE tt E =Ent Q n a Q a n n n Q Q a n G ¢ n N to m N m m N m m m m co m CO W m In m m m u m m rn rn m W rn m W rn m rn W rn rn m rn rn rn rn W rn W m rn rn m W m rn rn rn W rn --.W rn rn WW r�r _ O M N Q W M to 1� W Q M M M N O) Ol Ot N N Q Q W W 0 0 M W W W N 1 M M M M M M M N N N M M M N M N N N M M M M M M M M M M M M M M M V M K a M M 3 N N N M N N N N N N N N N N N N N N N N N N N N N N N N N N N Attachment 5 Tarn Oil Pool 1998 Annual Reservoir Surveillance Report Production/Special Surveys The only surveillance activity of this type in 1998 was an injection spinner log taken on 2N-325 on December 5, 1998. Analysis of this log showed fairly uniform injection across the Bermuda interval with approximately 25% of the perforated interval not taking injection. Attachment 6 Tarn Oil Pool 1998 Annual Reservoir Surveillance Report Results of Special Monitoring Below is a table showing information related to a radioactive tracer analysis of the well fracturing treatment for well 2N-345. The testing was done to confirm the fracture height and to get a qualitative estimate of proppant flowback over time. Well Date Type Comments 2N- 7/23/98 Frac RA tracer added to initial fracture treatment 345 2N- 8/8/98 Log Tracer analysis log showed 148' TVD fracture height growth above 345 Bermuda interval. 2N- 9/9/98 Log Tracer analysis log showed proppant pack integrity had remained 345 stable following production from the well. Attachment 7 Tarn Oil Pool 1998 Annual Reservoir Surveillance Report Well Allocation and Test Evaluation Summary Tarn DS 2N and 2L facilities were initially fabricated with an Accuflow metering system having a design capacity of 4000 BFPD. After initial production at DS 2N it became apparent that the Accuflow was undersized. A portable test separator system provided by Halliburton Energy Services was installed at DS 2N within one week of initial start-up production from well 2N-323. Additional production was deferred until the metering system was in place. Halliburton Energy Services provided well testing services at DS 2N through the remainder of 1998. A redesigned Accuflow at DS 2N was commissioned in late December and was under going functional check-out testing through the first of the year. The Accuflow at DS 2L was also redesigned to ensure adequate testing capacity and had not been commissioned by the end of 1998. Portable test separators provided by Halliburton Energy Services and Trico Industries provided well testing services at DS 2L for 1998. A minimum of two well tests per month were taken on production wells. Test separator backpressure corrections were applied to wells flowing above 2000 BLPD. Nodal hydraulics modeling for each well test was used to correct flow rates to reflect typical flowing conditions. Flow rates for the well test period were not corrected for backpressure. Correction to stock tank barrel conditions were made by applying Tarn specific pressure corrections (derived from the PVT analysis of Tarn #2 crude oil samples) and API temperature corrections. Production volumes were tracked through the KDGS and Setcim production monitoring systems. Tarn production was applied an allocation factor of 1.0 for 1998. Attachment 8 Tarn Oil Pool 1998 Annual Reservoir Surveillance Report Tarn Development Plan and Operational Review Following are summaries of key activities that have either already occurred in the first quarter of 1999, or are planned at this time. Development Drilling - From January 1, 1999 through March 31, 1999, five additional Tarn development wells have been drilled (four on DS 2N and one on DS 2L) bringing the total development well count for Tarn to twenty-seven. Plans are to take a break from Tarn drilling after the fifth well to allow time to assess the performance of the wells currently in place at both DS 2L and 2N. Additional development drilling at Tarn may resume in the fourth quarter of 1999, or be delayed until 2000 depending upon the economic climate and the performance of the existing wells. It is still estimated that a total of thirty-five to forty wells will ultimately be drilled before the development is complete. MI/Water Injection -Gas injection was initiated at DS 2L in early March 1998 into two wells. The remaining injection wells on both DS 2L and 2N will be put on injection before mid -year 1999. The possible use a WAG (Water Alternating Gas) process for the area of higher quality pay on DS 2N is being evaluated. As noted in the Pool Rules testimony, lab tests show that the Tarn reservoir rock is susceptible to damage from water injection. The level and consequences of the damage may be less in the more highly permeable areas of the reservoir, however. An initial small-scale water injection test in which water will be trucked to Tarn for injection into a single zone of one injection well on DS 2N will begin in late March or early April. If the trucked water test shows no sign of significant damage, a larger scale test may be undertaken. In this test, the existing Tarn MI line would be converted to water injection service for a few months in the summer of 1999. Injection of water could then take place in several injection wells in the high quality area of DS 2N. If this proves successful, steps will likely be taken to facilitate an ongoing "WAG" operation at Tarn. Augmenting the existing MI flood in the high quality areas of the reservoir with periodic water cycles could have two benefits. First, the water would be expected to slow the breakthrough of subsequently injected gas into the producers; and second, the sweep performance of the flood should improve. One or more well conversions from producers to injectors in the compartmentalized area of DS 2N will take place in 1999 to add injection into this area. Artificial Lift - The use of gas cap gas from 2L-329A and MI for short-term gas lift has been tested at Tarn in early 1999. Both sources have proved successful in certain applications; however, neither source seems to be effective in unloading newly fractured wells with high water cuts. Use of either source of gas has lead to hydrate formation and/or freezing in the wellbores of wells producing at high watercuts. Work is underway to provide letdown stations or MI to be used for lift at wells that need periodic lift for well kickoff. This is not seen as a viable means for continuous lift of wells due to high economic value of the MI. The lower rate wells on both DS 2L and 2N are being evaluated for installations of coil tubing velocity strings to better match tubing size to productivity. The first two installations are expected to be in place by mid-1999 with others to follow if warranted. Other artificial lift options still under consideration are use of hydraulic jet pumps or use of a "booster station" (gas/liquid separation with gas compression and liquid pumping). Well Testing -The DS 2L Accuflow is expected to be commissioned in April 1999. Work is continuing to reconcile the well test measurements made with the rental test equipment on DS 2N and the 2N Accuflow results. There is some evidence that the Accuflow rates may be 5%-10% less than the rental equipment measured rates. This may be related to the foaming tendency of the Tarn crude. Exploration/Delineation - Two targets for additional exploration/delineation remain in the expanded Unit area. The first is the Cairn interval near DS 2N. This interval can be reached from the 2N gravel pad. The economics of a well to this area, given the tight nature of the Tarn 4 core and the likely gas/oil contact, are still being evaluated. No firm time has been set to drill a well to further evaluate Cairn near DS 2N. The second exploration target is the Cairn trend and/or other reservoir targets further to the south, near the southern limit of the expanded Kuparuk River Unit. The approved Unit expansion included a leasehold stipulation that by October 1, 2000, there must either be a well drilled into one of the six southern leases, or an approved AFC to do so during the 2000/2001 winter drilling season. Otherwise, all six leases will contract out of the Unit. The Tarn Owners still intend to fulfill these commitments. Tarn Kickoff to Tank Issues Kickoff Necessary Due to a Variety of Factors • Declining reservoir pressure (Injection recently initiated) 2N-337 -444 psi 8/2/98 2286 psi 12/3/98 1842 psi 2N-339 -578 psi 8/17/98 2330 psi 10/22/98 1752 psi 2N-345 -976 psi 7/22/98 2302 psi 11/27/98 1326 psi • Increasing backpressure with increased oil and gas production +I'DV (�S 3d� -Production header pressure has increased 110 psi since start-up • Unfavorable tubing hydraulics can lead to liquid fallback • Paraffin buildup leads to reduced ID and increased friction Productivity Identification • FFP vs header pressure trending • Well testing Kickoff Procedure • Open well to tank until flow is established then return well to process facilities • Usually of short duration Additional Advantages • Hot fluid flush can remove paraffin deposition Disadvantages • Safety -high activity level • Environmental concerns • Fluid disposal • Manpower Continuous Lift Gas is Not the "Cure All" • 2N-337 temporary lift had numerous periods of lift gas cycling • Lift gas is unfavorable for paraffin build-up do to cooling effects C C d N cc C) a) M CM Z N adOa Jo JOw wnO 0 0 0 0 0 O Ln O Ln O co N N r r • O 0 Lf ) 0 I Y m Q • a a a_p : Q� E c Q� 4�/ T. 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