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Home My WebLink About2000 Tarn Oil Pool0""Ps PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Stephen V. Bross Supervisor Greater Kuparuk Area Satellite Development ATO - 1126 Phone 265-6083 Fax 265-6133 March 29, 2001 Ms. Julie Heusser, Commissioner Alaska Oil and Gas Conservation Commission 333 West 71h Ave. Suite #100 Anchorage, Alaska 99501-3539 Re: 2000 Tarn Oil Pool Annual Reservoir Surveillance Report Dear Ms. Heusser: In compliance with Rule 11, Conservation Order No. 435, Phillips 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 2000. The following is an outline of the information provided: a. A summary of the enhanced recovery project (Attachment 1). b. Voidage balance, by month, for produced and injected fluids (Attachment 2, Attachment 3). c. Analysis of reservoir pressure surveys taken in 2000 (Attachment 4). d. Results of production surveys, and any special surveys, taken on the Tarn Oil Pool in 2000 (Attachment 5). e. Results of well allocation and test evaluation for Rule 7, and any other special monitoring (Attachment 6). f. Development Plan and Operation Review (Attachment 7). If you have any questions concerning this data, please contact Bob Christensen at (907) 659-7535 or Jeff Spencer at (907) 265-6813. Sincerely Steve Bross GKA Satellite Development Supervisor RECEIVED MAR 3 0 2001 Alaska Oil & Gas Cons. Commission Anchorage bcc: Central Files ATO - 320 Jeff Spencer ATO - 1144 Ron Marquez NSK - 69 Christensen NSK - 69 Attachment 1 Kuparuk River Unit Tarn Oil Pool 2000 Annual Reservoir Surveillance Report Summary of the Enhanced Recovery Project Background In 1998 AAI received approvals for formation of the Tarn Oil Pool in the Kuparuk River Unit, 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 20`h and July 281h' respectively. The Unit Expansion and Participating area were approved effective July 1, 1998. Construction of the Tarn road, pads, powerlines and pipelines took place in the 1998/1999 winter construction season. Tarn development drilling commenced in April of 1998. Tarn production began on July 8, 1998. Injection of miscible injectant (MI) began in November 1998. By year-end 1999, twenty-seven Tarn development wells had been drilled. Progress of FOR Project New development activity in 2000 consisted of drilling ten additional development wells, bringing the total number of Tarn wells to thirty-seven. Continuous MI injection continued as the primary enhanced recovery technique in 2000, however a second field-test of water injection took place in the summer of 2000. The primary goal of this test was to further evaluate the feasibility of implementing an MWAG FOR process across the entire field. Listed below are the key findings from the 2000 Water Injection Tests at Tarn. 1. Once again, injection of water at pressures below reservoir parting pressure does not appear economically feasible. Water injection rates at pressures below parting pressure are too low to match voidage. 2. Operating at injection pressures above reservoir parting pressure allows water injection rates that come close to matching voidage. Note: It is expected that sufficient water injection capacity to match voidage will be available by yearend 2001 as a result of additional development drilling and several producer -to -injector conversions planned for this year. 3. No signs of decreasing injectivity were observed during the summer water injection cycle, and injection rates remained high when the wells were returned to MI injection service. 4. The 2L water injection again confirmed the viability of injecting water in the 2L lobe and hence MWAG operations are also planned for this pad. Reservoir Management Summary Tarn began production in July of 1998 and produced 13.1 million barrels of oil and 17.9 billion cubic feet of gas by year-end 1999. Injection of MI began in November 1998 with 17.4 BCF of MI injected through 1999. In 2000, Tarn produced 8.8 MMBO and 17.8 BCF of gas. The injection totals for 2000 were 16.6 BCF of MI and 1.4 MMBW. The cumulative yearend I/W ratio for DS 2N is estimated at 0.75, while the estimated cumulative I/W for DS 2L is 1.41. The monthly average I/W ratios for DS 2N and 2L in December 2000 were 1.44 and 1.10 respectively. Because the cumulative I/W is less than 1.0 in the 2N area, some pressure depletion has occurred and an ongoing effort to increase reservoir pressure in the 2N area was initiated in October 2000. Re -pressurization is currently being accomplished through a strategic combination of increased injection and reduced withdrawals in order to maintain I/W ratios greater than 1.0. Once a cumulative I/W of 1.0 is reached in the 2N area, plans are to maintain reservoir pressure by more closely balancing monthly injection and production rates. The MI/water (MWAG) injection process at Tarn is projected to stabilize oil production rates and GOR's from the producing wells. Additional development drilling and several producer -to -injector conversions are also expected to take place this year. All the efforts outlined above are intended to improve FOR sweep efficiencies and increase ultimate recovery from the field. Paraffin deposition in the producing wellbores, surface drill site facilities, and cross-country production pipeline continues to have an impact on production operations at Tarn. Mechanical scraping and hot oil treatments are used to keep the downhole tubulars clear. Hot oil treatments are also used to flush the on -pad surface facilities. Paraffin buildup in the cross-country pipeline is being monitored with periodic radiographic inspection. A growing number of Tarn wells require artificial lift to produce continuously against the pipeline back -pressure. MI or gas from the gas cap supply well 2N- 329A has been used as lift gas to keep these wells on line during much of the year. Hydraulic jet pumps were successfully used to lift eleven of these wells during the summer water injection cycle since the MI line was temporarily converted to water injection service. Plans are to expand this program to other Tarn wells requiring artificial lift in the future as conditions warrant. Attachment 2 Kuparuk River Unit Tarn Oil Pool 2000 Annual Reservoir Surveillance Report Produced Fluid Volumes Note: The large water volumes shown below for July, August, September and early October include water used for artificial lift (i.e. Jet Pump power fluid). As this water did not originate in the reservoir, efforts are underway to modify PAI databases and software to separately track water used for artificial lift purposes in the future. OIL GAS WATER CUM OIL CUM GAS CUM WATER Month Year STB MSCF STB STB MSCF STB 1 2000 814,403 1,289,173 3,087 13,892,962 19,164,483 438,104 2 2000 788,657 1,262,221 4,077 14,681,619 20,426,704 442,181 3 2000 839,952 1,401,479 2,839 15,521,571 21,828,183 445,020 4 2000 775,092 1,391,375 2,721 16,296,663 23,219,558 447,741 5 2000 785,532 1,465,634 2,438 17,082,195 24,685,192 450,179 6 2000 705,859 1,475,343 2,410 17,788,054 26,160,535 452,589 7 2000 661,285 1,623,497 12,670 18,449,339 27,784,032 465,259 8 2000 652,042 1,764,353 263,028 19,101,381 29,389,678 728,287 9 2000 627,882 1,448,066 332,633 19,729,263 30,837,744 1,060,920 10 2000 777,643 1,695,531 17,193 20,506,906 32,533,275 1,078,113 11 2000 676,489 1,558,952 3,454 21,183,395 34,092,227 1,081,567 12 2000 661,711 1,400,999 1,650 21,845,106 35,493,226 1,083,217 2000 TOTAL: 8,766,547 17,776,623 648,200 Attachment 3 Kuparuk River Unit Tarn Oil Pool 1999 Annual Reservoir Surveillance Report Injected Fluid Volumes WATER GAS MI CUM WATER CUM GAS CUM MI Month Year STB MSCF MSCF STB MSCF MSCF 1 2000 0 0 2,210,758 1,733,206 0 19,907,665 2 2000 0 0 2,224,814 1,733,206 0 22,132,479 3 2000 0 0 2,332,593 1,733,206 0 24,465,072 4 2000 0 0 1,763,997 1,733,206 0 26,229,069 5 2000 0 0 864,396 1,733,206 0 27,093,465 6 2000 0 0 663,723 1,733,206 0 27,757,188 7 2000 38,475 0 152,449 1,771,681 0 27,909,637 8 2000 613,614 0 0 2,385,295 0 27,909,637 9 2000 758,100 0 7 3,143,395 0 27,909,644 10 2000 6 0 1,936,133 3,143,401 0 29,845,777 11 2000 0 0 2,177,199 3,143,401 0 32,022,976 12 2000 0 0 2,225,447 3,143,401 0 34,248,423 2000 TOTAL: 1,410,195 0 16,551,516 Attachment 4 Kuparuk River Unit Tarn Oil Pool 2000 Annual Reservoir Surveillance Report Reservoir Pressure Surveys Tarn reservoir pressure is referenced commenced at 2N pad in July of 1998. ranged from 2300-2350 psi. to a depth of 5200' ss. Production Initial reservoir pressure measurements Production commenced at 2L pad in December of 1998. Consistent with 2N pad, the range on initial reservoir pressure measurements was 2330-2385 psi. Rule 8 Format Follows for 1st 2nd 3d and 4th Quarters Z O c (n O y N O¢ UO Z a O_W H cr a W >CC CC= W Cl) N N Z W O ¢a U ¢O 0 S. o ¢ Z W Q cn J_ Q O J Qa Y z (n Z Q Z J Q Q T E >> y R VI N M (D r M M V (0 0 r n� M M 10 N n N W M M O (0 OD 0 0 cD M Q) O N V f� 07 N f� N O N N V C N r N N r r N N r N N N N r r N IL m mN c c d U o_ _T > R c O y E C7 m CO D N ((DD O 0 o U c 0 D o 0 m 0 c N j N S '(� V q t00 10 O N LO 0 0 N N N N n M M M M M C} W . Q C J V M I� M d' M M M O O O O O O O O O 0 0 0 0 O 06 m O jCO � N' 0 O _ m t U rn u� M o U° co v 0) 0 M �o rn Q) U P00 m CD 100 N N (ND N lM N O V N W N 10 O O tD D) R D) N M M ID M 7 N V 1� 7 0 Q (y C7 m CT. 0 O Q N � Q N N N O N W r 1N M � NN 0 0 O O d N N O T 0 r 00 '7 m N M (NO N l00 M M N m N N 0 � m ((DD N r N do C N U) (n N Z N DD O M CO N M N (D T C O O M O M h M (D N f- N M (D O M V N O 1l O M c) N 00 V M 7 0 LL d N r N N r r N N r N N r N r r N QoOC\l (a 0CL � a_ (D 7 N V O W V M N M O) N N N (0 d = � � CD I _ o a M�0N N M c) N0 (0 m m 7 O C' f;N I,Nr. D) N 00 V 0 m M �2 O O D) n �! cy� (D In W (O O LL _ C y > � j N Y O L C N 0 0 co N (0 O N O (O co O O 0 c) D) 00 LO 00 LO N (Q� S O C O (00 n � n n M 0 0 (D O M n m M N r V 10 N coM coM r y c i Y LL F c (L 0 E F°N 0) m DNanm m m (O CYy T om L0) �0 rn°1C31 wOrn!c M p) 0) M (D N m yED_ E _ (6 O)rO) 0) 0) 07 Q) mO ID LL F U1 N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 r o oo �o oo Cc) 000000 or0000 000 U o Cry _ a (ca 0 000000000000000(D. O 3: 2 O o 0 0 0 0 0 0 0 0 0 o r O O r c m (O n l0 N V M N V M V n r 01 N _ ' N m m M N M M N N N M N M N M M N N N N N m N cq 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Q N N N N N N N N N N N N N N N N M M M M M M M M M M M M M M M M O N O O O O O O O O O O O O O O O O ._.. O C Co E C ca Z 0 0 0 o 0 0 0 0 0 0 0 0 0 0 0 0 4] lD lD lD lD lD lD lD lD LLi LL] ID LL� In lD lD L N d N a) U N >_ N a N oc E (0 co co 00 O co (O (D M N M f- a M u] a N p v) J 1 O (p Z O N N N N N M V 7 M N M M M M (h CM M M M M M M M M M M ME O T 'O E= 0 R = Z Z Z Z Z Z Z Z Z Z Z Z Z' J J J C Z j N N N N N N N N N N N N N N N N 0) tcn a_Y Attachment 5 Kuparuk River Unit Tarn Oil Pool 2000 Annual Reservoir Surveillance Report Production Logs and Special Surveys Injection surveys were conducted at drill site 2N to evaluate vertical conformance while injecting miscible gas. Three wells, 2N-307, 2N-321 A and 2N-325 were surveyed during calendar year 2000. Results from the surveys were referenced to the latest stratigraphic framework of the Bermuda pay interval to allocate injection to distinct turbidite sequences. The interpreted reservoir architecture is summarized below: Lavender Sequence (crevasse splay - limited potential) Upper Blue Sequence (present only in the south) Blue Sequence (present only in the south) Red Sequence (present only in the north) Green Sequence (present only in the north) Rose Sequence (present over most of the field) Dark Blue Sequence (present only in the south). A survey run in 2N-307 on 2/3/2000 showed no out -of -zone injection and indicated that approximately 2/3 of the total injection stream was entering the youngest of three sequences perforated in the well (Red Sequence). Based on survey results, the middle sequence (Green) was taking approximately 25% of injection, with the remainder allocated to the oldest sequence (Rose). Similar results were noted in the injection profile of 2N-321 A that was measured on 2/5/2000. Approximately 55-60% of the total injection stream was observed entering the Red Sequence, while the older Green Sequence was estimated to take roughly 31-34%. The remainder of the MI stream, or 10%, was shown to be entering the Rose Sequence. Results from an injection survey conducted on 2/6/2000 in 2N-325 showed support was largely limited to the oldest stratigraphic sequence of the Bermuda interval. Approximately 90% of the total injection stream was observed entering the Dark Blue Sequence which is limited in areal extent to the southern portion of the reservoir. The remaining 10% of injection was estimated to be entering the Rose Sequence located immediately above the Dark Blue sequence. The Tarn inter -well tracer study continued in 2000 with 5 gas -based tracers injected into Wells 2N-307, 2N-321, 2N-325, 2N-331 and 2N-343 on 1/21/00. Sampling confirmed interactions between injector 2N-307 and producers 2N- 308 and 2N-313. Very small amounts of tracer (a magnitude lower) were also detected in producers 2N-323 and 2N-329, although this may be due to sample contamination. Sampling methods are currently being evaluated to ensure future samples are accurate and representative of well interactions. Sampling also continued in 2000 at producer 2N-345, which has seen pre -mature gas and water breakthrough in the past. Interactions between 2N-345 and injectors 2N-321, 2N-325, and 2N-331 were confirmed. Tracer was detected in 2N-345 within 3 days of injection, with the strongest response from 2N-325. Based on the injection profile data mentioned above, the most likely path of communication between 2N-325 and 2N-345 appears to be occurring through a thief zone located in the upper Dark Blue sequence. As previously noted in last year's report, extensive diagnostic work was performed in 1999 to determine the path of communication between 2N-345 and offset injectors. Additional logging was performed in April of 2000 to determine the maximum depth of injection in the openhole section below the 7 5/8" surface casing shoe. This was done to locate any potential weak zones close to the producing horizon and determine if annular disposal of drilling fluid and cuttings had somehow contributed to the rapid water and MI breakthrough responses seen in 2N-345. Radioactive tracer was pumped down the OA of Wells 2N-321A and 2N-325 while logs were run inside the tubing string. In both cases, a review of the logs indicated that all fluids were exiting within 100' of the bottom of the 7 5/8" casing shoe, and thus did not appear to be a factor in inter -well communication in the much deeper Iceberg or Bermuda intervals. Reverse circulation jet pumps were installed in eleven wells (2L-305, 2L-307, 2L-313, 2L-315, 2L-325, 2N-309, 2N-319, 2N-335, 2N-337A, 2N-339, and 2N- 345) during the summer water injection cycle, with water from the injection header used as the power source fluid. The operation of the pumps was generally successful, with flowing bottom hole pressures ranging from - 1100 to 1500 psi and typical power to produced fluid ratio - 2:1. Attachment 6 Kuparuk River Unit Tarn Oil Pool 2000 Annual Reservoir Surveillance Report Well Allocation and Test Evaluation Summary The 2L and 2N Accuflows continue to undergo weekly hot diesel flushes to minimize paraffin deposition problems and maintain the accuracy of the test data. Produced fluid volumes were tracked through the Setcim production monitoring system and producing wells were tested a minimum of two times per month. Production allocation to Tarn continued to be based upon an allocation factor of 1.0 in 2000. Note: At the request of the Alaska Department of Revenue, a review of GKA metering facilities and equipment was conducted in late 2000 by a third party consultant (PriceWaterhouseCooper). Discussions are currently underway regarding possible implementation of some of the consultant's recommendations for modifying the allocation method used for GKA satellites. Attachment 7 Kuparuk River Unit Tarn Oil Pool 2000 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 2001, or are planned at this time. Development Drilling — A program of five additional development wells are planned for Tarn in 2000. Drilling is expected to commence in the second quarter of the year. All five wells are targeted for peripheral or distal areas of 2N and 2L. Successful results from the downdip wells could prove up several additional locations for drilling at a later time. MI/Water Injection — Construction of a 12" water injection line out to the Tarn drill sites is currently underway and expected to be operational by mid -summer. Once surface facilities associated with the water line are completed, individual injectors will be capable of injecting either MI or water. Plans are to inject water into both the 2N and 2L lobes and begin implementation of a fieldwide MWAG process. Future MI and water injection cycles for individual patterns will be determined based on reservoir performance. Artificial Lift — Plans are to continue to use MI for lift on some wells and hydraulic jet pumps on others. Water from the new 12" water injection line will be used as the power fluid for the jet pumps. Paraffin Mitigation — Field testing of paraffin inhibitor chemicals is currently underway at Tarn in an effort to reduce paraffin deposition in the tubing. Other ideas currently under evaluation include the use of paraffin -cutting plunger lift installations, installation of line heaters, and/or installation of pigging facilities on the Tarn production line. A laboratory experiment involving Tarn crude is also underway to assess the effectiveness of a microbial product to inhibit paraffin deposition. Exploration/Delineation - Another prospective area is the Cairn interval near DS 2N. A portion of this prospective play can be reached from the DS 2N pad. The economics of this play appear marginal at this time, but are still being evaluated. No firm time has been set to drill a well to further evaluate Cairn near DS 2N. Seismic data suggested the possibility of another possible sand lobe just to the east of the 2L lobe. This area, now known as "2L-East" was penetrated in 2000 with Well 2L-317. However, due to insufficient net pay thickness and reservoir quality, the well was sidetracked back to the main 2L lobe and is currently planned for injection service as Well 2L-317A.