The URL can be used to link to this page

Home My WebLink About1999 Tarn Oil PoolARCO Alaska, Inc Post Office . 1x 100360 Anchorage Alaska 99510-0360 Telephone 907 276 1215 Stephen V. Bross Supervisor Greater Kuparuk Area Satellite Development ATO - 1126 Phone 265-6083 Fax 265-6133 March 27, 2000 Mr. Robert Christenson, Chairman of the Commission Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3120 Re: 1999 Tarn Oil Pool Annual Reservoir Surveillance Report Dear Mr. Christenson: A L r � gym. a / it In compliance with Rule 11, Conservation Order No. 435, 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 1999. 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 1999 (Attachment 4). d. Results of production surveys, and any special surveys, taken on the Tarn Oil Pool in 1999 (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 Judith Abrahams at (907) 659-7061 or Ryan Stramp (907) 265-6806. Sincerely, Steve Bross GKA Satellite Development Supervisor ARCO Alaska, Inc. is a Subsidiary of Atlantic Richfield Company RECEIVED NEAR 29 2000 Riaska Oil & Gas Cons. Corjjmission A choTyge AR313-6003-C Attachment 1 F?ECEIV ED Kuparuk River Unit MAR 292000 Tarn Oil Pool A►askaQ 1999 Annual Reservoir Surveillance RepoOGasCMs Co Summary of the Enhanced Recovery Project An�'01�e ftissron 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 1998, twenty-two Tarn development wells had been drilled. Progress of FOR Project New development activity in 1999 consisted of the drilling of five additional development wells, bringing the total number of Tarn development wells to twenty-seven. Continuous MI injection continued as the primary enhanced recovery technique in 1999, however, field tests of water injection took place in the spring and summer of 1999. The primary goal of these tests was to evaluate the feasibility of shifting to an MWAG FOR process. Listed below are the key findings from the 1999 Water Injection Tests at Tarn. 1. 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. 3. Some signs of decreasing permeability (reservoir damage) were seen in the analyses of the pressure fall off data over the duration of the water injection test. 4. Injection of water above parting pressure seems to have stimulated the wells resulting in increased MI injectivity after the water injection as compared to pre -water injection rates. 5. One producer (2N-345) began producing water during the water injection test. The rapid timing of the water breakthrough suggests the path followed by the water may not have been through the Tarn reservoir, although diagnostic logging did not show any signs of near wellbore channels in the offset injection wells. Reservoir Management Summary Tarn began production 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 1998 with 1.2 BCF of MI injected in 1998. In 1999, Tarn produced 9.5 MMBO and 13.4 BCF of gas. The injection totals for 1999 were 16.5 BCF of MI and 1.7 MMBW. The cumulative I/W ratio for DS 2N is estimated at .67 while the estimated cumulative I/W for DS 2L is 1.54. The monthly average I/W ratios for DS 2N and 2L in December 1999 were 1.22 and 2.32 respectively. The MI/water injection process at Tarn is working to stabilize oil production rates and GORs from the producing wells. Even the downdip wells described as being potentially "compartmentalized" in last annual report now are showing signs of pressure support. Thus far only one well, 2N-345, is showing signs of MI breakthrough. Investigations are still underway to determine of this breakthrough is occurring through the reservoir or through some other pathway. As discussed in last year's report, the existence of the higher quality reservoir in the "main channel" area of DS 2N makes the possibility of an MWAG process more feasible than originally thought. Water injection was tested at DS 2N in the summer of 1999 with positive results. Paraffin deposition in the producing wellbores, surface drill site facilities, and cross-country production pipeline continues to have some impact on production operations at Tarn. Mechanical scraping and hot oil treatments are used to keep the wellbores clear. Hot oil treatments are also used to flush out the on - pad surface facilities. Paraffin buildup in the cross-country pipeline is being monitored with periodic radiographic inspection. Several of the Tarn wells required artificial lift to produce continuously against the pipeline backpressure. MI or gas from the gas cap have been used as lift gas to keep these wells on line during much of the year. Hydraulic jet pumps using injection water as powerfluid were utilized during the water injection test period. Attachment 2 Kuparuk River Unit Tarn Oil Pool 1999 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 1999 667522 974363 1469 4201969 5450790 8028 2 1999 603132 638740 2518 4805101 6089530 10546 3 1999 738676 738729 3407 5543777 6828259 13953 4 1999 777329 872463 4095 6321106 7700722 18048 5 1999 934264 1129081 5016 7255370 8829803 23064 6 1999 863132 1049340 1012 8118502 9879143 24076 7 1999 799434 1074437 50796 8917936 10953580 74872 8 1999 878781 1397651 148469 9796717 12351231 223341 9 1999 801475 1464988 192005 10598192 13816219 415346 10 1999 865892 1445286 12221 11464084 15261505 427567 11 1999 801409 1355425 3836 12265493 16616930 431403 12 1999 813066 1258380 3614 13078559 17875310 435017 1999 TOTAL 9544112 13398883 428458 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 MO YR STB MSCF MSCF STB MSCF MSCF 1 1999 0 0 1652874 0 0 2847778 2 1999 0 0 1376122 0 0 4223900 3 1999 0 0 893459 0 0 5117359 4 1999 0 0 1620071 0 0 6737430 5 1999 0 0 2133240 0 0 8870670 6 1999 0 0 1748901 0 0 10619571 7 1999 520959 0 0 520959 0 10619571 8 1999 650091 0 0 1171050 0 10619571 9 1999 562156 0 153317 1733206 0 10772888 10 1999 0 0 2163509 1733206 0 12936397 11 1999 0 0 2431204 1733206 0 15367601 12 1999 0 0 2329306 1733206 0 17696907 1999 TOTAL 1733206 0 16502003 Attachment 4 Kuparuk River Unit Tarn Oil Pool 1999 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 2"d 3'd and 4th Quarters » E � « \ o, )} \ 'b E (®0 - AL)[ \ 73 0 n _\ @/ =n co §/ \@ Q\ }, \� { ®2 ){ o@ \k 00 #E C) } k co ° \_ : 0 c _0 ) « E / ) { =m 2 /») &oo } 3)]\-0 \ °£_�� / �a z £2. a -0 ) 2 _ ( {/ E) § m as ] - k) != 00 o\ {\ 00 \i \44 0 ! a z - / - / $ E \ 0 a m z 0 ) CL \ o ) - e0E j d < z / \ t § a ° E a ° e z }) \ \ ) ƒ 05, §/ v M w c a5 E 0 n H a G N N d U C � U`r U a. 0 C9 N C O � � O U o a c O 6 7 V U O u `c O a o 01C)C) o UU� pornco 0 d `n C3 c o a� c M Y U m N N r O O O _N C O O o 0 c of E 7 N 0) }10 O Q m d O O N N O a o ca LL Q N p O a a Lf)LOU)co M M O2 M N_ O = E r r r r a)a Q > 0� C0 } Cl) u'1 N O a a) 4� LO O 7 O 0 n O Q c o m rn n r Q C O D C 7 d Y � O Cl O O O O of 7 O N co Cl) 0 c rn N a C N a 3 O O m y CL 7 (1) rn rn 0 7 E m m 0)E L O N r U O d O C a) � M o) m m Q O a) ON iO iO iO cn r O C4,N E a) O LO O 00 ro `o 03 O<900 c m 2 00 N 0 0 M O co CO c c c a Q E C4 cm 0 0 0 0 o _ a >N ] z coNcqi c+� cq c o 0 0 0 O p c 0 0 0 0 Q LO0�LO a) Oo r O c E Q p Q C3 a`) z a a> t O o U E a) O z Mr- 0 0 -6 E O — M� M M a) O _+- C O J Z Z Z cmN N Z ?: N N N N L <n k § o E / « \ o� )} \ 9n[ \o/ _ E \ 71 0 3 _\ � \ o r\ §ƒ =n \@ \ Qf \ b #, t� t ®8 0 �� /f 2 L) ) d #E } #\ )) ®° {! : 0 © a �o d » E 2 \ \ '0. p =o 2 k») a) / a- ¥0 0OL ( a) a) ° ) a CDf�)) : 2 5 { \/ Et § 3° /a ] // _ ,o C) \ E ° {o /©» : 0 3 { - \ -/ $ E D 0 6 ■ J o k \ a)o eoEc G a )$2� / § a ! t ± E ° E e f }) { \ }\ Iz ( §� \ )} \ sE[ (®\ ta[ \_ ��\ 3 9\ \ o � >/ =e G co o §/ \° ° \ Q2 \ a Gr < t a }/ ! 0� ~ e/ & c 3 -- <E )) y§ G12 0 © (D co �_m \ �§CL ) CD e_ § { %E 9 ƒ c o 2 >0 Ea_ ®=\c \ �s \/? 6 D ) = §m y { \( �t § 2» ® ] k{ ,_ \-- !o ! /) )�\ {/ \° 0 \f 00 §� ) E88 / / u \ - _ < E a d a)2 o 0 ) mmm 0 j \ {Bo== G < < <� 2 / 0 § o ! } f § <r_ b 2mm \{ f \ \ / \kk /\ Attachment 5 Kuparuk River Unit Tarn Oil Pool 1999 Annual Reservoir Surveillance Report Production Logs and Special Surveys Injection surveys were completed at drill site 2N to evaluate injection splits with wells on miscible injection (1/1/99 - 6/28/99 and 9/29/99 - 12/31/99) or water injection (7/6/99 - 9/26/99). The 1/99 MI profile in 2N-321A identified a thief zone at the top perforated interval, which was taking - 60-70% of injection. The MI logs completed prior to water injection in 2N-307, 2N-325, 2N-331, and 2N-343 indicated relatively uniform profiles, with each perforated interval typically taking < 35% injection. The 5/99 MI profile in 2N-321A was completed after the trucked water injection test (see Attachment #6) and was consistent with the 1/99 MI profile. The logs completed while on water injection for 2N- 321 A, 2N-325, and 2N-343 showed changes in the profile distributions from the MI logging results. The 7/99 water injection log for 2N-321A indicated a thief zone profile consistent with the previous MI logging, but the 9/99 water injection log showed a uniform profile across the entire Bermuda interval with the top interval taking < 30% injection. The MI logging for 2N-325 indicated injection in 3-4 perforated intervals, but the 9/99 water injection log showed all injection into the bottom two perforated intervals. The MI logging for 2N-343 indicated injection in 3 perforated zones, while the 9/99 water injection log showed a mid Bermuda thief zone taking 100% water injection. Perforations were added in injection wells 2N-325 and 2N-343 and production wells 2N-335 and 2N-345 to increase injection and production conformance, respectively. The subsequent injection profiles in 2N-325 indicated < 10% injection into the add perf interval on MI and 0% on water injection. The low penetration and low shot density perfs added in 2N-343 did not change the injection profile. The production profile in 2N-345 indicated that the add perf intervals were producing > 50%. The production profile in 2N-335 was inconclusive due to logging problems associated with the high deviation. A pressure survey completed in 2N-335 following the add perfs indicated there was no cross flow between the perforated intervals. Special logging procedures were completed to evaluate the pre -mature water flood and MI breakthrough in producer 2N-345. Borax PNL, water flow (WFL), and RA tracer logs were run in 2N-321A, 2N-325, and 2N-343. A CNL log was run in well 2N-321 A and overlaid with the open hole neutron log. A down hole pressure fall -off was completed with a down hole shut in tool in 2N-325 to validate the results of surface PFO evaluations while on water injection. The objectives and results of these logging procedures are addressed further below. The primary objective of Phase I of the Tarn pilot water injection test was to determine if water injection into the Bermuda interval would result in catastrophic formation damage. Injection well 2N-321A was selected for the pilot test since a high perm thief zone had been identified from MI profile logging. The 2N-321A thief zone, which is at the top of the Bermuda interval, was mechanically isolated and - 3,500 bbls. of produced water was transported from CPF2 and pumped into the thief zone (4/3/99 - 4/8/99). Step rate tests indicated the thief zone was stimulated, and a pressure gauge below the mechanical isolation indicated pressure communication from thief zone injection to the isolated Bermuda zone below. Catastrophic formation damage was not observed, and a post water injection MI profile in 2N-321A (with the thief zone no longer isolated) showed a consistent injection profile to that observed before water injection. Gas based chemical tracers were injected at drill site 2N to evaluate MI flood performance. Four tracers were added 4/99 in 2N-325, 2N-331, 2N-343, and the 2N-321A thief zone. Two additional tracers were added 6/99 in 2N-307 and the entire injection interval in 2N-321A. Gas sampling of the offset producers and analysis of the samples by ProTechnics has not indicated tracer breakthrough. A 1-3/4" CTU velocity string was installed in well 2N-339 on 4/12/99 to improve the production hydraulics. The production characteristics did not change significantly after the velocity string installation, but paraffin problems in the wellbore were magnified due to the reduced tubing ID. The primary objective of Phase II of the water injection test was to determine if long term IWAG was feasible. Water injection was initiated in 2N-321 A, 2N- 331, and 2N-343 in July, and subsequently started in 2N-307 and 2N-325 in August. Step rate tests and pressure fall -off data indicated well stimulation with injection above frac gradient, and the increase in MI injectivity after water injection validated this data. A down hole shut in tool was used in 2N-325 to validate the surface pressure fall -off evaluations. Catastrophic formation damage due to water injection was not observed in any of the 2N injectors. Reverse circulation jet pumps were installed in five wells (2N-309, 2N-319, 2N- 335, 2N-337A, and 2N-345) during Phase II of the 2N water injection test, 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. Water flood breakthrough was first identified in producer 2N-345 with the 7/30/99 well test. Diagnostics were completed while drill site 2N was still on water injection to determine the source of pre -mature breakthrough. The diagnostics included borax PNLs and water flow logs in offset injection wells 2N-325 and 2N-343, which did not indicate out of zone injection above the Bermuda. RA tracer was injected in offset injectors 2N-321A, 2N-325, and 2N- 343. Subsequent logging in these injection wells showed possible tracer above the Bermuda at two depths in 2N-321 A. Water based chemical tracers were injected 9/99 in 2N-321 A, 2N-325, and 2N-343. Analysis of produced fluid samples from 2N-345 indicated tracer breakthrough from injector 2N-321 A sixteen days after tracer injection, and a lower concentration breakthrough from 2N-325 was observed sixteen days after tracer injection. MI injection was re- established following Phase II of the water pilot, and MI breakthrough was observed in 2N-345 based on the elevated GOR and API gravity. A CNL was run in offset injector 2N-321A and overlaid with the open hole neutron log. Gas saturation increases in comparison to the base open hole neutron were observed in the Iceberg interval above the Bermuda in 2N-321A. The evaluation of the injection communication to 2N-345 is ongoing in 2000. Attachment 6 Kuparuk River Unit Tarn Oil Pool 1999 Annual Reservoir Surveillance Report Well Allocation and Test Evaluation Summary The 2N Accuflow was redesigned for increased rate capacity and commissioned at the end of 1998. Chemical injection sensitivities completed in February for the 2N Accuflow verified the requirement for a minimum of 5 gpd anti -foam injection for effective separation of wells producing greater than 2,500 bopd. A portable testing separator provided by TRICO Industries was utilized in April for series testing with the 2N Accuflow and verified the repeatability of the oil and gas measurements for the two systems. Use of the portable testing systems for the purpose of well testing at 2N was discontinued 5/10/99. The 2L Accuflow was commissioned on 4/19/99. Well testing from January through May was completed with portable testing separators provided by Halliburton Energy Services, TRICO Industries, and Production Testing Services. The PTS portable separator was utilized in May for series testing with the 2L Accuflow and verified the repeatability of the oil and gas measurements for the two systems. Use of the portable testing systems for the purpose of well testing at 2L was discontinued 5/27/99. A minimum of two well tests per month were taken on production wells. Production volumes were tracked through the Setsim production monitoring system. Production allocation to Tarn continued to be based upon an allocation factor of 1.0 in 1999. Attachment 7 Kuparuk River Unit Tarn Oil Pool 1999 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 2000, or are planned at this time. Development Drilling — A program of nine additional Tarn development wells is planned for Tarn in 2000. Drilling is expected to commence in the second quarter of the year. Six of the new wells will be drilled in the updip area if DS 2N. The remaining three wells will target downdip/distal locations in the 2N and 2L lobes. Successful results from the downdip wells could prove up several additional downdip locations for drilling at a later time. MI/Water Injection — The current plans are to WAG the Tarn injection line back to water this summer for another period of water injection. Both DS 2N and DS 2L would be switched to water this time. This will allow another water slug to be introduced at 2N to help mitigate the ultimate effects of MI breakthrough and improve sweep. The 2L water injection will confirm the viability of water in the 2L lobe and also begin the MWAG process at this pad. Options for implementing MWAG at Tarn over the long term are being investigated. Artificial Lift — We plan to continue to use MI for lift and to use water powered jet pumps in the summer when the injection line is on water service. Longer - term alternatives such as a "booster station" are still being evaluated. Paraffin Mitigation — Evaluations are underway targeting alternative ways to address the paraffin issues. Ideas under evaluation include the use of paraffin cutting plunger lift installations, installation of a line heater at Tarn, and/or installation of pigging facilities on the Tarn production line. Exploration/Delineation - The Unit expansion approval document included a stipulation that by October 1, 2000, a well had to be drilled into one of the six southern leases of the expanded area, or an approved AFC to do so during the 2000/2001 winter drilling season had to be in hand. The owners have drilled three penetrations into the Meltwater North prospect in the 1999/2000 exploration season. Two of these penetrations are on the stipulated block of leases, thus fulfilling the work commitment. Another prospective area is the Cairn interval near IDS 2N. A portion of this prospective play can be reached from the IDS 2N pad. Economics of this play appear marginal, at best, at this time, but are still being evaluated. No firm time has been set to drill a well to further evaluate Cairn near IDS 2N. Seismic data suggests the possibility of another possible sand lobe just to the east of the 2L lobe. This area, now known as "2L-East" likely cannot be reached from IDS 2L. Alternatives for testing this area are being considered.