Enhanced Oil Recovery (EOR) in Tight Oil: Lessons Learned from Pilot Tests in the Bakken

Transcription

1 Enhanced Oil Recovery (EOR) in Tight Oil: Lessons Learned from Pilot Tests in the Bakken Tight Oil Optimization Workshop Calgary, Alberta, Canada March 12, 215 James Sorensen John Hamling 215 University of North Dakota Energy & Environmental Research Center.

2 EERC Research Program Partners Sponsoring Partners Additional Support 2

3 Today s Objectives Review of publicly available records Five North Dakota Bakken injection tests Elm Coulee Bakken injection test Lesson s learned 3

4 Injection Tests Five North Dakota Bakken injection tests are known: 1. #966: Water, tested March April 1994 (5 days) 2. #16713: CO 2, tested September October 28 (29 days) 3. #1717: Water, tested April May 212 (?? days) 4. #16986: Waterflood followed by field gas injection Waterflood, tested April 212 February 214 (672 days) Field gas, tested June August 214 (54 days?) 5. #24779: Vertical CO 2, test began February 11, 214 (duration unknown) All Class II wells. Details of tests are limited. 4

5 Injection Test Locations 5

6 #966 Water Injection Test Meridian Oil Company. Converted existing horizontal well. Freshwater injection into Upper Bakken Shale. Injection began March 8, 1994: Shut in April 27, 1994 (5 days). shut in for approximately 1 2 months to evaluate its performance. Request to put back on pump July 19, test was found to be unsuccessful. Injected Water Volumes March 1994: 7616 bbl (avg psi). April 1994: 5644 bbl (avg. 196 psi). 6

7 #966 Water Injection Test 12 Monthly Production, #966 1 Monthly Oil 8 Injection Test Duration Oil, bbl Mar-89 Aug-9 Dec-91 May-93 Sep-94 Jan-96 Jun-97 Date 7

8 #16713 CO 2 Injection Test EOG. Fractured (April 28) with sand and gel, no report of multistages; however, well diagram shows six packers in production zone. Permit includes a detailed injection plan. Planned 6-day soak time with return to production; later altered to 3 days. Food-grade CO 2 from Praxair. Injection began September 15, 28: CO 2 injection completed on October 14, 28 (29 days). After 11-day injection, breakthrough occurred 1 mile away in an offset well. Injected CO 2 volumes: September 28: 51 bbl. October 28: 4862 bbl. No posttest results; no records of any kind after March 21. 8

9 #16713 CO 2 Injection Test 35 3 On Pump Monthly Oil Production, #16713 Monthly Oil Injection Test Duration Oil, bbl Well Returned to Sales 1 5 Aug-7 Feb-8 Sep-8 Mar-9 Oct-9 May-1 Nov-1 Jun-11 Dec-11 Jul-12 Jan-13 Aug-13 Mar-14 Sep-14 Date 9

10 #16713 CO 2 Injection Test Offset Wells After injecting CO 2 for 11 days into the Austin 1-2H (#16713), we have begun to see breakthrough from Austin 1-2H (#16713) to the Austin 2-3H(#16768), over a mile away. The other offset wells we are monitoring, the Austin 9-11H (#1775) and the Bruhn 1-12H (#17475), have yet to show an increase in CO 2 concentrations. The concentration observed in the Austin 1-2H (#16713) has increased from a background reading of 5 ppm the week before injection began and during the first days of the injection to approximately 25, ppm. Based on our calculations this translates to approximately 4 Mcfd of the approximately 1 Mcfd we are injecting into #

11 #16713 CO 2 Injection Test: Offset Wells 11

12 #16713 CO 2 Injection Test: Gas Production in Offset Well # Monthly Gas Production in Offset Well #16768 Monthly Gas Injection Test Duration Gas, Mcf Additional production from injection test? 4 2 Aug-7 Apr-8 Dec-8 Aug-9 May-1 Jan-11 Sep-11 May-12 Jan-13 Oct-13 Jun Date

13 #1717 Water Injection Test EOG. Fractured (August 28) with sand and gel, no report of multistage; however, seven packers are illustrated in the well diagram. Taken off production April 22, 212. Produced water injection test. Huff n puff. Injection test began May 3, 212: No available notes on completion of test. Contradictory injection dates listed on state Web site. Planned 3-day injection with 1-day soak. Cycle to repeat until deemed uneconomical; returned to production. August 2, 212, additional reserve pits were installed to collect fracture sand Requested low-pressure injection through artificial lift on October 12, 212 (sundry notice), i.e., artificial lift was initiated. No newer records. Injected Produced Water Volumes April 212: 1,38 bbl. May 212: 28,797 bbl. 13

14 #1717 Water Injection Test 25 Monthly Oil Production, #1717 Monthly Oil 2 Oil, bbl Injection Start "Low Pressure Injection" Jun-8 Dec-8 Jul-9 Jan-1 Aug-1 Feb-11 Sep-11 Apr-12 Oct-12 May-13 Nov-13 Jun-14 Date 14

15 #16986 Water and Field Gas Injection Tests EOG Middle Bakken horizontal. Well currently listed as Inactive gas injector. Time line: Spudded January 28, 28. Began producing in April 28. Fractured June 28 (sand and gel, no note of multistage OR presence of production packers). On pump late July 28. September 28 applied for permit for recompletion and injection of food-grade CO 2. Permit approved late October 28. Permit rescinded October 29. No evidence to suggest conversion occurred. December 211, request for conversion to EOR injection well (produced water injection, waterflood pilot ); approved February 212. Water injection began April 16, 212. Periodic injection until February 214. No additional details in well file. Returned to production in March 214. Cumulative Injected Produced Water Volumes (North Dakota Industrial Commission [NDIC]) 438,969 bbl 15

16 #16986 Field Gas Injection Test Time line, continued: June 214 requested change to gas injection. Test consisted of injection of field gas with some produced water injection. Water used to manage effects of gas mobility in the fracture system or, if needed, build system pressure with less gas volume. Goal evaluate and test the technical feasibility and production performance results of injecting produced gas into the Bakken Formation for the purposes of secondary recovery. Injection began June 27, 214. Appeared to have communication with the production well. Injection data provided through August 2, 214: Injection end date unknown (ongoing?). Injected field gas volumes: June 214: 4598 Mcf July 214: 5,871 Mcf August 1 2, 214: 33,26 Mcf Cumulative total: 88,729 Mcf No posttest production data available. 16

17 Volume, bbl #16986 Water and Field Gas Monthly Production, #16986 Montly Monthly Oil Oil Monthly Water Injection Test Duration CO 2 Injection Permit Approved CO 2 Permit Rescinded Injection Tests Water Injected, bbl 6, 5, 4, 3, 2, 1, Request Waterflood Injection Permit; Approved Feb. 212 Waterflood, Monthly Injection Volumes #16986 Apr-12 Jun-12 Aug-12 Nov-12 Jan-13 Apr-13 Jun-13 Sep-13 Nov-13 Feb-14 Date Water Injected Field Gas Injection Start Apr-8 Oct-8 May-9 Dec-9 Jun-1 Jan-11 Jul-11 Feb-12 Aug-12 Mar-13 Oct-13 Apr-14 Date 17 Waterflood Injection Start Resume Production

18 #16986 Water and Field Gas Injection Tests: Offset Wells 18

19 #16986 Waterflood: Production from Offset Well #16461 Volume, bbl Offset Well, #16461, Monthly Production Monthly Oil Monthly Water Monthly Gas Water Injected, Mbbl Water Injected #16986 Water Injected Apr-12 Oct-12 May-13 Nov-13 Date Waterflood Injection Gas Produced, Mcf Jan-7 Sep-7 Jun-8 Feb-9 Oct-9 Jun-1 Feb-11 Nov-11 Jul-12 Mar-13 Nov-13 Jul-14 Date 19

20 #16986 Water and Field Gas Injection Tests: Offset Wells 2

21 #16986 Waterflood: Production from Offset Well #16346 Volume, bbl Offset Well, #16346, Monthly Production Monthly Oil Monthly Water Monthly Gas Water Injected, Mbbl Water Injected #16986 Water Injected Apr-12 Oct-12 May-13 Nov-13 Date Waterflood Injection Gas Produced, Mcf Aug-6 Apr-7 Jan-8 Sep-8 May-9 Jan-1 Sep-1 Jun-11 Feb-12 Oct-12 Jun-13 Mar-14 Date 21

22 Volume, bbl #16986 Water and Field Gas Monthly Production, #16986 Montly Monthly Oil Oil Monthly Water Injection Test Duration CO 2 Injection Permit Approved CO 2 Permit Rescinded Injection Tests Water Injected, bbl 6, 5, 4, 3, 2, 1, Request Waterflood Injection Permit; Approved Feb. 212 Waterflood, Monthly Injection Volumes #16986 Apr-12 Jun-12 Aug-12 Nov-12 Jan-13 Apr-13 Jun-13 Sep-13 Nov-13 Feb-14 Date Water Injected Field Gas Injection Start Apr-8 Oct-8 May-9 Dec-9 Jun-1 Jan-11 Jul-11 Feb-12 Aug-12 Mar-13 Oct-13 Apr-14 Date 22 Waterflood Injection Start Resume Production

23 2 #16986 Water and Field Gas Injection Tests #16986 Daily Field Gas Injection Volume and Pressure Gas Injected, Mcf Uncertainty in Reported Pressure Values Daily Volume Daily Pressure Pressure, psig 2 5 6/25/214 7/2/214 7/9/214 7/16/214 7/23/214 7/3/214 8/6/214 8/13/214 8/2/214 Date 23

24 #16986 Water and Field Gas Injection Tests 1, #16986 Cumulative Field Gas Injection Volume 9, 8, Gas Injected, Mcf 7, 6, 5, 4, 3, 2, 1, 6/25/214 7/2/214 7/9/214 7/16/214 7/23/214 7/3/214 8/6/214 8/13/214 8/2/214 Date 24

25 #16986 Water and Field Gas Injection Tests Gas injection operations began on the Parshall 2-3H (#16986) on June 27, 214, which represented the first day where we had consistent gas injection rate. On July 2, 214, the Patten 1-2H (#16461), which is one of three wells on the 128 EOR pilot area, had gas production of 177 Mcf and oil production of 33 bbl. Preinjection GOR for this well was approximately 4 scf/bbl; therefore, we would estimate that of the 177 Mcf produced on this day, 164 Mcf was incremental as a result of gas injection operations. To mitigate the volume of gas channeling through to the Patten 1-2H (#16461), our first operational course of action was to reduce the VFD speed of the pump to help build bottom hole pressure in this well. On 7 /3 we continued to observe instantaneous gas rates on the Patten 1-2H (#16461) and these rates were showing an escalation from the previous day. We decided to stop the pump on the Patten 1-2H (#16461) and operate this well on an as needed basis. We feel this will help mitigate the volume of gas that it being cycled from injection to surface and help build BHP in the injection well. 25

26 #16986 Water and Field Gas Injection Tests: Offset Wells 26

27 #16986 Field Gas Production from Offset Well # Monthly Production, # #16461 Daily Water Production 3 1 Oil, bbl Water, bbl Water 4 2 Daily Oil Daily Gas 6/18/14 7/8/14 7/28/14 Date 8/17/ Gas, Mcf 4 2 No notable production response was observed in other offset wells over this time period /18 6/28 7/8 7/18 7/28 8/7 8/17 8/27 Date 27

28 #24779 CO 2 Injection Test Whiting. Class II, vertical well, inactive. Drilled as a stratigraphic test well. Collected 366 of core. No production. Test designed to see if the formation can accept CO 2 gas. Planned for 2-day test. Cemented production casing. Planned to use packers to isolate the Middle Bakken zone. Planned injection of 1 Mscf of CO 2. Short soak period (days). Produce well, collect samples, and reinject all fluids except samples. Injection reported to start on February 11, 214. Results unavailable/unknown. 28

29 Elm Coulee Test in Montana Conventional huff n puffs respond within days or weeks. BBLS Oil/Month Response at Elm Coulee 2 appears to have taken months. Burning Tree State 36-2H Oil Production CO₂ Huff 'n Puff Test Period Put back on pump Period of Possible Incremental Oil Recovery? Oil Production Production Month DFN Could the delayed response be a reflection of the dominance of diffusion as a mechanism for CO 2 movement in the Bakken? From NW McGregor (Mission Canyon) Future field tests need robust baseline characterization, injection, and monitoring data to determine fate and effect of CO 2 in the reservoir. From NW McGregor (Mission Canyon) 29

30 What Did We Learn?... Water and gas injectivity into various lithofacies of the Bakken petroleum system has been demonstrated. Production responses to injection were observed, which indicates that fluid mobilization can be influenced. Laboratory results suggest potential for high mobilization under the right conditions. A more complete understanding of these conditions can be gained from field tests. Engineered tests within a well-characterized geologic setting will help inform successful injection programs by providing fundamental knowledge needed to dovetail lab studies, geologic models, and reservoir simulation. This will allow evaluation of EOR scenarios that can guide more successful pilot and field EOR development. 3 Greg Latza Photography

31 Recap Too few data exist for the six injection tests performed in the Bakken to perform thorough engineering and geologic analysis, nor are the designs or test objectives fully understood. Unless we are able to gain insight into these previous tests, we will need to develop a basic understanding of injectivity and reservoir performance in order to better engineer and adapt successful EOR programs in unconventional reservoirs. Unconventional reservoirs will require an unconventional approach 31 Andrew Burton / Getty Images

32 Contact Information Energy & Environmental Research Center University of North Dakota 15 North 23rd Street, Stop 918 Grand Forks, ND World Wide Web: Telephone No. (71) Fax No. (71) James Sorensen, Senior Research Manager John Hamling, Senior Research Manager 32

33 Acknowledgment This material is based upon work supported by the U.S. Department of Energy National Energy Technology Laboratory under Award No. DE-FC26-8NT Disclaimer This presentation was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government, nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. 33