2010 University of North Dakota Energy & Environmental Research Center.

Transcription

1 Zama Acid Gas EOR, CO 2 Storage, and Monitoring Project CSLF Storage and Monitoring Projects Interactive Workshop Saudi Arabia March 1, 2011 John A. Harju 2010 University of North Dakota Energy & Environmental Research Center.

2 Acknowledgments Apache Canada, Ltd. Natural Resources Canada Alberta Energy Resources and Conservation Board RPS Energy Advanced Geotechnology, Inc. U.S. Department of Energy National Energy Technology Laboratory y( (NETL)

3 Where s Zama? Operated by Apache Canada, Ltd.

4 Zama Pinnacle Reef

5 Zama History Discovery 1967 Primary Well Development 60 s-70 s Waterflood Implementation 80 s - present (selected pinnacle reefs) Number of Pools Discovered to 846 Date Cumulative oil produced to August 2006 Current Field Production 209 mmstb (17.4% OOIP) 6, % water cut Source: Nimchuck, 2006

6 Zama History Estimated Field Recoveries MMbbls Primary Recovery Secondary Recovery Base Case Proven CO 2 Recovery Probable CO 2 Recovery Remaining Unrecoverable Technical evaluation based on $61 Million demonstration project in operation since Incremental pool 15% Zama Field OOIP is 1200 MMbbls Source: Nimchuck, 2006

7 Zama Acid Gas Enhanced Oil Recovery (EOR) Project Unique approach combining acid gas disposal and carbon dioxide (CO 2 ) EOR. Acid gas is obtained from EOR recycle and additional field production passed through the onsite gas plant. Eliminated CO 2 venting to the atmosphere and surficial stockpiling of elemental sulfur. Six pinnacles currently accepting acid gas for EOR. Potential for expansion into Potential for expansion into hundreds of additional pinnacles.

8 Current Reservoir Pressures Vs. Original Candidate EOR Pools Near Zama Gas Plant (6 km radius) 30,000 25,000 HyCal and Depleted Oil HyCal and Initial Oil BP Alston w/40% H2S Alston w/40% H2S Pressure e, kpa 20,000 15,000 10,000 Slim Tube Test Result 5,000 - Pure CO2 MMP Acid Gas (33% H2S) MMP Original Reservoir Pressure Lab Measured MMP (Pure CO2) Lab Measured MMP (20% H2S) Lab Measured MMP (40% H2S) Most Recent Pressure Source: Lavoie, 2005

9 Rising Bubble Apparatus (RBA) Minimum Miscibility Pressure (Multicontact) MMP (MPa) Rising Bubble Apparatus MMP for H 2 SandCO 2 Injection Gas Zama Keg River F Pool W6M Original Reservoir pressure Original BP 8.9 MPa Depleted BP 6.9 MPa Depleted BP 4.9 MPa Mol% H 2 S in CO 2 Injection Gas Actual H 2 S conc Slide courtesy of B. Jackson

10 Zama Acid Gas Project - Risks / Challenges Vertical Sweep efficiency control Excessive acid gas breakthrough Protection of wells and pipelines against corrosion Determining i optimum perforation zones over the life of each pinnacle Optimum gas injection rates Safety in handling high H 2 S concentrations Possible need to drill additional wells Plugging and freezing up of wells due to hydrates, wax, and asphaltene precipitation (wax stabilized hydrates) Slide courtesy of B. Jackson

11 Zama Pinnacle (F-Pool) Carbonate reservoir Shekilie Basin 5300 feet deep About 40 acres at the base (.16 km 2 ) 400 feet tall (120 m) 10% average porosity md permeability 2100 psi initial reservoir pressure Zama Basin Patch (Pinnacle) Reefs

12 Current F-Pool Configuration Top-down injection scheme through one wellbore. Injected gas stream is approximately 70% CO 2 and 30% H 2 S. Two production wells. Observation well completed in the Sulphur Point Reservoir. Former producer completed in top of pinnacle, currently plugged to 104 m above top of pinnacle. N 100/ W6 DISCOVERY WELL UNUSED IN EOR KEG RIVER F POOL Open Production Perforations Open Injection Perforations 102/ W6 100/ W6 103/ W6 PROD #2 CO2 INJ PROD #1 SLAVE PT. AQUIFER FT. VERMILLION EVAPORITE (WATT MTN. AQUITARD) WATT MTN. SHALE F Pool -966 m SS SULPHUR POINT MUSKEG Dolomite Stringer ANHYDRITE AQUITARD MDT Intervals m SS m SS m SS m SS m SS m SS GAS/OIL CONTACT SS m SS TD (injected acid gas) m SS (TVD) -1106m SS 108m ZAMA MEMBER KEG RIVER POOL m SS Abdn. Comp. 142m ZAMA MEMBER m SS 77m TD ORIGINAL O/W m SS (TVD) CONTACT LOWER Spill TD m SS (TVD) KEG RIVER Spill point AQUIFER point TD m SS (TVD)??????? S

13 F-Pool Pinnacle Production History Pool Pressure and Production History ,000 Ra ate (m3/d) Began production in January 1967 Cumulative oil production prior to 2006 = 1,104,887 bbl 25,000 20,000 15,000 10,000 Datum Pr ressure (kpaa) & GOR (m3/m3) x , Jan-67 Jun-72 Dec-77 Jun-83 Nov-88 May-94 Nov-99 May-05 Daily Fluid PROD m3/d DAILY OIL PROD m3/d DAILY WTR INJECTION m3/d /10 GOR m3/m3 x 10 Pressure Survey Survey Date Oil 175,663 m3 Gas 15,144 e3m3 Wtr 59,898 m3 Wtr Inj 366,424 m3

14 Acid Gas Injection Began Injection December 15, Average injection rate around 1 MMCF/D. Second production well completed June Cumulative injection over 60, tons. Cumulative incremental production is over 50,000 barrels. It is anticipated that as much as 588,000 additional barrels (approximately 15% of the estimated original oil in place) can be produced from the Zama pinnacle reef structure using this technique.

15 Philosophy of Monitoring Maximize the use of existing data sets in an effort to characterize the baseline conditions of the site. Minimize the use of invasive or disruptive technologies to acquire new data. Monitoring, verification, and accounting (MVA) data acquisitions will be coordinated with routinely scheduled operation activities. Ensure that the monitoring operations are as transparent as possible to the day-to-day field operations. The Zama MVA program was developed using current Alberta regulatory framework for acid gas injection. Characterization activities were added to fully describe the system and provide confidence in the safe and secure storage of injected fluids.

16 MVA Operations Monitor the CO 2 H 2 S plume through: Perfluorocarbon tracer injection and fluid sampling in the overlying Sulphur Point Formation Reservoir pressure monitoring Wellhead and formation fluid sampling (oil, water, gas) Monitor for cap rock failure through: Pressure measurements of injection well, reservoir, and overlying formations Fluid sampling of overlying formations Determine injection well conditions through: Wellhead pressure gauges Well integrity tests Wellbore annulus pressure measurements

17 Geology and Hydrogeology Results Conducted to better understand the storage characteristics of regional aquifer systems and the fate of acid gas. Results indicate there is minimal potential for acid gas migration to shallower strata and potable groundwater.

18 Mechanical Integrity Program elements include: Evaluation of possible cap rock leakage mechanisms. Triaxial and unconfined compressive strength. Uniaxial i pore volume compressibility. Schmidt rebound hammer. Minimum horizontal in situ stress orientations. Vertical stress magnitude. Geomechanical simulation of acid gas injection.

19 Mechanical Integrity (continued) Modular Dynamics Test July 2008 Performed to obtain horizontal stresses in reservoir cap rock Tested three intervals: Two anhydrite One dolomite stringer (encased in anhydrite) Unable to fracture anhydrite! Fracture attained in dolomite at over 5000 psi. Allowable injection pressure is approximately 2100 psi.

20 Geochemistry Petrophysical evaluation Injection zone, cap rock, and overlying porous intervals. Laboratory work EERC acid gas soak test to determine rates of mineral reactions in carbonates and evaporites. Modeling To evaluate reactions in carbonates with respect to: Acid gas. Formation fluids. Formation minerals.

21 Wellbore Cement Acid Gas Interactions The EERC has developed novel (innovative) approaches to prepare and maintain H 2 S CO 2 mixtures under relevant sequestration conditions. Cement samples were exposed for a period of 28 days at a temperature t of 50 C and a Up to 18 samples per reactor can be run in individual glass vials. pressure of 15 MPa using pure CO 2 and H 2 S CO 2 ( 21 mol% H 2 S in the vapor phase) to simulate acid gas.

22 Wellbore Cement Acid Gas Interactions (continued) The CO 2 -only exposed cement underwent carbonation and decalcification in the outer rim area, while the interior regions of the cement remained intact and unaltered. The H 2 S CO 2 exposed cement exhibited carbonated zones similar to the CO 2 -only samples. However, the H 2 S CO 2 exposed cement showed evidence of significant ifi impact to the interior region of the samples. Working closely with NETL labs to interpret results. Will provide valuable information toward understanding the risk management issues related to potential wellbore leakage. Pure CO 2 forms a carbonate "sheath." H 2 S CO 2 forms ettringite and iron sulfides. Well bore cement: 2200 psi, 50 C, 28 days

23 Current Activities New laboratory work to determine: Capillary threshold pressure of cap rock. Threshold intrusion pressures for acid gas-rich brine. Mechanical changes before and after acid gas exposure. This work will allow the field ed operator to determine maximum operating pressures in this regime. Work has been funded by Natural Resources Canada and Apache Canada, Ltd. Additional funding was received from the U.S. Department of Energy to conduct additional laboratory- and field-based activities at Zama.

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25 Contact Information Energy & Environmental Research Center University of North Dakota 15 North 23rd Street, Stop 9018 Grand Forks, North Dakota World Wide Web: Telephone No. (701) Fax No. (701) John Harju Associate Director for Research Ed Steadman PCOR Partnership Program Manager Senior Research Advisor