The Intersection of Environment and EOR: How Carbon Capture is Changing Tertiary Recovery
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Increasing interest by governments worldwide on reducing CO2 released into the atmosphere form a nexus of of opportunity with enhanced oil recovery which could benefit mature oil fields in nearly every country. Overall approximately two-thirds of original oil in place (OOIP) in mature conventional oil fields remains after primary or primary/secondary recovery efforts have taken place. CO2 enhanced oil recovery (CO2 EOR) has an excellent record of revitalizing these mature plays and can dramatically increase ultimate recovery. Since the first CO2 EOR project was initiated in 1972, more than 154 additional projects have been put into operation around the world and about two-thirds are located in the Permian basin and Gulf coast regions of the United States. While these regions have favorable geologic and reservoir conditions for CO2 EOR, they are also located near large natural sources of CO2. In recent years an increasing number of projects have been developed in areas without natural supplies, and have instead utilized captured CO2 from a variety of anthropogenic sources including gas processing plants, ethanol plants, cement plants, and fertilizer plants. Today approximately 36% of active CO2 EOR projects utilize gas that would otherwise be vented to the atmosphere. Interest world-wide has increased, including projects in Canada, Brazil, Norway, Turkey, Trinidad, and more recently, and perhaps most significantly, in Saudi Arabia and Qatar. About 80% of all energy used in the world comes from fossil fuels, and many industrial and manufacturing processes generate CO2 that can be captured and used for EOR. In this 30 minute presentation a brief history of CO2 EOR is provided, implications for utilizing captured carbon are discussed, and a demonstration project is introduced with an overview of characterization, modeling, simulation, and monitoring actvities taking place during injection of more than a million metric tons (~19 Bcf) of anthropogenic CO2 into a mature waterflood. Longer versions of the presentation can be requested and can cover details of geologic and seimic characterization, simulation studies, time-lapse monitoring, tracer studies, or other CO2 monitoring technologies.
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The Intersection of Environment and EOR: How Carbon Capture is Changing Tertiary Recovery
- 1. Society of Petroleum Engineers Distinguished Lecturer Program www.spe.org/dl 1 Dr. Robert S. Balch Petroleum Recovery Research Center New Mexico Tech The Intersection of Environment and EOR: How Carbon Capture is Changing Tertiary Recovery
- 2. 2 ACKNOWLEDGMENTS Funding for this project is provided by the U.S. Department of Energy's (DOE) National Energy Technology Laboratory (NETL) through the Southwest Regional Partnership on Carbon Sequestration (SWP) under Award No. DE- FC26-05NT42591. Additional support was provided by Chaparral Energy, LLC and Schlumberger Carbon Services. The lecturer gratefully acknowledges the contributions of more than 50 SWP scientists and engineers, working at New Mexico Tech, the University of Utah, the University of Missouri, Los Alamos National Laboratory, Pacific Northwest National Laboratory, and Sandia National Laboratories.
- 3. OUTLINE 1. A brief history of CO2 Enhanced Oil Recovery (EOR) 2. Carbon Capture and Storage (CCS) vs utilization (CCUS) 3. Case Studies of Carbon capture and utilization for EOR 4. Southwest Partnership demonstration at Farnsworth unit a) Introduction to Farnsworth b) Characterization of the reservoir and seals c) Models and Simulation d) Monitoring, Verification and Accounting (carbon storage security) 3
- 4. CO2 ENHANCED OIL RECOVERY • CO2 acts as a solvent at the right pressure and temperature conditions • Impact on production – typical response to a CO2 flood is equivalent to the response of a waterflood. • Extends life of fields: CO2 EOR can add an additional 30+ years after the end of a waterflood. • Limited by • Natural supply • Limited by infrastructure • Minimum miscibility pressure https://www.netl.doe.gov/file%20library/research/oil-gas/small_CO2_EOR_P Criteria for Screening Reservoirs for CO2 EOR Temperature, oF < 250, not critical Pressure, PSIA >1200, varies Permeability, mD >1 Oil Gravity, oAPI > 27 Viscosity, cp < 10 Residual Oil Saturation, % >25 Depth, ft <9800 and >2000 4
- 5. CO2 EOR PROJECTS • First CO2 EOR project started in 1972 at SACROC unit in Texas • Since then 154 additional projects have been emplaced, initially in the Permian basin and Gulf coast areas of the United States • Availability of Natural CO2 • Carbon capture has Plotted using data tabulated in Oil and Gas Journal April, 2014 5
- 6. CARBON CAPTURE, (UTILIZATION) AND STORAGE • Concerns over CO2 in the atmosphere is prompting governments to investigate CCS/CCUS • For large point sources (coal plants) looking at saline aquifers • For smaller point sources use for EOR is growing due to: • Proximity to mature fields • Purity of CO2 Permian Basin 50.3% Gulf Coast 12.9% Other USA 25.8% Other World 11% Plotted using data tabulated in Oil and Gas Journal April, 20 6
- 9. IMPLICATIONS OF ANTHROPOGENIC CO2 FOR EOR • Governmental Impacts • Tax credits/carbon credits • Faster path to sequestration due to profit potential • Impacts for Producing Companies: • Local supply: Sources near every oil field • Increased recovery: ~2/3 of all oil world-wide is stranded • Mitigate regulatory impacts • Market advantages • Public perception 9
- 10. USA CASE STUDIES FOR CCS • US Department of Energy Regional Carbon Sequestration Partnerships • Seven regional partnerships • Each demonstrating injection of at least 1,000,000 metric tons of CO2 • Four projects are demonstrating storage in conjunction with EORModified from http://energy.gov/fe/science-innovation/carbon-capture-and-storage- 10
- 11. FARNSWORTH UNIT • Farnsworth field was discovered in 1955. • Over 100 wells were completed by the year 1960. • Water injection for secondary recovery started in 1964. 11 Property Value Initial water saturation 31.4% Initial reservoir pressure 2218 PSIA (Pbubble 2059) API 36.7o Original Oil in Place (OOIP) 120 MMSTB (60 MMSTB west- side) Drive Mechanism Solution Gas
- 12. S O U T H W E S T C A R B O NS O U T H W E S T C A R B O N P A R T N E R S H I PP A R T N E R S H I P R E G I O NR E G I O N www.agrium.com http://www.conestogaenergy.com/arkalon- Anthropogenic Supply: 500-600,000 Metric tons CO2/year supply Legend Utiilization & Storage Carbon Capture Transportation Oil Fields Other CO2 Sources 0.1 to 0.7 MT/yr 0.7 to 1.8 MT/yr 1.8 to 4 MT/yr 4 to 10 MT/yr 10 to 20 MT/yr 12
- 13. ACTIVE AND CURRENTLY PLANNED CO2 PATTER Detailed in SPE 180408 2010-11 2013-14 2017? 2012-13 1.0 mile2016 2016
- 14. CHARACTERIZATION • Goals are to better understand geology of storage system • Deliver fine scale facies based models including hydraulic flow Ron Blakey - http://jan.ucc.nau.edu/rcb7/300moll.jpg 14
- 15. CONCEPTUAL GEOLOGIC MODEL Incised Valley Depositional System 15 Puckette et al., 20
- 16. B B ’ CONCEPTUAL GEOLOGIC MODEL • Cross-section is hung on the overlying Morrow shale • Ancient river bed is easily discerned B’B 16
- 17. 3D VSP Well Monitoring Well Cross-Well Tomography 3D VSP Area 1.0 miles Farnsworth Unit Seismic Activities 17 Detailed in SPE 180408
- 18. SEISMIC INTERPRETATION • Multiple scales of seismic data allow for leveraging of information • Core and log-scale data at the well-bore can be interpreted out to increasingly lower resolution data sources 18
- 19. SEISMIC INTERPRETATION 19 • Interpreted 16 horizons down to the target Morrow reservoir (purple) • Seismic horizons picks allowed a well-tie between time domain seismic and depth- domain well logs • Allows for direct relationships between log/core and seismic featuresHutton, 2015
- 20. LARGE SCALE FAULTS AND CHANNELS Nine faults and fault-like features were interpreted using a variety of seismic attributes and mapping observed features in the 3D seismic volume. 20 Hutton, Masters thesis, Geophysics
- 21. PETROPHYSICAL MODELING Core porosity vs log permeability was computed for 51 cored wells • Over 750 feet of core were collected in three SWP drilled characterization wells • Extensive logs from near surface through the reservoir were collected • The data was inconclusive in R² = 0.1744 0.1 1.0 10.0 100.0 1000.0 0.0 5.0 10.0 15.0 20.0 25.0 LogPermeability Porosity core porosity 21
- 22. IMPROVED HYDRAULIC FLOW UNITS The Winland equation relates porosity to permeability using variables that impact hydraulic flow (Kolodzie, 1980): • log R35 = 0.732 + 0.588 log Kair – 0.864 log core • Hydraulic units were grouped into porosity/permeability categories based on similar pore throat sizes 22 R² = 0.696 R² = 0.7048 R² = 0.6671 R² = 0.7983 R² = 0.5897 R² = 0.593 R² = 0.7227 R² = 0.6966 0.1 1.0 10.0 100.0 1000.0 0.0 5.0 10.0 15.0 20.0 25.0 LogPermeability Porosity HU8 HU7 HU6 HU5 HU4 HU3 HU2 HU1 Detailed in SPE 180375
- 23. GEOLOGIC MODELS ARE USED FOR SIMULATION • SWP evaluates and updates fine-scale geologic models yearly • Goal is to integrate, and honor, seismic and well data • Includes fault planes picked from seismic 23
- 24. SIMULATION STUDIES • Reservoir production history matching through primary, secondary, and tertiary recovery. • Carbon dioxide interactions with reservoir minerals and fluids. • Predictions of future production and carbon dioxide storage in the reservoir. • Enhanced oil recovery and carbon dioxide storage with coupled geochemistry and geomechanics. • Reduced order models for risk assessment and 24
- 25. HISTORY MATCH • Primary: • 1956 – 1964 • 11.2 MMStb • 9.3% of OOIP • Secondary: • 1964 – 2010 • 25.6 MMSTB • 21.3% of OOIP • Tertiary CO2: • 2010-2016 • 2.6 MMSTB 25
- 26. FATE OF INJECTED CO2 • CO2 saturation within the Morrow formation • Injection period: November 2010 through July 2016 26 Detailed in SPE 179528
- 27. OPTIMIZATION OF WAG CYCLES • Water Alternating Gas (WAG) Cycles optimized for using proxy models • Predictions for 25 patterns in West Farnsworth with recycle • Goal is to co- optimize production 27 Detailed in SPE 180084 and SPE 180376
- 28. 28 OPTIMIZATION OF WAG CYCLES WITH PROXY MODELS (25 PATTERNS – WEST SIDE) Detailed in SPE 180084 and SPE 180376 Results Unit Base case Optimized CO2 Purchased BScf 58 58 CO2 Production Cumulative BScf 230 238 Recycle BScf 215 235 CO2 Injection Cumulative BScf 273 293 Total Storage* BScf 43 56 % Storage % 75 95 Total Oil Production MMstb 43.62 48.80 % of OOIP (60 MMSTB) % 72.70 81.40
- 29. MONITORING (MVA) • As a demonstration project a comprehensive monitoring strategy is in place. • Monitoring – understand CO2 plume movement over short and long time periods • Direct monitoring - tests repeat air and water samples for seeps, leaks, and well-bore failures • Seismic MVA - utilizes time lapse seismic data at a variety of scales to image the CO2 plume over time • Verification – assurance that CO2 stays in target reservoir, doesn’t make it back to atmosphere • Accounting – Accurately measure amount of stored carbon including storage mechanisms 29
- 30. Detecting CO2 at Surface: • Surface soil CO2 flux • Atmospheric CO2/CH4 eddy flux • Gas phase tracers Detecting CO2 and/or other fluid migration in Target/Non- Target Reservoirs: • Groundwater chemistry (USDWs) • Water/gas phase tracers Tracking CO2 Migration and Fate: • In situ pressure & temperature • 2D/3D seismic reflection surveys • VSP and Cross-well seismic DIRECT MONITORING STRATEGY 30
- 31. MVA OVERVIEW 31
- 32. 32 ACCOUNTING - CO2 AND INCREMENTAL PRODUCTION • 461,000 tonnes stored since October 2013 • 901,556 tonnes stored since November 2010 • Average monthly oil rate increased from ~3,500 to ~65,000 BBL’s in first 4 years of CO2 Flood • Initial production response within 6 months 0 10 20 30 40 50 60 70 80 0 10 20 30 40 50 60 70 80 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 ThousandsMetrictonnesCO2 ThousandsSTBOil Monthly Oil Production and CO2 Injection, 2010-2016 Oil Produced (bbls) CO2 Injected (tonnes) Monthly accounting since October of 2013
- 33. 33 CONCLUSIONS • Demand for CO2 for EOR projects has outpaced natural supplies • Carbon Capture can mitigate CO2 emissions using geologic storage and is responsive to government interests in reducing carbon emissions, worldwide • Costs for using anthropogenic CO2 for EOR purposes is mitigated by existing oilfield infrastructure and increased oil production • Case studies can provide “best practices” and demonstrate viability of the use of local anthropogenic sources • The Farnsworth project highlights enhanced recovery with
- 34. Society of Petroleum Engineers Distinguished Lecturer Program www.spe.org/dl 34 Your Feedback is Important Enter your section in the DL Evaluation Contest by completing the evaluation form for this presentation Visit SPE.org/dl
Hinweis der Redaktion
- By the end of my talk I hope to convince you that CO2 EOR and carbon sequestration creates significant opportunities for both Industry and the environment.
- CO2 EOR can revitalize mature fields, a typical tertiary response is on the order of the secondary recovery efforts both in duration and volumes. In the past projects have been limited by chemistry, CO2 supply, and infrastructure.
- Since the first CO2 project in 1972, at least 154 more have been emplaced world-wide. Projects initially depended on natural CO2 and demand has outpaced supply allowing the use of capture technology to augment natural supplies. Over 1BCF of natural CO2 is injected into the Permian basin every day, and this could be replaced with anthropogenic CO2. Anthropogenic CO2 can also add to the total available CO2 for EOR projects. Including in 2015, a pilot project by Saudi Aramco with CO2 being captured at the Hawiyah gas recovery plant and piped 85 km to the ‘Uthmaniyah field. This plot shows the number of CO2 EOR projects over time since 1972. Currently approximately 37% of projects use captured CO2. This is poised to change, with the Paris accord, a dozen countries are looking at offshore storage of carbon, EOR plays a key role in this due to in place infrastructure and economic motive.
- Conventional coal plant waste streams are expensive to processes into pure CO2, both in facilities cost and required energy, but there are other facilities that provide pure CO2 streams and only require dehydration and compression. These smaller sources, fertilizer, ethanol, gas processing, cement plants, etc can be more local to a potential project. The chart on this slide shows that about 63% of project are in the Permian basin or Gulf coast and utilize predominantly natural CO2 sources. The remaining 37% use captured CO2.
- The US has dominated CO2 EOR with large natural sources proximal to favorable geology. However, CO2 sources are widely distributed! Wherever there are people there are sources of CO2. Power plants, cement plants, gas processing, fertilizer plants, ethanol generation, etc. Over 80% of power used by humans is based on fossil fuels, and many chemical and industrial processes generate CO2 as a waste stream.
- This map shows anthropogenic sources of CO2 and potential oilfield sinks. Existing pipelines from natural sources are in close proximity to large man-made sources. Mature basins in the region are all within a few 10’s of miles of existing sources. A large gas separation plant in Wyoming provide CO2 for 16 CO2 EOR projects in Colorado, Wyoming, and Montana, and highlights the potential to generate CO2 in proximity to mature oil development.
- Regulations may impact the affordability of projects. The Arkalon Ethanol Plant in Liberal Kansas supplies 200,000 metric tonnes of CO2 per year to 3 EOR projects. Because their CO2 is “sequestered” they can sell their ethanol in California, where there are laws requiring “green energy sources”. Companies can benefit from proximity of CO2 sources to mature production, increased production and extended field life, and may potentially benefit from carbon credits, and since CO2 EOR inherently stores CO2, they can benefit from improved public perception about their projects.
- Black drops show the approximate location of large scale CO2 EOR / sequestration demonstration projects in the united states. The Southwest regional partnership on carbon sequestration, signified by SWP on this map is a consortium of three universities, three national laboratories, service companies, and operating partners including Chaparral Energy who operates eight CO2 EOR projects utilizing man-made CO2. Farnsworth Unit is the location of the SWP’s large scale demonstration project.
- Chaparral Energy acquired FWU, and started to convert the field to CO2 EOR in 2010 No natural CO2 available. Existing infrastructure in place from waterflood was updated
- Farnsworth unit is a Carbon Capture, Utilization and Storage project. Co2 is sourced from two anthropogenic sources, the Arkalon Ethanol Plant in Liberal Kansas, and the Agrium Fertilizer plant in Borger Texas. Over 100 miles of pipeline connect the two sources to 3 currently active projects and can be extended to several more fields in the area. Grey shaded portions of the map show oil fields in the vicinity of these two point sources of CO2. Chaparral can vary delivery to fields to maintain operational flexibility. Chaparral built or partnered in compression and dehydration facilities at each site. Carbon cost is low, ~$0.60 per mcf, less than paying for natural CO2, even if it were regionally available.
- This map shows current and near future pattern conversion to CO2 injection. Development uses invert 5 spot patterns with a central CO2 injector surrounded by 4 producers on approximately a 40 acre spacing. Farnsworth development is being monitored by the SWP and the sequential addition of additional patterns allows for testing and retesting of technologies to directly and indirectly observe CO2 in the reservoir. At present only the western half is being developed for CO2 EOR, though eventually as CAPex allows the eastern side will also be developed.
- Pennsylvanian continental assemblage at approximately 300 million years ago, the small yellow rectangle shows the location of Farnsworth during deposition of the Morrow. Waxing and waning of ice sheets in southern hemisphere caused repeat global sea level oscillations.
- The SWP project examined legacy wells, drilled three new wells specifically for characterization with extensive logs nearly to the surface, and a total of 750 feet of core in the reservoir, secondary reservoir, and primary and secondary seals. Our interpretation is that deposition occurred in an incised valley. During a high stand, mudstones and marine shales were deposited. During low stands rivers carved out or “incised” valleys into the mudstones and deposited fluvial sandstones. Later high stands deposited shales over the top of the sandstones.
- Interpreted geologic cross-sections hung on the top of the Morrow shale support the incised valley theory as sands thicken across the center of the reservoir and thin at the edges in all north south cross-sections
- Seismic data has been an integral part of the characterization program and includes a baseline 42 mi2 3D survey over the entire field, three baseline 3d VSPS centered on injection wells, four baseline cross-well tomography segments between injector/producer pairs. In addition, a dedicated monitoring well has a 16 level 3 component passive seismic monitoring array installed within it.
- From right to left, Gamma Ray log in the 13-10A injection well, cross-well tomography, 3D VSP, and surface seismic data
- Faults 1, & 2 Form an anticlinal structure; Fault 3 is an oblique slip fault; Faults 3, 4, & 5 create a trough or graben structure in the NE corner of the field; and Fault 6 terminates below the Morrow
- This is not unexpected. East and west portions of the field appear to have different permeability's due to changes in diagenesis. In addition, up to 8 distinct sub-facies have been identified in log studies for the Morrow B.
- R35 refers to the pore throat aperture radius when core samples are 35% saturated during a mercury porisometry experiment. It is believed that above this radius pore networks become interconnected and can form continuous flow paths.
- Average permeability at the Morrow B interval with interpreted faults. Faults have offsets in the reservoir and can impact fluid flow, and storage security. Typical models have millions of gridblocks and are up-scaled when simulating flow in the morrowB
- Simulation is an integral part of studying CO2 injection, and is essential for making predictions of storage security, studying storage mechanisms, and understanding material balances.
- Each year a new simulation model is created using increasingly detailed geologic models as a basis. The first step each year is to accurately history match Primary, secondary , and tertiary processes including Oil, water, and gas production.
- Predictions can also be made of CO2 saturation and sweep efficiency. This figure shows predicted CO2 saturation in the Morrow formation through July of 2016. We also study geomechanics and rock fluid interactions with these models and results can be used to estimate the best time for repeat seismic surveys to directly image co2 in the reservoir by running synthetic seismic data through different fluid states of the simulation models.
- The Purple line is purchased CO2, this is the CO2 that a government entity would be interested in for storage statistics. The Black line represents the CO2 available for recycle at any given time. The red line is a planned wag schedule. There is potential for waste if available CO2 exceeds injection needs as patterns are filled, and CO2 that ends up being flared rather than recycled is lost to storage, and lost to utilization. The operators WAG schedule is predicted to stores ~75% of the Purchased CO2 and produces about 72% of the OOIP
- Optimization of WAG cycles can increase CO2 storage by 20%, cumulative oil by 5.2 million barrels and total recovery by nearly 9%! An interesting outcome from simulation studies was that optimal storage also provides for optimal incremental recovery.
- How are we going to do this? We have a battery of surface and subsurface methods at our disposal to track the fate of CO2 and look for any potential leakage.
- Viewing the MVA methods on a map, our efforts are generally concentrated around the primary project CO2 injection well (13-10A) and monitoring well (13-10). CO2 Soil Flux data for sites around 13-10A well, have shown that no CO2 emissions have been detected. We also monitor the water quality in the overlying Ogallalla Aquifer, studying more than a dozen characteristics. Again, no changes during the course of our monitoring program.
- The figure on the left shows monthly accounting since SWP began monitoring the site in 2013, with stacked layers representing purchased CO2 (green), net stored CO2 (blue), recycled gas (yellow), and Co2 lost to flaring (red). The figure on the right shows oil production and CO2 injection rates with the field going from about 3500 BOPM to over 65,000 BOPM in only 4 years. Oil rate growth has leveled off as new patterns are not being added at this time due to low oil price.
- Circle back – Mature fields around the world are the best site for storing the carbon promised by world leaders and formalized in the Paris accord – about 1000 Farnsworth fields needed to store the 4-5 Billion tonnes by 2040. This is perhaps the only way to achieve this goal in that time period due to existing transportation infrastructure, and available point source CO2 that can effectively be captured. Public perception, regulatory policy and economics of CO2 EOR are very likely to dramatically improve in coming years.