Program

Introduction

Carbon-conscious companies are looking to achieve carbon neutral or negative status by capturing and sequestering their CO2 output through methods known as Carbon Capture and Storage (CCS). The goal is to capture CO2 outputs from various sources and store the CO2 in deep saline reservoirs. The industrial sources of CO2 range from power plants, landfills, and hydrocarbon operations to steel, cement, ammonia, and ethanol plants. Before any CO2 is injected into the ground operators must document compliance of federal, state, and local regulations to obtain permitting. A subsurface characterization study is one of the main components of regulatory permitting. A local geologic study within the CO2 source area identifies prospective injection sites based on favorable subsurface storage conditions and better informs permitting strategy, surface facility planning, and mitigates the risk of CO2 leakage or permit denial.

Demonstrating geological storage permanence is an iterative process of data gathering, integration, and dynamic flow simulation. In order to scale CCS technologies and ensure efficiency, a comprehensive development program is needed that includes everything from pre-injection permitting, subsurface modelling, and infrastructure build to advanced site characterization and plume monitoring. Schlumberger has over a decade of multi-discipline carbon sequestration experience and has developed geologic criteria and monitoring programs using Petrel* and Eclipse* to ensure successful permanence of CO2 storage at commercial scale for the purpose of facilitating low carbon energy sources and reducing global carbon emissions.

The study area for site identification and ranking is in the Los Angeles Basin, California (Figure 1). The purpose of this study is to demonstrate site identification and ranking workflows and subsequent dynamic simulation. This area is considered infeasible for geologic storage due to the environmental, societal, and governance concerns associated with the large residential population density and the proximity of the San Andreas fault system. In commercial evaluations local regulations concerning environmentally sensitive areas and highly populated residential areas would dictate proposed location criteria but have not been considered here for demonstrational purposes.

Background Geology

The Los Angeles Basin is the largest of the California Peninsular Range basins with an area of 1,500 square miles and a sedimentary thickness of roughly 27,000 ft. The basin formed in three major phases: an extensional phase from the mid-Miocene through the early Pliocene associated with the opening of the Gulf of California, a subsidence and deposition phase from the Late Miocene through the early Pleistocene, and a post-Pleistocene compressional phase of extensive faulting and folding.

The Los Angeles Basin lies in a tectonically active area. Three major fault zones- the Palos Verde, the Newport-Inglewood, and the Whitier- divide the basin into blocks. The middle axial trough block between the Newport-Inglewood and Whitier zones contains the area of interest for this study. The principal horizontal stress direction of these large fault systems is N-NW; therefore, borehole breakouts tend to favour approximately E-W (Chavez, 2015). The basin depocenter in the Central Block is less faulted and experiences less seismicity. Four major sedimentary formations are defined in the basin: the Topanga, Puente, Repetto, and Pico from deepest to shallowest of which the middle two are primary hydrocarbon reservoirs. The Puente Formation consists of about 8,000 ft of bathyal silt and sandstones and is characterized by three distinct zones of varying grain size. The Repetto Formation is deepest in the central block, reaching thicknesses of over 10,000 ft, and consists of southward prograding lower submarine fan deposits (California Geological Survey, 2006).

Methodology

In the first stages of a CCS project, the operator must understand if there are suitable subsurface storage formations that will accept and contain the injected CO2. Geologic storage systems must demonstrate that saline (>10,000 ppm) formations exist at depths below the minimum super critical CO2 depth (- 2,500 ft) and exhibit favorable injectivity properties (porosity, permeability, salinity, temperature and pressure) (EPA, 2018). More importantly, regional low-permeability seals must exist and demonstrate that injected CO2 will be permanently isolated in the injection reservoir. In addition to injectivity and seal characterization, it must be proven that no potential pathways exist from the CO2 storage reservoir to the surface including leaky faults and improperly abandoned wells. Such subsurface features can act as conduits for upwards CO2 movement, resulting in contamination of Underground Sources of Drinking Water (USDWs). Regional dip affects plume migration and must be considered when selecting locations.

To identify prospective storage site locations subsurface data was integrated into Petrel* subsurface modelling software. Within the study area there are 3066 legacy wells (IHS, 2020). Interpreted well tops and published maps provided input for the structural model (CalGEMS, 2020) (Wright, 1991) (California Geological Survey, 2006). Raster log images were used to interpret 21 lithofacies logs for sand, sand-shale, and shale layers across the study area (IHS, 2020). Base of freshwater was mapped and is variable across the study area ranging from 500 – 3,500 ft (USGS, 2018). Lithofacies interpretation provided the input for full field modelling using Sequential Indicator Simulation (SIS) facies modelling algorithm in Petrel*. Variogram parameters were selected from estimated sediment transport direction and calculated facies variance. Due to the lack of digital well data, constant porosity and permeability values were estimated from field data (DOGGR, 1992). The model was used in conjunction with aforementioned feasibility criteria to identify five prospective injection locations labelled A-E (Figure 1).

After identifying proposed locations, a ranking system was applied per location to understand feasibility of the geologic storage system. Evaluation criteria for this study are shown in Figure 2.a. and include fault leakage and reactivation, distance to subsurface operations, and reservoir storage potential. Reservoir storage potential is calculated based on simulated sand thickness with constant porosity using the Department of Energy’s (DOE) CO2 storage for saline reservoirs (DOE, 2015). CO2 density was calculated using reservoir temperature and pressure (DOGGR, 1992) (Span & Wagner, 1996). Each area is ranked relative to each other on an unweighted scale of 1-5, 1 being most favorable and 5 being least favorable. The result of this preliminary analysis is a quantitative understanding of subsurface risks by identifying locations that have the lowest score, i.e., are most favorable for geologic storage.

A dynamic model was constructed over the most favorable injection location to simulate saline storage using Eclipse* E300 compositional reservoir simulator. A subset of the geomodel covering an 8.1 mile x 9.1 mile area around the most favorable injection location was used as input for the dynamic model. Property upscaling was applied to the new grid with a cell size of 330 ft x 330 ft to reduce the number of cells and improve computational efficiency. The reservoir was assumed to be 100% brine saturated with an initial formation salinity of 15,000 ppm, based on the data from nearby oil and gas fields (DOGGR, 1992). For dynamic modelling, the injected fluid is assumed to be pure CO2. Infinite-acting conditions were assumed at the lateral boundaries to serve as pressure sinks/sources during and after the injection. Continuous injection with a rate of 1 million tonnes/year was applied for 20 years. A 50- year post-injection period was added to understand plume stabilization and inform monitoring strategies.

Conclusions

The Repetto formation was delineated as the best reservoir candidate due to both sand thickness and overlying seal presence. Silt and mudstone layers in the overlying Pico Formation provide regional seals up to around 330 ft thick. Site evaluation criteria and ranking show that proposed injection site B is the most feasible for long term geologic storage (Figure 2.a.). Ranking shows proposed injection sites D, E, and C are the least favourable targets due to their proximity to active and legacy wells. Based on historical earthquake data, proposed injection sites D and E are more susceptible to future earthquake events. Dynamic modelling was conducted over proposed injection site B. Figure 2.b. and Figure 2.c. show results of dynamic modelling and estimated plume geometry after 20 years injection and 50 years post-injection. Although this site would never be recommended for commercial storage, the same prospect assessment, subsurface characterization, and dynamic modelling workflow showcased here can be implemented for the full spectrum of carbon storage cases using Schlumberger’s Petrel* and Eclipse* software.

References 

• CalGEMS. [2020]. Well Finder. Retrieved from https://maps.conservation.ca.gov/doggr/wellfinder/#/ 
• California Geological Survey. [2006]. An overview of Geologic Carbon Sequestration Potential in California. 
• Chavez, J. A. [2015, May]. Principal Stress Analysis of Rock Fracture Data from the Long Beach Oil Field, Los Angeles Basin, California. Long Beach, California, USA. 
• DOE. [2015]. Carbon Atlas - Fifth Edition. NETL, Department of Energy. Retrieved from https://www.netl.doe.gov/coal/carbon-storage/strategic-program-support/natcarb-atlas 
• DOGGR. [1992]. CALIFORNIA OIL & GAS FIELDS Volumes I, II, & III . 
• EPA. [2018]. Geologic Sequestration of Carbon Dioxide Underground Injection Control [UIC] Program Class VI Implementation Manual for UIC Program Directors. Retrieved from https://www.epa.gov/sites/production/files/2018- 01/documents/implementation_manual_508_010318.pdf 
• IHS. [2020]. Retrieved from https://my.ihs.com/energy 
• Span, & Wagner. [1996]. PSU Earth and Mineral Sciences Energy Institute CO2 Calculator. Retrieved from http://www.energy.psu.edu/tools/CO2-EOS/ USGS. [2018]. Data analyzed for the preliminary prioritization of California oil and gas fields for regional groundwater monitoring. USGS. Retrieved from https://www.sciencebase.gov/catalog/item/57a50b81e4b0ebae89b6d877 
• USGS. [2019]. Retrieved from https://mrdata.usgs.gov/geology/state/state.php?state=CA 
• USGS. [2019]. Earthquake Hazards Program. Retrieved from https://earthquake.usgs.gov/ 
• Wright. [1991]. Active Margin Basins Chapter 3 Structural Gelogy and Tectonic Evolution of the Los Angeles Basin. American Association of Petroleum Geologists.

Eugene Holubnyak¹, Tiraz Birdie², Jennifer Hollenbach¹
¹Kansas Geological Survey, University of Kansas, Lawrence, KS
²TBirdie Consulting, Lawrence, KS

The U.S. Environmental Protection Agency Underground Injection Control (EPA UIC) Class VI well permit is the latest in a series of underground injection permits administered by the EPA. It was developed specifically to ensure safe and permanent storage of (buoyant) carbon-dioxide. The permit requirements are arguably the most stringent of all the previous five permit classes, with the result being that to date, the only Class VI permits have been issued for Decatur, IL.

The Arbuckle Group carbonate saline aquifer is Oklahoma and Kansas has been utilized extensively for waste disposal purposes since 1935. UIC Class I and Class II wells target Arbuckle Group as the primary disposal zone in the region. However, recent developments of Mississippian Lime Play and other industrial activities are exerting unprecedented pressure on Arbuckle saline aquifer use as an industrial waste disposal reservoir. There is some evidence from independent pressure monitoring gages, UIC Class I well monitoring records, and other sources of regional fluid level and pore pressure increases in Arbuckle reservoir in Kansas and Oklahoma. Competing interests of various industrial groups that include oil and gas, chemical complex, and potentially CO2 geological storage could collide in the future if regulatory framework is not outlined.

This presentation will be focused on challenges that region with active induced seismicity presented to KGS-Berexco team for UIC Class VI permit application filled for the Wellington CO2 saline aquifer storage pilot in southcentral Kansas. Our team came up with several solutions on how to address EPAs concerns including seismic monitoring and response plan, geological structural modeling and assessment, and pressure monitoring routines. These plans and routines and plans are presented here.

David E. Riestenberg¹, George J. Koperna¹, Jack Pashin², and Richard Esposito³
¹Advanced Resources International, Inc.
²Oklahoma State University
³Southern Company

This paper summarizes the ongoing evaluation of the Project ECO₂S site, a 12,000-hectare CO₂ storage complex adjacent to Mississippi Power Company’s (MPC) Plant Ratcliffe facility in Kemper County, Mississippi, USA. Considerable geological characterization of the Kemper storage site has taken place since 2016 and includes well drilling, coring, petrology, petrography, petrophysics, and sequence stratigraphy studies. The logs and core data acquired from three 2017 characterization wells and vintage exploratory wells were utilized to populate property (porosity and permeability) and structural models of the modelled area. Reservoir units are Mesozoic in age and are comprised of poorly consolidated sandstone and mudrock, including the Paluxy Formation, the Washita-Fredericksburg interval, and the Lower Tuscaloosa Group Massive sand, in ascending order. These Cretaceous clastic units occur from about 1,720 meters to 1,010 meters below ground surface, with over 350 meters of net sand. The CO₂ storage reservoirs have exceptional quality, with mean reservoir porosity of 28.5% and mean reservoir permeability of 3.5 Darcy. Net sandstone to gross reservoir thicknesses ratios within the reservoir intervals range from 0.7 to greater than 0.9 and are laterally extensive beyond the ECO₂S site, suggesting an enormous storage resource capable of storing hundreds of megatons of CO₂ and serving as a regional storage hub. Structural dip is moderate at 10 to 12 meters per kilometer. Overlying caprocks occur in the Marine Tuscaloosa shale, Selma Group and Porters Creek Clay, in ascending order. Caprock tests suggest that the Storage Complex seals are ductile and have very low (nanodarcy) permeability.

The Project ECO₂S site appears capable of storing CO₂ from three large volume Southern Company operated fossil fuel power sources, which together emit 22.5 million metric tons per year, or 675 million metric tons over 30 years. In 2020-2021 three additional characterization wells will be drilled and seismic profiles of the storage complex will be acquired. Project ECO₂S is part of the CarbonSAFE Program and is financially supported by the USDOE-NETL and Mississippi Power Company. The project is managed by the Southern States Energy Board. Technical Support is provided by Southern Company Research and Development.

Regional CO₂ Static Capacity Estimate, Offshore Saline Aquifers, Texas State Waters, U.S.A.

David L. Carr1, Kerstan J. Wallace2, Andrew J. Nicholson3, and Changbing Yang4

Abstract

Using a large and robust subsurface data set, we estimated the prospective storage resources of Miocene sandstone-bearing saline aquifers in coastal Texas and the immediately adjacent offshore Texas State Waters (OTSW). The OTSW, the 16-km-wide (10 mi) swath of Gulf of Mexico waters lying immediately seaward of the 590 km long (367 mi) Texas shoreline, comprises 9,875 km2 (3,813 mi2). The estimated P50 net capacity of the Miocene interval in the OTSW is 30.1 gigatonnes (Gt). Approximate depths to the top of the Miocene interval lie at favorable drilling depths of 1,006 m (3,300 ft) and typically contain a 300 to 600 m (1,000 to 2,000 ft) thickness of stacked sandstone reservoir intervals.

Our offshore Texas Miocene CO2 capacity estimate is noticeably higher than many estimates from other states and countries. We think this higher estimate is due to the unusually large pore volumes offered by the thick, high net-to-gross, and high-porosity Miocene sandstone reservoirs of the northern Gulf of Mexico Basin. The reservoirs are geologically young and typically only mildly diagenetically altered as compared with those of many areas of the world, e.g., Europe, Australia, or South Africa.

Coastal Texas is particularly well positioned to capitalize on the Miocene geological CO2 sequestration opportunity. Multiple CO2 point sources either immediately overlie (onshore), or they are relatively close to, adjacent offshore storage reservoirs. This proximity, as well as the existing offshore pipeline infrastructure, facilitates use of offshore reservoirs and may potentially reduce transportation costs. Numerous depleted offshore Miocene oil and gas fields may be available for initial storage and/or enhanced recovery targets. More than 60 years of offshore oil and gas exploration and production in the region have generated robust data sets, facilities infrastructure, geological and engineering knowledge, and general cultural acceptance of offshore subsea and subsurface operations. In addition, the environmental risks of sequestration in OTSW reservoirs are low, given the lack of potable groundwater there. Finally, single-landowner status (State of Texas) allows for simpler land rights and liabilities assessment when compared with those of most onshore U.S. sites.

• 1Bureau of Economic Geology, The University of Texas at Austin
• 2Encana, Corp., Denver, Colorado
• 3Anadarko Petroleum Corporation, Houston, Texas
• 4Edwards Aquifer Authority, San Antonio, Texas

Richie G. Ness¹, David E. Riestenberg¹, George J. Koperna1, Steven M. Carpenter²
¹Advanced Resources International, Inc.
²Enhanced Oil Recovery Institute

The Salt Creek oilfield, located along the western periphery of the Powder River Basin in Wyoming, is the largest conventional oilfield in the Rockies, with 1,680 MMbbl of original oil in place. The field has been undergoing CO₂-Enhanced Oil Recovery (EOR) operations since 2003. The structure is an asymmetrical anticline with four-way closure and is bounded by an east-dipping backthrust immediately west of the field. Salt Creek produces from eleven Mesozoic intervals with the Cretaceous Frontier formation serving as one of the principal oil-producing units. The Wall Creek 1 interval of the upper Frontier produces oil along the structural crest of Salt Creek, within the main historical development area, and is the target of a limited CO₂-EOR program down dip of the crest where it is deep enough. Down-dip of the main reservoir, Wall Creek 1 production tests indicate a potentially extensive Residual Oil Zone (ROZ). More recent secondary production and tertiary EOR tests have indicated that the WC1 interval is amenable to CO₂-EOR and CO₂ storage along the east flank of the field.

Wall Creek 1 hydrocarbons are sourced from the Mowry Formation to the east in the Powder River Basin. Oil seeped into the Wall Creek 1 and migrated up-dip before charging the crest of the Salt Creek structure. Subsequent renewed shortening breached the overlying Niobrara caprock and facilitated vertical leakage of Wall Creek 1 oil from the reservoir. This may have aided in development of the extensive ROZ but alone does not resolve many of the peculiar Wall Creek 1 production trends east of the main reservoir or an apparent salt-water and an elevated temperature anomaly at the field crest.

Reported formation water resistivities indicate a saltwater anomaly at the field crest in the Wall Creek 1, with fresher water occurring down dip to the southeast. We hypothesize that thermohaline pore-fluid convection occurred along the backthrust at Salt Creek that intruded upon initially fresh formation waters. These heated brines migrated into the interval and swept the main oil-bearing reservoir, thereby increasing oil saturations along the east flank. Continued and late-phase oil migration also contributed to hydrocarbon accumulation in the Wall Creek 1 below the main reservoir. To test the CO₂-EOR potential of the Wall Creek 1 interval along the east flank of the field, geologic parameters such as net thickness, depth, and general reservoir quality were determined from well logs at several potential modeling locations. A field-scale grid of water saturation was constructed from ~900 wells at the field using the Indonesia water saturation equation. Geologic parameters were fed into a single-well CO₂-EOR simulation model to ascertain production performance at different locations across Salt Creek. The results indicate residual oil saturation ≤ 30% may exist in the Wall Creek 1 interval beyond the current production limits. Reservoir simulations suggest significant CO₂-EOR and associated storage potential of the Wall Creek 1 along the east flank and potentially beyond the Salt Creek field unit given the high reservoir quality of the interval.

Bjorn Paulsson, PhD, Paulsson, Inc. & Mark Kelley, MS, Battelle Memorial Institute

Continuous micro seismic monitoring of Carbon Capture Utilization and Storage projects (CCUS) using subsurface instruments will provide an improved understanding of both the CO2 flow and the behavior of the rock subjected to CO2 injection. The sound of fracturing and the sound of fluid flow are two distinct sounds that will help understand the dynamic of the subsurface fluid flow. Under a DOE funded project, Battelle Memorial Institute contracted with Paulsson, Inc. in 2016 to continuously monitor and characterize, over a period of one month, the injection of CO2, for the dual purpose of gaining and improved understanding of the CO2 subsurface fluid flow and enhanced oil recovery, into the Dover 33 reef located in Michigan. The oil field is operated by Core Energy LLC. Paulsson deployed an ultra-sensitive broad-band high-temperature and robust Fiber Optic Seismic Vector Sensor (FOSVS) to use in EOR operations including CCUS, UOG and EGS operations. Other applications include wastewater injection, and the monitoring of earthquake faults and Gas Storage Fields. The data recorded at the Dover 33 reef include about 100,000 micro seismic events at frequencies over 2,000 Hz with a Moment Magnitude of smaller than M-5. The data show a clear correlation between Pressure (P) and Micro-Seismic (MS). In particular, there are three rapid pressure increases that each generate an equivalent rapid increase in the rate of MS events removing any ambiguity that the injection pressure increase caused the increased rate of micro seismic events. The micro seismic events were record, mapped in 3D and categorized into several types of micro seismic events.

The latest status report of CO₂ enhanced oil recovery (CO₂ EOR) in the U.S. was published nearly seven years ago in the 2014 Oil & Gas Journal (OGJ) EOR Survey. Since then, petroleum industry operators and energy policy stakeholders have expressed demand for current information on U.S. CO₂ EOR project and production data. The objective of this report is to publish an updated survey of CO₂ EOR operations in the U.S. as of end-of-year 2019.

A complete list of CO₂ EOR projects in the U.S. was compiled, including project parameters, reservoir characteristics, and incremental oil production data. This information was obtained from state oil and gas commission publications and technical industry reports. Incremental oil production from CO₂ injection was calculated for each project using decline curve analysis. The survey data for each CO₂ EOR project was then sent to the respective operators for data verification.

Despite a challenging and competitive oil market the results of the survey showed incremental oil production from CO₂ EOR in the U.S. remained relatively unchanged from 2014 to 2019 with current production of 299,000 BOPD. The industry experienced a net increase of six new CO₂ EOR projects to 144. CO₂ supply for CO₂ EOR decreased from to 3 Bcfd, however the supply of anthropogenic CO₂ increased 30% to 1 Bcfd.

CO₂ EOR presents a significant opportunity for economically viable CO₂ storage in the U.S. Continued periodic updates to the U.S. CO₂ EOR survey are important to track the status and development of the industry.

Robert Dilmore¹, Diana H. Bacon², Christopher F. Brown², Megan M. Smith³, Joshua A. White³, Curtis M. Oldenburg⁴, Erika Gasperikova⁴, R. Burt Thomas⁵, Rajesh J. Pawar⁶, Dylan R. Harp⁶, Thomas L. Richard⁷
¹National Energy Technology Laboratory, ²Pacific Northwest National Laboratory, ³Lawrence Livermore National Laboratory, ⁴Lawrence Berkeley National Laboratory, ⁵National Energy Technology Laboratory/Leidos Research Support Team, ⁶Los Alamos National Laboratory, ⁷Penn State University

Enabling commercial-scale deployment of geologic carbon storage (GCS) requires stakeholders to have confidence that GCS sites will safely and effectively store large volumes of CO2 away from the atmosphere for hundreds of years, or more. The National Risk Assessment Partnership (NRAP) is a multi-year, multi-national laboratory collaborative research project sponsored by the U.S. Department of Energy, Office of Fossil Energy’s Carbon Storage Program, focused on developing and demonstrating methods and tools for quantitative assessment and management of subsurface environmental risks associated with GCS. NRAP has developed a computational toolset to support aspects of stakeholder decision-making related to evaluating long-term containment effectiveness, assessing risk of unwanted CO2 and brine migration, quantifying and managing potential induced seismicity risks, and designing effective and efficient monitoring networks to detect potential leakage. NRAP is also developing a set of conceptual workflows describing recommended methods for assessing subsurface environmental risks at GCS sites, building a catalog of use cases demonstrating tools and methods, and promoting the testing, use, and refinement of these products by the international carbon capture, utilization, and storage research, development, and deployment community.

Scott Frailey, PhD, P.E. – Reservoir Engineer, Illinois Geological Survey

Monitoring of CO2 at injection and monitoring wells validates the pre-injection analyses of net thickness, net reservoir, and net pay. Identification of net pay of CO2 storage wells, analogous to oil and gas operations, is necessary to select the perforated interval, estimate injection rate and pressure, and ultimately CO2 storage resources. Furthermore, net pay can be used to select pressure monitoring and fluid sampling intervals. For two Class VI CO2 injection wells in Decatur, Illinois, perforated intervals were chosen based on porosity logs and/or core porosity and permeability, and project specific objectives regarding permits and induced seismicity. In each case, spinner logs and pressure transient analyses indicated that only 20-30% of the perforated interval accepted brine injection (during testing) and CO2 injection during storage operations. This presentation summarizes the comparison of several methods for choosing net reservoir and pay cutoffs to CO2 monitoring results from spinner logs, pressure transient tests, and cased hole saturation logs.

Mark Kelley¹, Amber Conner¹, Jackie Gerst¹, Neeraj Gupta¹, Autumn Haagsma¹, Sanjay Mawalkar¹, Srikanta Mishra¹, Ashwin Pasumarti¹, Matthew Place¹, Samin Raziperchikolaee¹, Allen Modroo², Rick Pardini², Alain Bonneville³, Tom Bratton⁴, David Brock⁵, David Chace⁶, David Cole⁷, Thomas Coleman⁸, Liviu Grinde⁸, Ruiqing He⁹, Conrad Kolb¹⁰, Jeffery D. Macqueen¹¹, Jessica Morgan¹², Volker Oye¹³, Bjorn Paulsson¹⁰, Rich Van Dok¹⁴, Ismael Vera Rodriguez¹³
¹Battelle Memorial Institute, ²Core Energy LLC, ³Pacific Northwest National Laboratory, ⁴APEX Petroleum Engineering, ⁵Sage Rider, ⁶Baker Hughes, ⁷The Ohio State University, ⁸Silixa LLC., ⁹Paulsson Inc., ¹⁰Schlumberger, ¹¹Micro-g LaCoste, Inc., ¹²TRE Canada, ¹³NORSAR, ¹⁴Sterling Seismic & Reservoir Services

The Midwest Regional Carbon Sequestration Partnership (MRCSP) is one of seven regional partnerships established in October 2003 as part of the U.S. Department of Energy’s (DOE’s) Regional Carbon Sequestration Partnership (RCSP) program to assess the technical and economic viability and public acceptability of carbon sequestration in the U.S. The MRCSP Phase III project injected over 1 million metric tons of CO2 into a group of 10 Silurian-age (Niagaran) pinnacle reef reservoirs in Otsego County, Michigan that are operated by Core Energy, LLC. There are over 800 pinnacle reefs in northern Michigan, and collectively, these geologic features have enough capacity to store several hundred million MT of CO2. Moreover, most of the reefs are depleted oil- or gas-reservoirs having previously underwent primary production in the 1970s and 1980s; therefore, the reefs offer the opportunity to achieve CO2 storage through enhanced oil recovery (EOR) with CO2 (associated storage) and via injection alone sans production (sequestration).

A key objective of the MRCSP Phase III project is to evaluate the effectiveness of various monitoring technologies relevant for associated storage or sequestration. The MRCSP Phase III project conducted a comprehensive monitoring program that evaluated multiple technologies for their effectiveness for CO2 plume delineation, assessing geochemical interactions, well integrity, leak detection, induced seismicity, land deformation, and mass balance accounting in the group of 10 reefs operated by Core Energy.

• At all 10 reefs, a basic monitoring suite consisting of CO2 mass-balance accounting (i.e., injection rate, cumulative CO2 injected, production rate, cumulative CO2 produced) and reservoir pressure.
• At the Dover 33 reef, six additional monitoring techniques including vertical seismic profiling (VSP); geochemistry; borehole gravity (BHG); PNC logging; satellite (InSAR – Interferometric Synthetic Aperture Radar); and micro-seismicity monitoring.
• At the Bagley reef and the Charlton 19 reef, two additional monitoring techniques including geochemistry and PNC logging.
• At the Chester 16 reef, five additional monitoring techniques, including Distributed Acoustic Sensing (DAS) VSP monitoring; cross-well seismic; DTS; geochemistry; and PNC logging.

Thus, a total of 10 different technologies were tested, including two technologies (mass-balance accounting and pressure monitoring) in all 10 reefs, three technologies (pressure, PNC logging, geochemistry) in the four key study reefs, one technology (VSP) in two reefs; and four technologies (cross-well seismic, DST, microseismic, INSAR) each in a single reef. This presentation discusses the effectiveness of the various monitoring technologies in the context of the Silurian Niagaran reefs. The results are relevant to others planning or currently conducting CO2 sequestration of associated storage projects in similar carbonate reef reservoirs.

This presentation will discuss intended outcomes/objectives, deployment details, examples of monitoring results achieved, and an assessment of merits and limitations and lessons learned including possible measures for obtaining improved results. Some of the key findings of the study are listed below.

• Carbonate pinnacle reefs are a difficult environment for seismic technologies – all three seismic technologies had limited success delineating the distribution of CO2 in the reservoir; reasons for this were investigated and will be offered.
• Few technologies provided straightforward results. In this study, DTS provided clear evidence of CO2 breakthrough as corroborated by other monitoring data (PNC logging data); novel methods for visualizing DTS data to facilitate analysis and interpretation will be presented.
• Reservoir pressure monitoring is essential for understanding how the reservoir is responding to CO2 injection (e.g., tracking changes in injectivity index and stress, forecasting and monitoring storage capacity), and for building accurate reservoir models that can be used to interpret/confirm monitoring results.
• PNC logging and geochemistry monitoring can be difficult to interpret as stand-alone technologies but have the potential to provide valuable supporting evidence in conjunction with other monitoring methods; and, they can be done for relatively low cost (assuming wells already exist).
• INSAR monitoring can be valuable for addressing stakeholder concerns about surface deformation; however, due to uncertainty in results, should be augmented with a secondary method such as GPS monitoring and/or borehole tiltmeters.
• Monitoring injection induced seismicity is prudent in the pinnacle reefs, which are hydraulically-closed structures, especially during fill up if reservoir pressure is likely to exceed discovery pressure to maximize storage; in this study, there was no evidence of injection-induced seismicity however microseismic monitoring results were challenging to interpret due to the large number of events detected and the possibility of non- injection sources (e.g., noise).
• Borehole gravity may not provide adequate spatial resolution for CO2 delineation in pinnacle reef reservoirs owing their relatively small size.

Based on the monitoring results achieved in this study, recommendations were developed for monitoring CO2 storage in similar carbonate reservoirs. These will be discussed in the presentation.

Rick Schrynemeeckers
Amplified Geochemical Imaging LLC

A primary mode of Carbon Capture and Sequestration (CCS) is geologic sequestration in which carbon dioxide (CO₂) is injected into underground geologic sinks. Critical to the success of geologic sequestration is reservoir characterization to ensure that underground storage sinks have adequate seal and do not leak to pose a potential threat to human health and the environment.

However, the ability to determine if these subsurface structures have adequate seal prior to CO₂ injection and that those seals remain leak-proof is difficult since there are not many sensitive (i.e. parts per billion) CO₂ monitoring technologies available to provide adequate sensitivity and coverage for underground sequestration. However, ultrasensitive passive geochemical sorbers at the surface can provide the ability to monitor co-injected chemical tracers at nanogram mass levels (10-9 grams), thereby assessing the effectiveness of containment.

The first case study took place in the Yibal field located within the Fahud Salt Basin in northwestern Oman. The purpose of the survey was to ground-truth the ability of high sensitivity surface geochemical imaging to map elevated hydrocarbon compound response along faults in the Natih A reservoir prior to CO₂ injection.

Ultrasensitive samples were deployed at the surface over structural closures at depth (i.e. depleted petroleum reservoirs) to monitor indications of natural leakage pathways. After deployment, collection, and analysis, hydrocarbon signatures were detected and differentiated along fault trends. Enhanced light hydrocarbon signatures were mapped along coherent segments of fault projections inferring reservoir leakage along specific fault traces. The surface geochemical survey was able to detect subsurface leakage at parts per billion (ppb) levels.

The second case study involved the In Salah CCS program in the Algerian Krechba Field. The reservoir was overlain by ∼950 m carboniferous mudstones, siltstones, and limestones which were then overlain by ~900 m of Cretaceous sandstone deposits.

CO₂ was injected into the∼20m thick down-dip water leg of the gas reservoir at ∼1.9 km depth.

Response of the reservoir to CO₂ injection had already been observed using geophysical technologies: InSAR (Interferometric Synthetic Aperture Radar), 3D seismic and microseismic. Surface deformation up to several cm was observed above each of the injection wells by InSAR. The 3D seismic survey concluded that the CO₂ injection had activated a deep fracture zone extending several hundred meters wide and extending about 150 m above the reservoir.

An AGI survey, using fluorinated CO₂ tracers and 143 samples, was employed to evaluate subsurface leakage. A different fluorinated tracer, with a detection limit of ~ 5 ppb, was used for each well. Only background hydrocarbons levels were detected above the reservoir and along fractures indicating no evidence of leakage from the gas storage reservoir or around the injection wells. Thus, the study demonstrated the ability of the ultrasensitive method to monitor baseline levels of hydrocarbons and potential leakage of perfluoronated tracers, used as a proxy for CO₂.

D.J. White, Geological Survey of Canada and, A. Rangriz Shokri and R.J. Chalaturnyk, Department of Civil and Environmental Engineering, University of Alberta

CO₂ injection has been occurring since 2015 at the Aquistore Project within the Williston Basin in southeast Saskatchewan, Canada. CO₂ injection rates are ~60 ktonnes per year with a total of 350 ktonnes injected as of January 2021. The storage reservoir is a 200 m thick Cambro-Ordovician hyper-saline clastic formation lying unconformably on the Precambrian basement at ~3400 m depth. Key components of reservoir monitoring at the Aquistore site include passive monitoring for induced seismicity, 4D seismic using a permanent 2D array of surface geophones and well-based distributed acoustic sensing (DAS). 4D surface and vertical seismic surveys have been acquired at times when cumulative injected CO₂ was 0, 36, 102, 141 and 272 ktonnes, respectively. Passive seismic monitoring began prior to the start of injection.

Time-lapse amplitude differences observed in the 4D seismic volumes are interpreted as zones of CO₂ saturation. The CO₂ generally appears to be migrating in the regional up-dip direction (NNW) following structural and porosity/permeability fabric in the reservoir. Results from the 4D seismic analysis are compared against in situ measurements of flow rates at the injector and time-lapse CO₂ saturation logs from an observation well. The 4D seismic data image a primary CO₂ plume within a ~10 m thick high-permeability interval within the reservoir. This zone has continued to expand in sequential 4D images. Most recently, a secondary plume has been imaged within the upper part of the reservoir. The observed prominent directionality in the spread of CO₂ was not predicted by pre-injection flow simulations that show radial plume expansion. The geological model has been updated to include anisotropy in horizontal permeabilities and a lateral flow barrier that corresponds to an interpreted stratal flexure/ basement fault that is sub-parallel to the dominant structural trends. Resultant flow simulations show lateral CO₂ spread that is more consistent with the 4D seismic images. No induced seismicity has been recorded at the site.

Injecting carbon dioxide (CO₂) into reservoirs has great environmental and oilfield development benefits, and also associated risks. This study shows the potential of carbon storage and fault slip in the Cook Inlet basin of southcentral Alaska. The Cook Inlet basin comprises of several oil and gas fields, producing hydrocarbons since the late 1950s. Oil reservoirs have undergone fluid injection for many years in order to enhance recovery. In this study, two 3D seismic surveys, several well-logs (~200 wells), and core data (~40 wells) were incorporated to analyze petrophysical and geomechanical properties and understand reservoir heterogeneities. Many basement-rooted faults are present in the basin, several affecting the Hemlock reservoir. Injection of fluid in the reservoirs can increase the pore pressure, which reduces the effective stress. This phenomenon increases the risk of fault slip.

The Hemlock reservoir consists of sandstone and conglomerates, with an average porosity of 15-20%. The formation has an estimated CO₂ storage capacity of 0.91-16.61 Gigatonne (Gt), with a P50 value of ~4.33 Gt in the whole Cook Inlet basin (onshore and offshore). Structure, thickness, porosity, permeability, and net pay maps show the sweetspots for fluid injection in the basin at a regional scale. Fault slip potential (FSP) models are developed in two depleted fields (with 3D seismic coverage) in the basin using hydrologic and geomechanical parameters (e.g., poroelastic stiffness tensors and Biot’s coefficient), and stress gradients from core, well-log, and formation test data, and standard fluid injection information. These models estimate the cumulative conditional probability of slip of the seismic-defined faults at a certain injection rate over time, not the exact slip amount. FSP results show that faults have a potential to slip, depending on several factors, such as the local in-situ stress conditions, pore pressure, and CO₂ injection rate. Pore pressure and the azimuth of the maximum horizontal stress (δH) with respect to fault orientation are critical factors for fault stability in the Cook Inlet basin.

Kayla A. Kroll¹, Christopher S. Sherman¹, Corinne Layland-Bachmann², and Joshua A. White¹
¹Lawrence Livermore National Laboratory, ²Lawrence Berkeley National Laboratory

The possibility inducing earthquakes has been recognized as a significant risk faced by carbon storage operations which, in extreme cases, may lead to property damage and complete cessation of storage at a site. Efforts to mitigate this risk first require an understanding of the current and short-term future seismic hazard. Therefore, we have developed an Operational Forecasting of Induced Seismicity toolkit “ORION”, an open-source, observation-based ensemble forecasting toolkit which is geared towards helping operators understand the seismic hazard at a site. ORION analyzes how the seismic hazard evolves during injection, and suggests possible mitigation strategies to employ, if an earthquake that exceeds certain threshold is observed. Through its ensemble modeling approach, Orion leverages the benefits of both statistical and physics-based forecasting methodologies, while reducing the impact of each model’s respective limitations. The Orion toolkit consists of an easy-to-use web-based GUI interface that affords a user as much or as little interaction as desired. Advanced capabilities allow the user to upload local, high-precision earthquake catalogs, projected injection profiles and/or spatiotemporal estimates of pressure/stress, and to tune various model parameters. Orion will then provide a spatial and temporal ensemble forecast of seismicity defined as the probability of exceedance of a given earthquake magnitude over a forecast period. Additionally, Orion will provide probability distribution of the statistically derived maximum possible earthquake magnitude that may be expected. Finally, Orion will provide suggested operational management strategies (e.g. reduce injection volumes at specific wells) based on the level of hazard.

Talib Syed, P.E. – Consulting Petroleum Engineer/CCUS Consultant

Geologic storage of CO₂ has gained significance, largely due to it being a green-house gas (GHG) and concerns related to impacts on climate from GHG emissions. The literature and experience from industrial analogs indicate that wellbores (both active/inactive or abandoned) may represent the most likely route for escape of the injected CO₂ from the storage reservoirs. Therefore, sound injection well design and life cycle well integrity of all wells is of critical importance in such projects, particularly from a storage perspective of 1000 years or more. Challenges related to safe long-term CO₂ storage and its economics, principally in deep saline formations and to a lesser extent in depleted oil and gas reservoirs, can be broken down into two main categories: (1) Well integrity challenges and (2) Injectivity or Regularity challenges. This presentation will present key engineering factors that have to be addressed from a well integrity (primary) and injectivity/injected volume (secondary) perspective to enable a CO₂ geologic storage project to be a success.

In a CO₂ injection well, the principal well design considerations include pressure, thermal stresses, corrosion-resistant materials (tubulars and cements) and injection rates. Proper maintenance of CO₂ injection wells is important to avoid loss of well integrity. Plugging and abandonment procedures (and risks from legacy wellbores) are also important to ensure that the injected CO₂ will not escape out of the stored reservoir and are adequately addressed with sound engineering practices and regulatory compliance.

Industry experience, particularly with CO₂ EOR, natural gas storage and acid/sour gas wells shows that new CO₂ storage injection wells can maintain life cycle well integrity if designed, constructed, operated and monitored as per current state-of-the-art design specifications (e.g. use of WELLCATTM, DrillPlanTM, and other in-house proprietary software) and regulatory requirements.

John R. Underhill, Iain Anderson, Lauren Chedburn, Martha Guttierez, Sam Head, Allan Hollingworth, Rachel Jamieson & Laura-Jane Fyfe
Centre for Exploration Geoscience, Institute of GeoEnergy Engineering (IGE), Heriot-Watt University, Riccarton Campus, Edinburgh

The UK Continental Shelf (UKCS) hosts two petroleum super-basins (North Sea Rift and Anglo-Polish Basin) and numerous other oil and gas sub-provinces, all of which are experiencing a marked decline in production. The urgent need to decarbonise industrial clusters and increasing drive for renewable sources to meet stringent net zero emission targets in NW Europe present an opportunity to extend the life of the basins. New initiatives include the evaluation of safe subsurface storage sites for carbon dioxide (CO₂), hydrogen, methane and compressed air, and the development of new energy integration projects such as coupled blue hydrogen, green hydrogen, platform electrification using wind turbines, geothermal energy, gas-to-wire and geothermal initiatives. Taken together, it is evident that the continued exploration and development of the hydrocarbon resources, coupled with the use of novel, sustainable renewable energy technologies, provide a foundation for the UKCS to remain an energy hub serving the needs of the countries that border it and beyond.

With many UKCS fields now depleted, efforts are increasingly focused upon their abandonment, decommissioning and the possibility that they can be re-purposed to face a low-carbon energy future. In order to make carbon storage a viable option, there is a need to demonstrate that CO₂ can be stored safely. Our research studies highlight the especial opportunity that fields (natural analogues) containing carbon dioxide represent. Three main clusters of CO₂ are found in the UKCS: in the UK Southern North Sea, the East Irish Sea Basin and in the South Viking Graben. Once considered an exploration risk or a threat to production, the CO₂-bearing structures can instead be viewed as safe subsurface stores since they have demonstrably trapped carbon dioxide over geological time scales. The talk will discuss the controls on the geographical distribution and source of the CO₂ and describe the structural, stratigraphic and sedimentological factors that govern its long-term entrapment. The results highlight the key factors that govern the geological suitability of the CO₂-bearing traps and assess the viability of other potential storage sites including depleted fields and saline aquifers that do not contain CO₂. Application of these criteria provides the basis upon which to evaluate carbon storage opportunities and construct a geological roadmap upon which an overlay of non-technical risks can also be placed.

Steve Whittaker, Ph.D.
University of Illinois – Illinois State Geological Survey

The Illinois Storage Corridor project is designed to accelerate commercial deployment of carbon capture, utilization and storage (CCUS) within a region having demonstrated effective geologic storage characteristics and with numerous industrial carbon sources. This will be achieved by characterizing two individual sites for commercial-scale CO₂ storage, each with committed industrial CO₂ sources, and by receiving approvals for Underground Injection Control Class VI permits for construction at each site. This work builds on experience from projects in the region that have proven the feasibility of commercial-scale storage within the Illinois Basin using the extensive Cambro-Ordovician Storage Complex that comprises the well-known Mt Simon Sandstone Storage Complex and St Peter-Knox Storage Complex. This work includes the Midwest Geological Sequestration Consortium subsurface evaluation of the Illinois Basin, and the more recent CarbonSAFE Illinois Phase 1 and 2 projects that have expanded our knowledge of the storage potential of the Corridor region. The project team will perform detailed characterization at each site including acquiring new subsurface data through seismic surveys, well drilling and testing, and computer simulations. The work includes engaging with stakeholders and public. The project will define the multi-industry storage corridor through the development of a storage hub near the One Earth Energy facility in north-central Illinois and at the Prairie State Generating Company site in south-central Illinois. The combined annual CO₂ captured by these facilities will ultimately exceed 6.5 million tons per year. The capture sites are located directly above strata having a high likelihood of excellent injection and containment characteristics minimizing the requirement for pipelines or other transportation options. The ISC project will address all submission requirements for USEPA UIC Class VI permitting and will develop workflows for effective site characterization and efficient permitting for sites in areas of extensive storage complexes to accelerate deployment of CCUS.

Outcomes of the ISC project will be the development of a commercial CCUS project from an ethanol plant using a proven storage complex at the One Earth Energy site. This will initiate the further development of the site as a regional storage hub to benefit other CO₂ sources without storage options and will be among the first CCUS project globally to place the hub concept into practice. The Prairie State CCUS project will be one of the largest in the world and will establish the role of CCUS to make significant reductions in CO₂ emissions from large industrial sources. The scale of this project will demonstrate leadership for other large industrial sources to undertake this important challenge.

Shuvajit Bhattacharya, Ph.D., Bureau of Economic Geology, UT Austin

Machine learning is an emerging tool in geosciences. It holds some promises for efficient geophysical data processing, integration, and interpretation, which is applicable to hydrocarbon exploration, CCUS, and geothermal energy. The study involves interpreting a multi-phase and multi-azimuthal normal fault network in the deep subsurface using novel 3D seismic attributes and deep learning. Such fault systems are common in many areas in the world, including the North Slope (Alaska), North Sea, and offshore SW Australia. Characterizing such fault systems is critical to de-risk CCUS projects. In this study, aberrancy attributes and convolutional neural networks are used to classify the faults and generate 3D fault models in an area of 1,000 square kilometers. The basement in the study area was reactivated several times due to different tectonic events, which compartmentalized the reservoirs. This impacted reservoir quality and recovery potential. The workflow and results presented here can also be beneficial to several areas.

Sallie E. Greenberg, Ph.D.
University of Illinois - Illinois State Geological Survey

Conventional wisdom indicates that policy drivers and international collaboration are needed for emissions reductions at a scale necessary to limit climate change to below 2 degrees Celsius and meet the carbon dioxide (CO₂) reduction targets such as those defined in Paris. Carbon capture utilization and storage (CCUS) is critical to meeting these targets. The demonstration of geologic storage of CO₂ at near commercial-scale has been essential to understanding the viability of to meet energy and climate objectives. The Illinois Basin – Decatur Project (IBDP), located in Decatur, Illinois is a one million tonne deep saline geologic CO₂ storage project led by the Midwest Geologic Sequestration Consortium, a United States Department of Energy – National Energy Technology Laboratory’s Regional Carbon Sequestration Partnership. IBDP is nearing completion of the integrated demonstration project in the Mt. Simon Sandstone, the largest-capacity saline reservoir in the Illinois Basin. IBDP stored 1 million tonnes of CO₂ derived from biofuel production at Archer Daniels Midland (ADM), making the project one of the only full-scale bioenergy CCS (BECCS) demonstration projects to-date. IBDP is has concluded post-injection monitoring and was the basis for the commercial-scale up of the Illinois Industrial Sources CCS Project (ICCS). IBDP demonstrated the safety, effectiveness, and efficiency the full CCS value chain. The injectivity and capacity of the Mt. Simon reservoir have been confirmed and are being utilized for the ICCS, an industrial-scale carbon storage project, which will began injection of one million tonnes per year starting in early 2017. The learnings and challenges of first of a kind CCS projects will be discussed, including project work flow, economy of scale, technical challenges, scientific findings, permitting, and public engagement.

Neeraj Gupta, Battelle

There is likely to be continued reliance on fossil fuels for energy for the foreseeable future. Therefore, it is important to foster development and deployment of Carbon Capture Utilization and Storage (CCUS) in developing countries for successful mitigation of CO₂ emissions, However, to date these efforts have been hampered by lack of access to technology, policy delays, and financial constraints. Building on the experience gained from US projects, with funding from multinational institutions, and in collaboration with local experts, Battelle conducted several early-stage projects in the developing countries. These projects include - a pre-feasibility of storage in Sichuan Basin China; an assessment of transition from CO₂-EOR to storage in Mexico; support for a pilot-scale project planning in South Africa; a detailed feasibility for CCUS for gas processing plants in Indonesia; and a FEED study for CCUS in coal to chemicals in Ordos Basin in China. These projects illustrate a range of CCUS project deployment scenarios with a variety of technical challenges. In all cases, capacity development through local collaboration and workshops was a key component of the program. Overall, these early-stage efforts were useful in their objectives of initiating CCUS development in the study areas, identifying and addressing key technical challenges, and promoting technology transfer. The lessons learned from these programs are also useful in developing the path forward for what will hopefully be the next wave of international collaboration on CCUS.

Camelia C. Knapp¹, Khaled Almutairi²ˈ³, James H. Knapp¹, Andrew Bean¹ˈ⁴, John Ollmann⁴, Dawod Almayahi¹, Adil Alshammar³, and Venkat Lakshmi⁵
¹Boone Pickens School of Geology, ²King Abdulaziz City for Science and Technology, ³School of the Earth, Ocean, and Environment, University of South Carolina, ⁴Battelle, Albany, Oregon, ⁵University of Virginia

The Atlantic offshore carbon storage resources were assessed as part of the Southeast Offshore Storage Resource Assessment (SOSRA) research project funded by the U.S. Department of Energy (DOE). This study focuses on development of offshore prospective storage resource assessment of the Upper and Lower Cretaceous as well as Upper Jurassic sections within the Southeast Georgia Embayment (SGE). Using legacy industry 2-D seismic reflection and well data, this assessment was the first application of an innovative approach of multiple seismic inversion techniques in this area. This work included a reliable and replicable workflow of model-based inversion that provides the tools to discriminate lithology and predict porosity and permeability. The impedance and porosity relationships show well-founded and reliable correlations. These relationships reveal low seismic impedance to coincide with high porosity intervals identified on well logs and which are proposed as potential CO₂ storage reservoirs. The seismic data were converted to depth by using a sophisticated approach of deriving regional seismic velocities from legacy refraction and reflection stacking velocity data. A holistic approach to the entire South Atlantic Margin was taken with respect to seismic velocity analysis with emphasis on the SGE.

In the Upper Cretaceous strata, the CO₂ storage capacity is approximately 31.92 GT, regionally. The storage capacity for the two identified significant reservoirs in the SGE is ~8.79 GT of that amount. There are three target reservoirs within the Lower Cretaceous strata based on geophysical and well log analysis. The calculated storage capacity is 746 Gt of CO₂ at P50 that could be stored securely in a 4.61*1012 cubic ft volume. The total average thickness of the potential reservoirs is 1425 ft. In addition, there are three identified potential reservoirs separated by four seals within the Upper Jurassic strata in the Southeast Georgia Embayment. The Upper Jurassic section is bound at the bottom by the Triassic post-rift unconformity. A total of ~46 Gt storage capacity within a 4300 sq mi area is estimated for the Upper Jurassic strata within the SGE.

These estimates were constrained by geomechanical and computed tomography (CT) data collection and analyses of existing COST GE-1 drill core for experimental rock physics evaluation aimed to ground-truth the geophysical studies and constrain volumetric estimates. More specifically, the rock physics study included X-ray Fluorescence (XRF) and medical X-ray Computed Tomography (CT) images on whole-core samples and industrial CT images, porosity, permeability, dry rock density, grain density, P-wave velocity, S-wave velocity, and elastic moduli for plug samples within potential reservoir and seal depth intervals. These data provided a better understanding of in-situ geomechanical response and rock properties of both reservoir and seal lithologies to constrain CO₂ storage suitability within the SGE. Injection simulations models were run using the Computer Modelling Group Ltd. (CMG) reservoir simulation software platform. The main model covered 3,600 km2 with a resolution of 10,000 cells to explain the distribution of CO₂ in both the Upper and Lower Cretaceous strata reservoirs.

Robert Balch, Brian McPherson, Martha Cather

The Carbon Utilization and Storage Partnership of the Western United States (CUSP) is one of four new regional carbon storage partnerships created in 2019 by United States Department of Energy to accelerate commercial CO₂ storage in the United States. The CUSP includes members representing national laboratories, academia, state research agencies and industry in 13 states, and combines parts of several previous regional partnerships. The CUSP leverages the capabilities, data, and expertise accumulated through years of research and dozens of projects throughout the western U.S. with the overall objectives of identifying the most promising combinations of CO₂ sources, storage reservoirs, transportation routes and industrial partners that will allow more rapid deployment of CCUS in the region.

The project scope encompasses collection, updating and synthesis of diverse extant data sets, complex data analysis, modeling, and scenario development to support more rapid implementation of commercial-scale CCUS. Our emphasis on collaboration, knowledge dissemination and technology transfer will engage and inform stakeholders with the data and knowledge necessary to undertake CCUS projects throughout the region.

One major deliverable of the CUSP project is interactive maps and data products that delineate regions and specific targets having the best prospects for commercially-viable CCUS, and also highlight technical challenges and their effects on CCUS development. Readiness indices based on a number of factors will be developed to 1) help target the best areas for short-term, mid-term, and long-term CCUS projects, 2) identify potential improvements to make projects more economically/technically feasible, and 3) swiftly and cost-effectively graduate potential projects to short-term deployment. The project will examine and provide access to an unparalleled amount of spatial, economic, and engineering data across the entire CCUS supply chain.

The CUSP also has the opportunity to work on more focused projects with industry partners where our subject matter experts may provide assistance in helping them overcome specific scientific or regulatory challenge that are slowing their progress towards beginning or completing CCUS projects. The workflows and templates developed in these efforts can be useful to many as industries seek to capture and use or store more greenhouse gases.

Carbon Capture and Carbon Dioxide (CO2) EOR & Storage – A “Game Changer” Technology for India in its Environmental, Social and Energy Resources Goals

Dr. Ganesh Thakur, NAE, Distinguished Professor – University of Houston
Dr. Sushanta Bose, Sr. Geologist, currently at WDVG Company
Dr. Peila Chen, Reservoir Engineer and Research Associate, University of Houston

Abstract

With fossil resources continuing to be the primary source of energy consumption and increasing emphasis on greenhouse gas restrictions around the world, of carbon capture, storage and utilization (CCUS) plays an increasingly important role in today’s oil and gas operations to address and establish the low carbon technology. Nations with large energy demand like India, can be especially benefitted from this technology to significantly support its environmental and energy self-reliance goals. With financial incentives to capture carbon, operators are venturing more into CO₂ EOR and storage projects. University of Houston’s CCUS and EOR research at the Energy Industry Partnership team (EIP) focuses on detailed study of CO₂ EOR in conventional and unconventional reservoirs including laboratory studies, reservoir characterization, dynamic simulation, and integrated reservoir-well facilities studies. EIP’s fundamental research is complemented by field studies through active involvement in Oil India’s CO₂ EOR/Storage ventures, which is three phased.

Phase 1 –University of Houston has identified reservoir candidates for CO₂ EOR feasibility study from a pool of 50 reservoirs, by employing patented advanced reservoir screening techniques.

For a reservoir to be a good candidate for CO₂ EOR, remaining oil saturation has to be greater than 40%. Estimating mobility ratio, minimum miscibility pressure and bubble point pressure values are as critical as considering geological characters of the reservoir such as lateral and vertical facies variations. Another practical and crucial factor in consideration is if the reservoir has been managed appropriately.

Phase 2 – CO₂ EOR Pilot Design: Laboratory Study, Simulation Study (3-D Geological Modeling, History Matching, CO₂ EOR Simulation), Pilot Design (CO₂ Source Study, Facilities/Completion, Economic Analysis) 

3-D geomodelling included full cycle of reservoir mapping, petrophysics and static modeling. The minimum miscibility pressure (MMP), the lowest pressure at which the injected gas becomes miscible with the reservoir fluid, was studied in the laboratory using slim tube experiments. Furthermore, swelling tests, asphaltene precipitation tests and core flooding were also carried out in the EOR laboratory to understand the dynamics of a particular reservoir for the EOR applicability. Dynamic simulation included rigorous pressure-production history matching exercise followed by water injection and CO₂ EOR predictions. The CO₂ storage capacity of the reservoirs were investigated and optimum pilot injection patterns were determined along with economics and facilities studies. Consequently, local industrial sources for anthropogenic CO₂ were carried out in collaboration with the operator. 

Phase 3 – CO₂ EOR Pilot Implementation

Till date, UH-OIL collaboration has developed two CO₂-EOR pilot designs, and reservoir management operations for preparation of CO₂ EOR is ongoing. Authorities in India have approved CO₂ injection in the first pilot. The encouragement from the progress of this study and the incentives by the government, other operators have also shown significant interest and activity on the ground. It is believed that the nation will be greatly benefitted in its energy and environmental goals with successful implementation of the fieldwide projects. 

Key Words: Low Carbon Technology, Carbon Capture and Storage, CO₂ EOR, CO₂ Storage, Anthropogenic CO₂

Osmond, J. L.¹*, Mulrooney, M. J.¹, Holden, N.¹, Skurtveit, E.²𝄒¹, Faleide, J. I.¹, and A. Braathen¹
¹University of Oslo. ²Norwegian Geotechnical Institute, *Corresponding author

Capture of industrially sourced CO₂ and transport to the Aurora subsurface storage site in the northern North Sea are approved to commence in 2024 under the direction of the Longship and Northern Lights projects. Results from well 31/5-7 drilled in early 2020 within exploitation license EL001 confirmed suitable parameters at Aurora (e.g., porosity, injectivity, etc.). While the geology of the site proves promising for CCS, it remains imperative to mature additional locations in order to meet current climate mitigation targets and establish the Horda Platform as a European storage hub.

Planned injection and containment at Aurora will be hosted by the Lower Jurassic Dunlin Gp stratigraphic storage complex (storage aquifer and seals), however, the Upper Jurassic Viking Gp represents an additional storage complex. Moreover, Aurora is located in the western-most of three large, basement-rooted fault blocks, each showing storage potential. Hundreds of thick- and thin-skinned faults create two- and three-way structural traps for both storage complexes in all three fault blocks. Some Viking Gp traps contain hydrocarbons (e.g., Troll field), providing direct analogs, but should be avoided for CO₂ storage until the end of their production life around 2050. Nevertheless, the remaining structural traps currently make the most attractive storage prospects, as they can focus injected CO₂ in a predicable fashion, particularly during the early stages of the sequestration process before other trapping mechanisms take over (e.g., residual trapping).

As both top and lateral seals must completely envelop the storage aquifer, understanding the distribution and nature of the seals is critical for predicting subsurface CO₂ containment. In order to provide insight towards additional CCS potential in the Horda Platform, we present a summation of top and lateral seal mapping, modeling, and observations for the Dunlin and Viking Gp storage complexes in the three major fault blocks.

For the Dunlin Gp storage complex, interpretation of its top seal distribution from 3D seismic and wellbore data confirm seal presence in all three fault blocks, including that of the Aurora site. The majority of small thin-skinned faults at the Jurassic stratigraphic level and create aquifer juxtapositions against the top seal, while larger thick-skinned faults must provide membrane seals along the largest closures. In these latter cases, the Dunlin Gp sandstone aquifer is up-thrown and juxtaposed against the overlying Viking Gp sandstone aquifer, but shale gouge ratio analysis and regional aquifer pressures suggest favorable membrane fault seal potential. Top seal formations above the Viking Gp aquifer are determined to be present throughout the Horda Platform, but only the eastern-most fault block is currently prospective for CO₂ storage, given the high risk of contaminating producing fields in adjacent fault blocks. Fault seals in this case appear to be juxtaposition-controlled, even for thick-skinned faults, which are analogous to Troll East. Considering the availability of structural traps for expanding storage activities in the Horda Platform, our work infers that the presence top and lateral seals is probable for both the Dunlin and Viking Gp storage complexes.

Neeraj Gupta, Battelle, Columbus Ohio

There is likely to be continued reliance on fossil fuels for energy for the foreseeable future. Therefore, it is important to foster development and deployment of Carbon Capture Utilization and Storage (CCUS) in developing countries for successful mitigation of CO₂ emissions, However, to date these efforts have been hampered by lack of access to technology, policy delays, and financial constraints. Building on the experience gained from US projects, with funding from multinational institutions, and in collaboration with local experts, Battelle conducted several early-stage projects in the developing countries. These projects include - a pre-feasibility of storage in Sichuan Basin China; an assessment of transition from CO₂-EOR to storage in Mexico; support for a pilot-scale project planning in South Africa; a detailed feasibility for CCUS for gas processing plants in Indonesia; and a FEED study for CCUS in coal to chemicals in Ordos Basin in China. These projects illustrate a range of CCUS project deployment scenarios with a variety of technical challenges. In all cases, capacity development through local collaboration and workshops was a key component of the program. Overall, these early-stage efforts were useful in their objectives of initiating CCUS development in the study areas, identifying and addressing key technical challenges, and promoting technology transfer. The lessons learned from these programs are also useful in developing the path forward for what will hopefully be the next wave of international collaboration on CCUS.

Case Studies and Industry Applications 45Q and ISO: Possible solutions for CCUS

Steven M. Carpenter¹ George J. Koperna²

¹Enhanced Oil Recovery Institute, 2435 King Blvd, Ste 140 Casper, WY 82604 USA

²Advanced Resources International, Inc. 4501 Fairfax Drive, Suite 910, Arlington, VA 22203 USA

Whether one refers to it as CCS, CCUS, CO₂-EOR, “saline storage”, “incidental storage”, or an as yet to be defined term, the intent is closely related. Capture anthropogenic (man-made) carbon dioxide, transport it to a safe and secure storage location or facility, and inject the carbon dioxide into the geologic formation. Much research has been conducted on the group of technologies that are required to accomplish the task, but little has been written, and even less has been shared about the “process” to create internationally acceptable standards to qualify, quantify, and verify the CCUS process. While the contents of the International Standards are copyrighted, what is often overlooked, and in many cases fascinating, is the behind the scenes process, “inside baseball” or “behind the curtain” of the sausage making process of ISO 27916-2109 Carbon dioxide capture, transportation and geological storage — Carbon dioxide storage using enhanced oil recovery (CO₂-EOR). This article provides a discussion of the progress in frameworks and protocols regarding the relevant information of the process and issues wrestled with in order to develop an international standard on CO₂-EOR/CCUS in the broader community. This presentation will present some of the background thinking, the extended debates about US and EU rules, various stakeholder’s perspectives on the key issues, and how this impacts rulemaking and technical solutions. Additionally, this presentation will discuss the process and regulation of CO₂-EOR and what the application of the IRS 45Q tax credit and the use of the ANSI 27916:2019 can mean for the advancement of CCUS. The amended section 45Q tax credit is intended to further incentivize technologies such as CO₂-EOR that deliver significant economic benefits while necessarily resulting in the associated storage of CO₂ as part of routine operations.

Scott Frailey, PhD, P.E. – Reservoir Engineer, Illinois Geological Survey

The Storage Resources Management System was developed to provide standard terminology and guidelines for assessing and quantifying subsurface CO₂ storage estimates for a defined storage project. Although the SRMS can be applied to any estimate of subsurface storage, the SRMS is intended for commercial usage. Therefore, key to the application of the SRMS is 1) a clearly defined project and plan of development (through active injection) and 2) an assessment of the storable quantities of CO₂ associated with the defined project. Classification of storable quantities is based on the maturity of a defined project, while Categorization of storable quantities is based on certainty in the estimate of storage (e.g., geology and displacement processes). The three major Classifications in order of decreasing project maturity are Capacity, Contingent Storage Resources, and Prospective Storage Resources. Capacity is used to describe forecasts of storable quantities for developed projects on active injection. The Contingent and Prospective Storage Resource classifications are for less mature projects, which may include regional assessments using a notional project. The Categorization of storable quantities has three categories: High, Best, and Low estimate with Low being highly likely (P90), Best being most likely (P50), and High being less likely (P10). For the Capacity Classification, the three categories are named Proved (Low), Probable (Best), and Possible (High). Proved Capacity is used to indicate the highest degree of certainty in a project’s storable quantities and that active injection is occurring or imminent. Successful use of the SRMS provides a common basis for comparison of storage resources in the context of defined projects in different regions and jurisdictions for financial, contractual, project development purposes.

John D. Pigott, Kulwadee L. Pigott, and Jerry Zhai

School of Geosciences, The University of Oklahoma, Norman, OK

Offshore subsurface marine water-bearing sandstones provide one of the largest potential reservoirs for the carbon dioxide sequestration (CDS). Delineation of the geometry, reservoir quality and sealing potential of such reservoirs can be facilitated through many of the same workflow procedures as conventional hydrocarbon (CHC) exploration, with a few important exceptions. A complication for both however is that for evaluation of poorly explored HC regions is the lack of good constraining subsurface data (wells and seismic). The solution for the pragmatic exploration of frontier CDS is the integration of basin analysis and seismic stratigraphy.

An example of such a procedure is provided by our investigation workflow applied to 75,000 kms² of the continental shelf of offshore New Jersey-Delaware using some 300 migrated 1978-1984 vintage 2D lines, 7 s record length, 4 ms sample rate, and petrophysical logs from 13 wells including the famous Cost B2 and Cost B3 wells. To enhance the geologic information between the sparsely distributed well control, a novel seismic inversion of 2D line stacking velocities was applied to generate 2D panoramas of velocity, density, porosity, and lithofacies. The workflow followed was: 1. Interpretation of the fault mechanical stratigraphy 2. Application of “Vail” seismic sequence stratigraphy 3. Application of a modified “Galloway” bipartite sequence motif of stacking patterns 4. Synthetic generation and tying 5. Detailed stratigraphic determination with micropaleo of wells 6. Delineation and correlation of  parasequence sets 7. Basin modeling of real and virtual wells for variations of temperature, porosities, and organic maturities with time and depth 8. Basin modeling determination of shale ductility 9. Determination of velocity, density, and porosity from the seismic inversion 10. Determination of seismic lithofacies from seismic inversion 11. Mapping of interpolated surfaces, and 12. Generation of isochrons and isopachs of shale, siltstone, and sandstones from Cretaceous to the Holocene.

The similarities between CHC and CDS reservoir exploration are finding optimal reservoir (avoidance of poor permeability siltstone and shale lithofacies), delineating good top and lateral seals, and locating structural and stratigraphic traps. Important differences between CHC and CDS reservoir exploration are that for the best CDS potential storage results one should 1. Look for low shale to gouge ratio “leaky” faults for maximum reservoir connectivity and potential in-fault disposal 2. Avoid reservoirs with existing hydrocarbons 3. Avoid reservoirs with acoustic DHI signatures, and 4. Avoid potentially overpressured reservoirs.

For the offshore New Jersey-Delaware Atlantic margin, we delineated 2.037 gigatonnes of potential CDS storage.  An implicit component shared both by CDS and CHC exploration is that of economics. For CDS, the optimal level of carbon capture and storage would be where the marginal benefits and marginal costs of CO₂ captured and stored are equal. A humbling storage consideration is the following. For every barrel of oil consumed, to dispose of its captured CO₂ as liquid would require 3.5 barrels of storage capacity. Thus, to be economic, the cost of capturing, transporting, and storing 3.5 barrels of CO₂ must be less than the cost of producing one barrel of oil.