- Email: [email protected]
Overview of a Large Scale Carbon Capture, Utilization, and Storage Demonstration Project in an Active Oil Field in Texas, USA
Available online at www.sciencedirect.com
ScienceDirect Energy Procedia 114 (2017) 5874 – 5887
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland
Overview of a Large Scale Carbon Capture, Utilization, and Storage Demonstration Project in an Active Oil Field in Texas, USA Robert Balcha*, Brian McPhersonb, and Reid Grigga a
New Mexico Institute of Mining and Technology, 801 Leroy Place, Socorro, New Mexico 87801, USA b University of Utah, 201 Presidents Cir, Salt Lake City, Utah 84112, USA
Abstract The Southwest Regional Partnership on Carbon Sequestration (SWP) is one of seven large scale CO 2 sequestration projects sponsored by the U.S. Department of Energy. The primary objective of the SWP effort, currently in its demonstration stage, is to exhibit and evaluate an active commercial-scale carbon capture, utilization and storage (CCUS) operation, and demonstrate associated effective site characterization, monitoring, verification, accounting, and risk assessment. The SWP has monitored storage of 461,040 metric tonnes of CO2 between October, 2013 and June, 2016 into 16 active patterns. At least 1 million metric tonnes of CO2 will be stored prior to completion of the study. The SWP project is located within an active EOR field, a mature waterflood in the Farnsworth Unit, Texas, which is undergoing conversion to a CO 2 flood. All CO2 utilized by the project is anthropogenic, sourced from a fertilizer and an ethanol plant, and this CO2 would otherwise be vented to the atmosphere. Much of the injected CO2 will be trapped permanently in the subsurface, and a primary objective is to quantify CO2 storage capacity and study conditions and characteristics that promote trapping. This project will contribute to the development of future commercial CCUS projects in the United States by demonstrating all aspects of an actual commercial CCUS field operation, including effective reservoir engineering, monitoring, and simulation technologies. The project has acquired multiple data sets for site characterization, monitoring CO2 plume growth, and storage security. Surface and near-surface monitoring methods used to evaluate CO2 migration out of the reservoir, have verified that CO2 leakage to the surface and/or groundwater has not occurred through September of 2016. As the SWP acquires data for each major area of study (characterization, monitoring, simulation, and risk), information and feedback are acquired to improve the work in other focus areas. A conscious effort is made to discern aspects of the work that can contribute to Department of Energy Best Practices Manuals for carbon sequestration, in particular as it relates to CCUS projects. This paper presents the SWP project, its current status, and progress towards primary goals.
* Corresponding author. Tel.: +1-575-835-5305; fax: +1-575-835-6305. E-mail address: [email protected]
1876-6102 © 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. doi:10.1016/j.egypro.2017.03.1725
Robert Balch et al. / Energy Procedia 114 (2017) 5874 – 5887 © 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license © 2017 The Authors. Published by Elsevier Ltd. (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. Peer-review under responsibility of the organizing committee of GHGT-13. Keywords: CO2-EOR; Sequestration; Carbon Storage; MVA; Simulation; Risk; Characterization
1. Introduction The Southwest Regional Partnership on Carbon Sequestration (SWP) is one of seven organizations performing large scale demonstration projects funded by the US Department of Energy. Each project covers a major region of the USA and/or Canada and focuses on studying regional storage potential, tabulating point sources of CO 2, and studying aspects of carbon storage via demonstration projects within their respective regions. Fig. 1a shows the mapped areas for each regional partnership. Blue drops signify the location of saline aquifer storage projects, and black drops show the approximate location of large scale Carbon Capture, Utilization and Storage (CCUS) demonstration projects. Each regional partnership was tasked with demonstrating the storage of 1 million metric tonnes of CO 2 into a project site within their region, and contributing to best practices for storage in aquifers and oil fields. This paper focuses on the SWP, and its associated region in the southwestern USA (Fig. 1b). The SWP is a consortium of three universities, three national laboratories, service companies, and operating partners including Chaparral Energy, LLC which operates eight CO2 EOR projects utilizing man-made CO2. Farnsworth Unit is the location of the SWP’s large scale demonstration project.
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Fig. 1. (a) U.S Department of Energy Regional Carbon Sequestration Partnerships. Black drops show the approximate location of large scale CO2 EOR / sequestration demonstration projects, blue drops show saline aquifer injection sites [1]. (b) The seven-state region covered by the Southwest Partnership on CO2 Sequestration. The geographic extent of the Anadarko basin is the hatched area in Oklahoma and Texas. The approximate location of Farnsworth Unit is indicated within the Anadarko basin [2].
1.1. Project Description The SWP Farnsworth project covers three phases of research; pre-injection, injection, and post-injection. The preinjection phase studied existing data to determine what additional information was needed and also established baseline data for monitoring injected CO2 in the subsurface and for verifying storage security at the surface. The preinjection study at Farnsworth focused on patterns that had not yet had CO 2 injection as the site was already an active enhanced oil recovery project when the SWP baseline study began. At the time of this paper, the project was in the injection period, and active project roles were data interpretation, evaluation of potential risks, design and development of monitoring, verification and accounting (MVA) plans; and injection of CO2 until the target goal of at least 1 million metric tonnes of net CO2 has been stored. The injection period study can be summarized as a continuous evaluation
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of characterization and production data to build and evolve a series of geologic models that facilitate reservoir simulation and monitoring programs for evaluating caprock integrity and security. The post-injection period for the Farnsworth project will commence after 1 million metric tons of CO 2 have been stored. During this period SWP will continue to perform MVA activities and track CO2 plume movement; conduct further simulation and risk assessment studies; and refine geologic models for the field site and region, and improve CO 2 storage estimates. 1.2. Field Site The SWP project is located within an active EOR field, a mature waterflood in the Farnsworth Unit, Texas, USA which is undergoing conversion to a CO 2 flood. Farnsworth unit is located in the Anadarko basin, a 70,000 square mile deep structural basin located primarily in northern Texas and Oklahoma (Fig. 1b). The basin has been under development since 1860 [3] and contains significant oil and gas reserves. The Anadarko is a mature oil and gas province and as such is representative of other mature productive basins within the USA and across the world, and has established production and transportation infrastructure in place, along with ongoing exploration and new development. Existing point sources of CO2 in the region, coupled with existing infrastructure and mature fields makes the basin an excellent study area for carbon capture utilization and storage (CCUS) projects. The SWP began studying the site in October of 2013. At the time of this paper, the field had 16 active CO2 injectors and had sequestered 461,040 metric tonnes of CO2 between October, 2013 and June of 2016. Prior to the SWP becoming involved with Farnsworth, an additional 440,516 tonnes were sequestered between October, 2010 and September, 2013 by the site operator, Chaparral Energy, LLC. Chaparral has converted a row of inverted 5-spot patterns to CO2 approximately every year since 2011, making the site an excellent testing facility for CO 2 monitoring technologies since each new row of injectors provides a new opportunity to record zero CO 2 baseline data, mid-flood data, and data from fully flooded patterns. All CO2 injected at Farnsworth project has been delivered from two anthropogenic sources, the Agrium Fertilizer Plant at Borger, Texas, USA and the Arkalon Ethanol Plant at Liberal, Kansas, USA (Fig. 2). Injected CO2 is being trapped in the subsurface in the Morrow B formation. The site operator is injecting CO2 in the center well of five-spot well patterns. The project started with three patterns in December 2010, with additional patterns added as recycled CO2 becomes available. As of September of 2015, there were 16 operating patterns (Fig. 3) and the eventual goal is to have a total of 25 patterns emplaced in the western half of Farnsworth unit. The operator injects anthropogenic CO2 at a rate of about ~518 tonnes/day or ~190,000 tonnes/year. SOU TH WE ST CAR BON PA R T N E R S H I P REGION
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
Fig. 2. Over 100 miles of pipeline connect two sources to three projects and could be extended to several more fields in the area. Grey shaded portions of the map show oil fields in the vicinity of the two point sources of CO2. Chaparral can vary delivery rates for operational flexibility.
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Figure 3. Current and near future pattern conversion to CO2 injection. Development uses invert 5-spot patterns with a central CO2 injector surrounded by four producers on approximately a 40 acre spacing.
2. Methods The SWP work plan established surface and subsurface monitoring baseline data in patterns that had not yet seen CO2, while studying already active patterns to aid in tool calibration and geologic understanding. Primary objectives of the project are reservoir characterization; reservoir modeling; monitoring, verification, and accounting of injected CO2; and business and geologic risk analyses. CO2 injection and production volumes are tracked in all wells in the unit to allow for a complete material balance to determine the mass of CO2 stored in the reservoir over the course of the project. Two patterns in the west half and one pattern in the east half of Farnsworth were selected as focal points of the demonstration project (Fig. 4). Existing data, production/injection history, a project-acquired 3D surface seismic survey, and ongoing flow simulations, were acquired and studied. Added value from the intensive studies in those patterns is an increased understanding of the entire unit. Project goals encompassing all three phases of work include: (1) Demonstration of injection of 100% anthropogenically sourced CO2: Using CO2 sourced from a fertilizer plant and an ethanol plant makes this project relevant to smaller, non-coal CO2 emission sources that are both common and widely distributed in oil producing regions world-wide. (2) Development of “best practices”: By studying a new set of injection wells that are transitioning to CO2 flood as needed, the effectiveness of monitoring technologies may be ascertained. (3) Demonstration of coupled reservoir model simulation and geologic model development for continuously improving characterization and MVA design: integration of reservoir simulation results with geologic models constructed using the 3D surface seismic survey, three baseline 3D-VSP surveys centered on injection wells, four cross-well baseline surveys and repeat seismic acquisition all contribute to continuously evolved reservoir models and improved seismic interpretations. (4) Understanding storage capacity and determination of modes of trapping: A continuous material balance, yield a “cradle to grave” lifecycle illustration of the EOR-CCUS processes.
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(5) Integration of characterization studies with simulation, risk assessment and MVA: Using results of seismic, log, core, and production data provides a comprehensive surface to injection zone reservoir analysis The project as a whole is broadly divided into four categories: Characterization, Simulation, Monitoring, and Risk. Results for each study area are iterative, integrated, and frequently encompass more than one category.
Fig. 4. Seismic data has been an integral part of the characterization program and includes a baseline 42 mi 2 3D survey over the entire field, three baseline 3D VSPS centered on injection wells, and four baseline cross-well tomography segments between injector/producer pairs. In addition, a dedicated monitoring well has a 16 level 3component passive seismic monitoring array installed within it [2].
3. Geologic and Geophysical Characterization The project has acquired multiple data sets for site characterization, monitoring CO 2 plume growth, and storage security. The project drilled, logged, and collected 750 ft of core from three characterization wells which allowed detailed geologic characterization, studies of rock mechanics in reservoir and seal units, and lab studies of relative permeability. The SWP also conducted and analyzed a full-field 3D surface seismic survey, three 3D-VSP baseline surveys, four crosswell seismic baseline surveys, and repeat surveys for one 3D-VSP and two crosswell seismic surveys (Fig. 4). Each year an updated fine-scale geologic model is produced and distributed for simulation analyses necessary for effective risk assessment and for increased resolution of monitoring, verification and accounting tasks. The evolution of this model can be observed by comparing permeability estimates from an early model (Fig. 5) to more current results shown in Fig. 6. Annual geologic models directly impact simulation efforts focused on historymatching the entire field, reactive transport modeling, CO2 capacity estimation, quantification of seal integrity, and ultimately forecasting the fate of the CO2 plume 100 years or more post-injection. The 3D VSP and cross-well data with repeat surveys have allowed for direct comparisons of the reservoir prior to CO 2 injection and at eight months into injection, with a goal of periodically imaging the CO2 plume as it migrates away from injection wells. Additional repeat surveys at regular intervals will continue to refine direct CO 2 imaging as production and injection data are integrated with newly acquired and interpreted data, and as models are regularly updated. One ultimate goal of subsurface characterization and interpretation is the development of a 3D, fully coupled process model of the injection site. Geologic, and in turn, simulation models, are based on information obtained from baseline data and ongoing collected data from pre-monitoring efforts, including drilling activities, seismic surveys, and sample analyses.
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Fig. 5. Statistically derived permeability distribution for Farnsworth. The data was incorporated into the 2015 version of the geologic/simulation model [4].
Fig. 6. Average permeability of Morrow B interval in an improved geologic model incorporating interpreted faults and hydraulic flow units [5]. 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 Morrow formation. This data was used in the 2016 version of the geologic model.
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4. Near Surface Monitoring The SWP has also acquired significant surface data for monitoring and characterization including soil flux and eddy covariance tower measurements for surface flux detection; subsurface data include baseline and repeat crosswell seismic surveys, a borehole passive seismic array to monitor for induced seismicity, distributed temperature arrays to measure variations in borehole temperature, and bottom-hole pressure and temperature sensors to monitor subsurface movement of CO2 (Figs. 7-8) These surface and near-surface monitoring methods are used to evaluate CO2 migration out of the reservoir. CO2 soil flux measurements from more than 90 surface locations are recorded quarterly and compared to baseline data collected monthly during the first year of observation. In addition, an eddy covariance tower is located on site to monitor atmospheric CO2 flux and identify any potential point-source leakage (e.g. wellbores). Other Farnsworth Unit monitoring focuses on drinkable groundwater chemistry, reservoir fluids chemistry, and aqueous- and gas-phase tracer studies. The regular CO2 soil and eddy flux, aqueous- and vapor-phase tracer, and groundwater chemistry studies have only shown seasonal variations and have verified that CO2 (or reservoir fluid) leakage to the surface and/or groundwater has not occurred through September of 2016.
Fig. 7. Direct monitoring strategy at the Farnsworth Unit incorporating numerous surface and subsurface approaches [2].
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Fig. 8. Viewing the MVA methods shown in Fig. 7 in map view. 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. Tracer emplaced in the reservoir are also measured in surface soil gas samples, and water sampled from the overlying Ogallala aquifer.
5. Simulation Studies The SWP uses a variety of numerical simulators to understand the complex coupled subsurface processes associated with injecting CO2 and water into Farnsworth for CCUS. The SWP is also assisting in developing a scientific numerical simulator with fully coupled multi-fluid hydrologic, heat transport, reactive transport and geomechanics capabilities (STOMP-EOR [6]). This simulator is specifically designed as a research tool, allowing scientists and engineers to explore models for three-phase relative permeability, mixed wettability capillary pressure-saturation functions, and compositional fluid phase behavior. The reservoir is also simulated using Schlumberger’s Petrel for model calibration and full field history matching. The comprehensive simulation model utilizes up-to-date versions of the geologic model and interpreted rock and fluid properties from core and log data. These increasingly complex models facilitate risk assessment and evaluation of storage capacity, injectivity, CO2 fate, CO2 transport, and trapping mechanisms. The model is revised each year after the newest geologic model is delivered, and has feedback from the project as new data are obtained from MVA efforts, injection and production data are updated, and as geologic and reservoir data are obtained and studied. 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. After the new simulation model is created each year, the first step is to accurately history match primary, secondary, and tertiary processes including oil, water, and gas production (Fig.9). Predictions can also be made of CO2 saturation and sweep efficiency. Fig. 10 shows predicted CO2 saturation in the Morrow reservoir through July of 2016. Geomechanics and rock fluid interactions are also studied 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 [7].
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Fig. 9. The oil match for the 2016 simulation model. 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.
Fig. 10. Predicted CO2 saturation in the Morrow B reservoir through July of 2016. The large east-west fault offsets the reservoir and impacts fluid flow.
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6. Risk Assessment Risk management focuses on two primary aspects (1) programmatic risks, including resource and management risks that may impede project progress or costs, and (2) sequestration (technical) risks inherent to the scientific and engineering objectives of the project. A risk prevention and mitigation analysis has been completed for the 50 most significant features, events, and processes (FEPs) that could impact the project, and this FEP analysis is updated each year. Risk assessment to date has focused much on reservoir heterogeneity and associated impacts on forecasted risks of the top 10 FEP’s. Quantitative results include predicted probability density functions for the top 10 FEP’s, estimated using MonteCarlo-based methods, including response surface methods and polynomical chaos expansion for surrogate (reduced order) models (SRMs or ROMs) calibrated by conventional reservoir models. Developed ROMs were used to evaluate the relative roles of key flow and operational parameters that drive CO 2 – water – oil transport behavior in the field. For example, Monte Carlo simulation results were assigned as input values for a global sensitivity analysis to evaluate conditions that would maximize cumulative oil production and net CO 2 injection [8]. Results of this analysis suggests that net CO2 injection is most sensitive to reservoir permeability, the time ratio of water- CO2 alternating injection rates (WAG), and the distance between injection and production wells. As an example, Fig. 11 plots cumulative oil production and net CO2 injection versus well spacing distance, with a spacing of just under 300 m providing optimum production associated with maximum net CO2 injection of ~2 Mt over a 5-year duration of the Farnsworth field. Specifically, for this site, to maximize both oil production and CO2 injection, injection wells should be located about 300 m from the production well. Shorter injection distances would produce more injected CO2 from the production well, also resulting in reduced cumulative oil production and reduced net CO2 storage. Additional risk and uncertainty analysis results suggest that model uncertainty and parameter (data) uncertainty play significant separate roles with respect to risk potential. Other outcomes to date include forecasted uncertainty associated with estimated storage capacity, modelling potential chemical impacts on groundwater quality from hypothetical leakage through well-bore cements; examining how different models for relative permeability and associated hysteresis impact uncertainty; and evaluation of possible impacts (risks) of pressure buildup.
Fig. 11. Results of a Monte-Carlo-based sensitivity analysis to evaluate conditions to maximize both cumulative oil production and net CO2 storage for the Farnsworth field [8].
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7. CO2 Accounting An important component of the project is to account for the fate of injected CO2 (Figs. 12-13), as the primary project goal is to permanently store 1 million metric tonnes of CO2 during the EOR process. Fig. 12 shows monthly CO2 accounting since monitoring of injection began in October 2013. Overall more than 92% of CO2 injected has remained in the system. During the first 21 months (October 2013–June 2015) of injection phase monitoring, 461,000 tonnes of CO2 were stored. Since injection began in 2010, 901,556 tonnes have been stored at Farnsworth. Fig. 13 shows cumulative injection including the 479,178 tonnes injected between December 2010 and October 2013. Losses due to flaring as Farnsworth recycling infrastructure was developed account for all CO2 that was not stored. Fig. 14 highlights an important aspect of CCUS, the motive for producers to become involved in storage projects. Fig. 14 shows oil production and CO2 injection rates with the field and illustrate production 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. It is interesting to note that the initial production response occurred within 6 months.
Fig. 12. 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).
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Fig. 13. Cumulative values for features shown in Figure 12.
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8. Conclusions The DOE’s Carbon Storage Program is tasked with developing technologies to safely and permanently store CO2 and reduce greenhouse gas emissions without adversely affecting energy use or hindering economic growth. The programmatic goals of storage research are to (1) develop and validate technologies to ensure 99 percent storage permanence; (2) develop technologies to improve reservoir storage efficiency while ensuring containment effectiveness; (3) support industry’s ability to predict CO2 storage capacity in geologic formations to within 30 percent; and (4) develop Best Practices Manuals (BPMs) for monitoring, verification, accounting, and assessment; site screening, selection, and initial characterization; public outreach, well management activities, and risk analysis and simulation. A key goal of the SWP effort at Fansworth is to demonstrate the importance of successful reservoir characterization, modeling, monitoring, and the ability to track injection and fate of 1 million metric tons of CO2 for combined EOR and storage at a mature and active oil field. This work first concentrated on geologic and reservoir characterization and then on accurately predicting and monitoring CO2 movement and storage within, and recovery from, the reservoir, for the duration of the project and nearly 1,000 years into the future. To understand long term storage simulation and a comprehensive risk analysis has been performed, and updated annually. Characterization and modeling efforts are used to continuously improve models of the reservoir and overlying seals. Understanding reservoir lithology, heterogeneity, and architecture is necessary for prediction of fluid flow, sweep efficiency, oil recovery, and storage potential and contributes to the understanding of similar geologic settings worldwide. Monitoring technologies are being compared and contrasted during and after injection of CO2 and these monitoring efforts can be used to determine the fate of injected CO2. A goal of the project is to identify the most effective and least expensive monitoring technologies, and to describe them for best practices manuals. Additionally, these studies improve our understanding of reactive transport of CO2 in EOR projects through detailed laboratory studies and modeling, ideally reducing the expense of monitoring of CO2 in future CCUS projects. Characterization and monitoring efforts have generated baseline data for CO2 flux, ground water quality, surface seismic, and have contributed to development of geologic models, reservoir performance, and risk prior to CO 2 injection. Updates to data and models are developed annually and incorporate monitoring data and refined interpretation from monitoring gas and fluids during injection operations. These data and interpretations support modeling efforts, the MVA program, and simulation and risk assessment studies.
9. Acknowledgements 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 has been provided by site operator Chaparral Energy, L.L.C. and Schlumberger Carbon Services. The authors gratefully acknowledge 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. 10. Disclaimer This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by
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the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. 11. References [1] Modified from http://energy.gov/fe/science-innovation/carbon-capture-and-storage-research/regional-partnerships [2] Balch, R., and B. J. McPherson (2016): ”Integrating Enhanced Oil Recovery and Carbon Capture and Storage Projects: a Case study at Farnsworth Field, Texas,” paper SPE 180408-MS presented at 2016 SPE Western Region Meeting, Anchorage AK, May 23-26 [3] Ball, M., Henry, M., and Frezon, S., (1991): “Petroleum Geology of the Anadarko Basin Region, Province (115), Kansas, Oklahoma, and Texas”, USGS Open File report 88450W, 38pp. [4] Ampomah, W., Balch, R. S., Rose-Coss, D., Hutton, A., Cather, M., and Will (2015): “An Integrated Approach for Characterizing a Sandstone Reservoir in the Anadarko Basin” paper OTC-26952. Offshore Technology Conference Houston, Texas, USA. May 2-5, 2016 [5] Rose-Coss, D., Ampomah, W., Balch, R. S., Cather, M., Mozley, P., and Rasmussen, L. (2016):”An Improved Approach for Sandstone Reservoir Characterization,” paper SPE 180375-MS presented at 2016 SPE Western Region Meeting, Anchorage AK, May 23-26 [6] White M.D., B.J. McPherson, R.B. Grigg, W. Ampomah, and M.S. Appold. 2014. “Numerical simulation of carbon dioxide injection in the western section of the Farnsworth Unit.” Energy Procedia, 63:7891-7912. doi:10.1016/j.egypro.2014.11.825 [7] Haar, K., and R. S. Balch (2016): ”Fluid Substitution Modeling to Determine Sensitivity of Time-Lapse 3-D Vertical Seismic Profile Data to Injected CO2,” abstract, presented at AAPG annual Convention and Exhibition, Alberta Canada, June 19-22 [8] Dai, Z., Viswanathan, H., Fessenden-Rahn, J., Middleton, R., Pan, F., Jia, W., Lee, S., McPherson, B., Ampomah, W., and Grigg, R.(2014): “An integrated framework for optimizing CO2 sequestration and enhanced oil recovery”, Environmental. Science. Technology. Letters, 2014a, 1, p. 49-54.
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13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland
Overview of a Large Scale Carbon Capture, Utilization, and Storage Demonstration Project in an Active Oil Field in Texas, USA Robert Balcha*, Brian McPhersonb, and Reid Grigga a
New Mexico Institute of Mining and Technology, 801 Leroy Place, Socorro, New Mexico 87801, USA b University of Utah, 201 Presidents Cir, Salt Lake City, Utah 84112, USA
Abstract The Southwest Regional Partnership on Carbon Sequestration (SWP) is one of seven large scale CO 2 sequestration projects sponsored by the U.S. Department of Energy. The primary objective of the SWP effort, currently in its demonstration stage, is to exhibit and evaluate an active commercial-scale carbon capture, utilization and storage (CCUS) operation, and demonstrate associated effective site characterization, monitoring, verification, accounting, and risk assessment. The SWP has monitored storage of 461,040 metric tonnes of CO2 between October, 2013 and June, 2016 into 16 active patterns. At least 1 million metric tonnes of CO2 will be stored prior to completion of the study. The SWP project is located within an active EOR field, a mature waterflood in the Farnsworth Unit, Texas, which is undergoing conversion to a CO 2 flood. All CO2 utilized by the project is anthropogenic, sourced from a fertilizer and an ethanol plant, and this CO2 would otherwise be vented to the atmosphere. Much of the injected CO2 will be trapped permanently in the subsurface, and a primary objective is to quantify CO2 storage capacity and study conditions and characteristics that promote trapping. This project will contribute to the development of future commercial CCUS projects in the United States by demonstrating all aspects of an actual commercial CCUS field operation, including effective reservoir engineering, monitoring, and simulation technologies. The project has acquired multiple data sets for site characterization, monitoring CO2 plume growth, and storage security. Surface and near-surface monitoring methods used to evaluate CO2 migration out of the reservoir, have verified that CO2 leakage to the surface and/or groundwater has not occurred through September of 2016. As the SWP acquires data for each major area of study (characterization, monitoring, simulation, and risk), information and feedback are acquired to improve the work in other focus areas. A conscious effort is made to discern aspects of the work that can contribute to Department of Energy Best Practices Manuals for carbon sequestration, in particular as it relates to CCUS projects. This paper presents the SWP project, its current status, and progress towards primary goals.
* Corresponding author. Tel.: +1-575-835-5305; fax: +1-575-835-6305. E-mail address: [email protected]
1876-6102 © 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. doi:10.1016/j.egypro.2017.03.1725
Robert Balch et al. / Energy Procedia 114 (2017) 5874 – 5887 © 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license © 2017 The Authors. Published by Elsevier Ltd. (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. Peer-review under responsibility of the organizing committee of GHGT-13. Keywords: CO2-EOR; Sequestration; Carbon Storage; MVA; Simulation; Risk; Characterization
1. Introduction The Southwest Regional Partnership on Carbon Sequestration (SWP) is one of seven organizations performing large scale demonstration projects funded by the US Department of Energy. Each project covers a major region of the USA and/or Canada and focuses on studying regional storage potential, tabulating point sources of CO 2, and studying aspects of carbon storage via demonstration projects within their respective regions. Fig. 1a shows the mapped areas for each regional partnership. Blue drops signify the location of saline aquifer storage projects, and black drops show the approximate location of large scale Carbon Capture, Utilization and Storage (CCUS) demonstration projects. Each regional partnership was tasked with demonstrating the storage of 1 million metric tonnes of CO 2 into a project site within their region, and contributing to best practices for storage in aquifers and oil fields. This paper focuses on the SWP, and its associated region in the southwestern USA (Fig. 1b). The SWP is a consortium of three universities, three national laboratories, service companies, and operating partners including Chaparral Energy, LLC which operates eight CO2 EOR projects utilizing man-made CO2. Farnsworth Unit is the location of the SWP’s large scale demonstration project.
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Fig. 1. (a) U.S Department of Energy Regional Carbon Sequestration Partnerships. Black drops show the approximate location of large scale CO2 EOR / sequestration demonstration projects, blue drops show saline aquifer injection sites [1]. (b) The seven-state region covered by the Southwest Partnership on CO2 Sequestration. The geographic extent of the Anadarko basin is the hatched area in Oklahoma and Texas. The approximate location of Farnsworth Unit is indicated within the Anadarko basin [2].
1.1. Project Description The SWP Farnsworth project covers three phases of research; pre-injection, injection, and post-injection. The preinjection phase studied existing data to determine what additional information was needed and also established baseline data for monitoring injected CO2 in the subsurface and for verifying storage security at the surface. The preinjection study at Farnsworth focused on patterns that had not yet had CO 2 injection as the site was already an active enhanced oil recovery project when the SWP baseline study began. At the time of this paper, the project was in the injection period, and active project roles were data interpretation, evaluation of potential risks, design and development of monitoring, verification and accounting (MVA) plans; and injection of CO2 until the target goal of at least 1 million metric tonnes of net CO2 has been stored. The injection period study can be summarized as a continuous evaluation
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of characterization and production data to build and evolve a series of geologic models that facilitate reservoir simulation and monitoring programs for evaluating caprock integrity and security. The post-injection period for the Farnsworth project will commence after 1 million metric tons of CO 2 have been stored. During this period SWP will continue to perform MVA activities and track CO2 plume movement; conduct further simulation and risk assessment studies; and refine geologic models for the field site and region, and improve CO 2 storage estimates. 1.2. Field Site The SWP project is located within an active EOR field, a mature waterflood in the Farnsworth Unit, Texas, USA which is undergoing conversion to a CO 2 flood. Farnsworth unit is located in the Anadarko basin, a 70,000 square mile deep structural basin located primarily in northern Texas and Oklahoma (Fig. 1b). The basin has been under development since 1860 [3] and contains significant oil and gas reserves. The Anadarko is a mature oil and gas province and as such is representative of other mature productive basins within the USA and across the world, and has established production and transportation infrastructure in place, along with ongoing exploration and new development. Existing point sources of CO2 in the region, coupled with existing infrastructure and mature fields makes the basin an excellent study area for carbon capture utilization and storage (CCUS) projects. The SWP began studying the site in October of 2013. At the time of this paper, the field had 16 active CO2 injectors and had sequestered 461,040 metric tonnes of CO2 between October, 2013 and June of 2016. Prior to the SWP becoming involved with Farnsworth, an additional 440,516 tonnes were sequestered between October, 2010 and September, 2013 by the site operator, Chaparral Energy, LLC. Chaparral has converted a row of inverted 5-spot patterns to CO2 approximately every year since 2011, making the site an excellent testing facility for CO 2 monitoring technologies since each new row of injectors provides a new opportunity to record zero CO 2 baseline data, mid-flood data, and data from fully flooded patterns. All CO2 injected at Farnsworth project has been delivered from two anthropogenic sources, the Agrium Fertilizer Plant at Borger, Texas, USA and the Arkalon Ethanol Plant at Liberal, Kansas, USA (Fig. 2). Injected CO2 is being trapped in the subsurface in the Morrow B formation. The site operator is injecting CO2 in the center well of five-spot well patterns. The project started with three patterns in December 2010, with additional patterns added as recycled CO2 becomes available. As of September of 2015, there were 16 operating patterns (Fig. 3) and the eventual goal is to have a total of 25 patterns emplaced in the western half of Farnsworth unit. The operator injects anthropogenic CO2 at a rate of about ~518 tonnes/day or ~190,000 tonnes/year. SOU TH WE ST CAR BON PA R T N E R S H I P REGION
Legend Utiilization & Storage Carbon Capture Transportation Oil Fields
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Fig. 2. Over 100 miles of pipeline connect two sources to three projects and could be extended to several more fields in the area. Grey shaded portions of the map show oil fields in the vicinity of the two point sources of CO2. Chaparral can vary delivery rates for operational flexibility.
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Figure 3. Current and near future pattern conversion to CO2 injection. Development uses invert 5-spot patterns with a central CO2 injector surrounded by four producers on approximately a 40 acre spacing.
2. Methods The SWP work plan established surface and subsurface monitoring baseline data in patterns that had not yet seen CO2, while studying already active patterns to aid in tool calibration and geologic understanding. Primary objectives of the project are reservoir characterization; reservoir modeling; monitoring, verification, and accounting of injected CO2; and business and geologic risk analyses. CO2 injection and production volumes are tracked in all wells in the unit to allow for a complete material balance to determine the mass of CO2 stored in the reservoir over the course of the project. Two patterns in the west half and one pattern in the east half of Farnsworth were selected as focal points of the demonstration project (Fig. 4). Existing data, production/injection history, a project-acquired 3D surface seismic survey, and ongoing flow simulations, were acquired and studied. Added value from the intensive studies in those patterns is an increased understanding of the entire unit. Project goals encompassing all three phases of work include: (1) Demonstration of injection of 100% anthropogenically sourced CO2: Using CO2 sourced from a fertilizer plant and an ethanol plant makes this project relevant to smaller, non-coal CO2 emission sources that are both common and widely distributed in oil producing regions world-wide. (2) Development of “best practices”: By studying a new set of injection wells that are transitioning to CO2 flood as needed, the effectiveness of monitoring technologies may be ascertained. (3) Demonstration of coupled reservoir model simulation and geologic model development for continuously improving characterization and MVA design: integration of reservoir simulation results with geologic models constructed using the 3D surface seismic survey, three baseline 3D-VSP surveys centered on injection wells, four cross-well baseline surveys and repeat seismic acquisition all contribute to continuously evolved reservoir models and improved seismic interpretations. (4) Understanding storage capacity and determination of modes of trapping: A continuous material balance, yield a “cradle to grave” lifecycle illustration of the EOR-CCUS processes.
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(5) Integration of characterization studies with simulation, risk assessment and MVA: Using results of seismic, log, core, and production data provides a comprehensive surface to injection zone reservoir analysis The project as a whole is broadly divided into four categories: Characterization, Simulation, Monitoring, and Risk. Results for each study area are iterative, integrated, and frequently encompass more than one category.
Fig. 4. Seismic data has been an integral part of the characterization program and includes a baseline 42 mi 2 3D survey over the entire field, three baseline 3D VSPS centered on injection wells, and four baseline cross-well tomography segments between injector/producer pairs. In addition, a dedicated monitoring well has a 16 level 3component passive seismic monitoring array installed within it [2].
3. Geologic and Geophysical Characterization The project has acquired multiple data sets for site characterization, monitoring CO 2 plume growth, and storage security. The project drilled, logged, and collected 750 ft of core from three characterization wells which allowed detailed geologic characterization, studies of rock mechanics in reservoir and seal units, and lab studies of relative permeability. The SWP also conducted and analyzed a full-field 3D surface seismic survey, three 3D-VSP baseline surveys, four crosswell seismic baseline surveys, and repeat surveys for one 3D-VSP and two crosswell seismic surveys (Fig. 4). Each year an updated fine-scale geologic model is produced and distributed for simulation analyses necessary for effective risk assessment and for increased resolution of monitoring, verification and accounting tasks. The evolution of this model can be observed by comparing permeability estimates from an early model (Fig. 5) to more current results shown in Fig. 6. Annual geologic models directly impact simulation efforts focused on historymatching the entire field, reactive transport modeling, CO2 capacity estimation, quantification of seal integrity, and ultimately forecasting the fate of the CO2 plume 100 years or more post-injection. The 3D VSP and cross-well data with repeat surveys have allowed for direct comparisons of the reservoir prior to CO 2 injection and at eight months into injection, with a goal of periodically imaging the CO2 plume as it migrates away from injection wells. Additional repeat surveys at regular intervals will continue to refine direct CO 2 imaging as production and injection data are integrated with newly acquired and interpreted data, and as models are regularly updated. One ultimate goal of subsurface characterization and interpretation is the development of a 3D, fully coupled process model of the injection site. Geologic, and in turn, simulation models, are based on information obtained from baseline data and ongoing collected data from pre-monitoring efforts, including drilling activities, seismic surveys, and sample analyses.
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Fig. 5. Statistically derived permeability distribution for Farnsworth. The data was incorporated into the 2015 version of the geologic/simulation model [4].
Fig. 6. Average permeability of Morrow B interval in an improved geologic model incorporating interpreted faults and hydraulic flow units [5]. 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 Morrow formation. This data was used in the 2016 version of the geologic model.
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4. Near Surface Monitoring The SWP has also acquired significant surface data for monitoring and characterization including soil flux and eddy covariance tower measurements for surface flux detection; subsurface data include baseline and repeat crosswell seismic surveys, a borehole passive seismic array to monitor for induced seismicity, distributed temperature arrays to measure variations in borehole temperature, and bottom-hole pressure and temperature sensors to monitor subsurface movement of CO2 (Figs. 7-8) These surface and near-surface monitoring methods are used to evaluate CO2 migration out of the reservoir. CO2 soil flux measurements from more than 90 surface locations are recorded quarterly and compared to baseline data collected monthly during the first year of observation. In addition, an eddy covariance tower is located on site to monitor atmospheric CO2 flux and identify any potential point-source leakage (e.g. wellbores). Other Farnsworth Unit monitoring focuses on drinkable groundwater chemistry, reservoir fluids chemistry, and aqueous- and gas-phase tracer studies. The regular CO2 soil and eddy flux, aqueous- and vapor-phase tracer, and groundwater chemistry studies have only shown seasonal variations and have verified that CO2 (or reservoir fluid) leakage to the surface and/or groundwater has not occurred through September of 2016.
Fig. 7. Direct monitoring strategy at the Farnsworth Unit incorporating numerous surface and subsurface approaches [2].
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Fig. 8. Viewing the MVA methods shown in Fig. 7 in map view. 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. Tracer emplaced in the reservoir are also measured in surface soil gas samples, and water sampled from the overlying Ogallala aquifer.
5. Simulation Studies The SWP uses a variety of numerical simulators to understand the complex coupled subsurface processes associated with injecting CO2 and water into Farnsworth for CCUS. The SWP is also assisting in developing a scientific numerical simulator with fully coupled multi-fluid hydrologic, heat transport, reactive transport and geomechanics capabilities (STOMP-EOR [6]). This simulator is specifically designed as a research tool, allowing scientists and engineers to explore models for three-phase relative permeability, mixed wettability capillary pressure-saturation functions, and compositional fluid phase behavior. The reservoir is also simulated using Schlumberger’s Petrel for model calibration and full field history matching. The comprehensive simulation model utilizes up-to-date versions of the geologic model and interpreted rock and fluid properties from core and log data. These increasingly complex models facilitate risk assessment and evaluation of storage capacity, injectivity, CO2 fate, CO2 transport, and trapping mechanisms. The model is revised each year after the newest geologic model is delivered, and has feedback from the project as new data are obtained from MVA efforts, injection and production data are updated, and as geologic and reservoir data are obtained and studied. 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. After the new simulation model is created each year, the first step is to accurately history match primary, secondary, and tertiary processes including oil, water, and gas production (Fig.9). Predictions can also be made of CO2 saturation and sweep efficiency. Fig. 10 shows predicted CO2 saturation in the Morrow reservoir through July of 2016. Geomechanics and rock fluid interactions are also studied 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 [7].
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Fig. 9. The oil match for the 2016 simulation model. 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.
Fig. 10. Predicted CO2 saturation in the Morrow B reservoir through July of 2016. The large east-west fault offsets the reservoir and impacts fluid flow.
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6. Risk Assessment Risk management focuses on two primary aspects (1) programmatic risks, including resource and management risks that may impede project progress or costs, and (2) sequestration (technical) risks inherent to the scientific and engineering objectives of the project. A risk prevention and mitigation analysis has been completed for the 50 most significant features, events, and processes (FEPs) that could impact the project, and this FEP analysis is updated each year. Risk assessment to date has focused much on reservoir heterogeneity and associated impacts on forecasted risks of the top 10 FEP’s. Quantitative results include predicted probability density functions for the top 10 FEP’s, estimated using MonteCarlo-based methods, including response surface methods and polynomical chaos expansion for surrogate (reduced order) models (SRMs or ROMs) calibrated by conventional reservoir models. Developed ROMs were used to evaluate the relative roles of key flow and operational parameters that drive CO 2 – water – oil transport behavior in the field. For example, Monte Carlo simulation results were assigned as input values for a global sensitivity analysis to evaluate conditions that would maximize cumulative oil production and net CO 2 injection [8]. Results of this analysis suggests that net CO2 injection is most sensitive to reservoir permeability, the time ratio of water- CO2 alternating injection rates (WAG), and the distance between injection and production wells. As an example, Fig. 11 plots cumulative oil production and net CO2 injection versus well spacing distance, with a spacing of just under 300 m providing optimum production associated with maximum net CO2 injection of ~2 Mt over a 5-year duration of the Farnsworth field. Specifically, for this site, to maximize both oil production and CO2 injection, injection wells should be located about 300 m from the production well. Shorter injection distances would produce more injected CO2 from the production well, also resulting in reduced cumulative oil production and reduced net CO2 storage. Additional risk and uncertainty analysis results suggest that model uncertainty and parameter (data) uncertainty play significant separate roles with respect to risk potential. Other outcomes to date include forecasted uncertainty associated with estimated storage capacity, modelling potential chemical impacts on groundwater quality from hypothetical leakage through well-bore cements; examining how different models for relative permeability and associated hysteresis impact uncertainty; and evaluation of possible impacts (risks) of pressure buildup.
Fig. 11. Results of a Monte-Carlo-based sensitivity analysis to evaluate conditions to maximize both cumulative oil production and net CO2 storage for the Farnsworth field [8].
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7. CO2 Accounting An important component of the project is to account for the fate of injected CO2 (Figs. 12-13), as the primary project goal is to permanently store 1 million metric tonnes of CO2 during the EOR process. Fig. 12 shows monthly CO2 accounting since monitoring of injection began in October 2013. Overall more than 92% of CO2 injected has remained in the system. During the first 21 months (October 2013–June 2015) of injection phase monitoring, 461,000 tonnes of CO2 were stored. Since injection began in 2010, 901,556 tonnes have been stored at Farnsworth. Fig. 13 shows cumulative injection including the 479,178 tonnes injected between December 2010 and October 2013. Losses due to flaring as Farnsworth recycling infrastructure was developed account for all CO2 that was not stored. Fig. 14 highlights an important aspect of CCUS, the motive for producers to become involved in storage projects. Fig. 14 shows oil production and CO2 injection rates with the field and illustrate production 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. It is interesting to note that the initial production response occurred within 6 months.
Fig. 12. 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).
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Fig. 13. Cumulative values for features shown in Figure 12.
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8. Conclusions The DOE’s Carbon Storage Program is tasked with developing technologies to safely and permanently store CO2 and reduce greenhouse gas emissions without adversely affecting energy use or hindering economic growth. The programmatic goals of storage research are to (1) develop and validate technologies to ensure 99 percent storage permanence; (2) develop technologies to improve reservoir storage efficiency while ensuring containment effectiveness; (3) support industry’s ability to predict CO2 storage capacity in geologic formations to within 30 percent; and (4) develop Best Practices Manuals (BPMs) for monitoring, verification, accounting, and assessment; site screening, selection, and initial characterization; public outreach, well management activities, and risk analysis and simulation. A key goal of the SWP effort at Fansworth is to demonstrate the importance of successful reservoir characterization, modeling, monitoring, and the ability to track injection and fate of 1 million metric tons of CO2 for combined EOR and storage at a mature and active oil field. This work first concentrated on geologic and reservoir characterization and then on accurately predicting and monitoring CO2 movement and storage within, and recovery from, the reservoir, for the duration of the project and nearly 1,000 years into the future. To understand long term storage simulation and a comprehensive risk analysis has been performed, and updated annually. Characterization and modeling efforts are used to continuously improve models of the reservoir and overlying seals. Understanding reservoir lithology, heterogeneity, and architecture is necessary for prediction of fluid flow, sweep efficiency, oil recovery, and storage potential and contributes to the understanding of similar geologic settings worldwide. Monitoring technologies are being compared and contrasted during and after injection of CO2 and these monitoring efforts can be used to determine the fate of injected CO2. A goal of the project is to identify the most effective and least expensive monitoring technologies, and to describe them for best practices manuals. Additionally, these studies improve our understanding of reactive transport of CO2 in EOR projects through detailed laboratory studies and modeling, ideally reducing the expense of monitoring of CO2 in future CCUS projects. Characterization and monitoring efforts have generated baseline data for CO2 flux, ground water quality, surface seismic, and have contributed to development of geologic models, reservoir performance, and risk prior to CO 2 injection. Updates to data and models are developed annually and incorporate monitoring data and refined interpretation from monitoring gas and fluids during injection operations. These data and interpretations support modeling efforts, the MVA program, and simulation and risk assessment studies.
9. Acknowledgements 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 has been provided by site operator Chaparral Energy, L.L.C. and Schlumberger Carbon Services. The authors gratefully acknowledge 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. 10. Disclaimer This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by
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the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. 11. References [1] Modified from http://energy.gov/fe/science-innovation/carbon-capture-and-storage-research/regional-partnerships [2] Balch, R., and B. J. McPherson (2016): ”Integrating Enhanced Oil Recovery and Carbon Capture and Storage Projects: a Case study at Farnsworth Field, Texas,” paper SPE 180408-MS presented at 2016 SPE Western Region Meeting, Anchorage AK, May 23-26 [3] Ball, M., Henry, M., and Frezon, S., (1991): “Petroleum Geology of the Anadarko Basin Region, Province (115), Kansas, Oklahoma, and Texas”, USGS Open File report 88450W, 38pp. [4] Ampomah, W., Balch, R. S., Rose-Coss, D., Hutton, A., Cather, M., and Will (2015): “An Integrated Approach for Characterizing a Sandstone Reservoir in the Anadarko Basin” paper OTC-26952. Offshore Technology Conference Houston, Texas, USA. May 2-5, 2016 [5] Rose-Coss, D., Ampomah, W., Balch, R. S., Cather, M., Mozley, P., and Rasmussen, L. (2016):”An Improved Approach for Sandstone Reservoir Characterization,” paper SPE 180375-MS presented at 2016 SPE Western Region Meeting, Anchorage AK, May 23-26 [6] White M.D., B.J. McPherson, R.B. Grigg, W. Ampomah, and M.S. Appold. 2014. “Numerical simulation of carbon dioxide injection in the western section of the Farnsworth Unit.” Energy Procedia, 63:7891-7912. doi:10.1016/j.egypro.2014.11.825 [7] Haar, K., and R. S. Balch (2016): ”Fluid Substitution Modeling to Determine Sensitivity of Time-Lapse 3-D Vertical Seismic Profile Data to Injected CO2,” abstract, presented at AAPG annual Convention and Exhibition, Alberta Canada, June 19-22 [8] Dai, Z., Viswanathan, H., Fessenden-Rahn, J., Middleton, R., Pan, F., Jia, W., Lee, S., McPherson, B., Ampomah, W., and Grigg, R.(2014): “An integrated framework for optimizing CO2 sequestration and enhanced oil recovery”, Environmental. Science. Technology. Letters, 2014a, 1, p. 49-54.
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