Regional Carbon Sequestration Partnership Research Articles

Distilling data to drive carbon storage insights

Wide-spread implementation of carbon capture and storage has the potential to decrease carbon emissions and aid in meeting global climate change mitigation goals. Data availability is one of the biggest challenges faced by the carbon capture and storage (CCS) community for modeling risks associated with CCS, necessary for wide-spread implementation in coming years. Collecting, integrating, and intuitively managing data is a time-consuming process, but one which is fundamental to establishing necessary access to carbon storage data. The US Department of Energy (US DOE) has been a major supporter of energy research in the US, including significant investment into carbon capture and storage research and technology development over the last ten years. The US DOE investments into the Regional Carbon Sequestration Partnerships, the National Risk Assessment Partnership, and other CCS related research has resulted in a large volume of data, of which much has been made public through the National Energy Technology Laboratories data repository, the Energy Data eXchange (EDX). Researchers at the National Energy Technology Laboratory have developed workflows, tools, and other methods that leverage EDX, open-source software, machine learning, and natural language processing to discover, curate, label, organize and visualize available data. This paper describes the available data on EDX for carbon storage applications, describes the results of a spatial and temporal analysis of the data, describes where it is most geographically available, makes a general assessment of the quality of the available data, and discusses visualization tools and natural language processing tools developed for understanding, discovering and reusing the data.

Our Own Backyard: Can Virtual Reality Help Us (And Others) Understand the CCUS Chain?

Carbon capture, utilisation and storage (CCUS) as a set of activities have been undertaken in various forms for many tens of years to separate CO2 from natural gas or for enhanced oil recovery (EOR). The role of CCUS as a tool to mitigate emissions has been increasingly studied and applied, for example at this series of conferences and through coordinated research around the world (e.g. Carbon Capture and Storage Flagship Program in Australia, Regional Carbon Sequestration partnerships in the US, and a whole range of projects in Norway such as Sleipner). The overall value chain and processes typically encompass: • Capture technology (e.g. natural gas clean-up, coal combustion, industrial processes, hydrogen production) • Utilisation (e.g. EOR, production of chemicals, geothermal) • Transportation by pipeline and shipping • Geological storage (aquifer, depleted hydrocarbon fields, EOR, coal, basalts etc.) • Monitoring of storage over the longer term (leakage, environmental impacts) These activities are underpinned by regulatory frameworks, international standards, government policy/legislation and social license to operate. While it is not expected that everyone employed or facing CCUS has expert levels of understanding of all facets of CCUS, few may be familiar or comfortable with the (a) technology (b) footprint (c) scale (d) impacts of the different parts of the CCUS process. How were these observations made? The CSIRO booth at the GHGT-14 Conference in Melbourne (2018) was set up to accommodate two virtual reality (VR) stations with a virtual tour of a carbon capture and storage journey (Figure 1). This was navigated in part by the visitor (i.e. wearing the VR headset) or controlled by the tour guide (operator) or both. The tour provides the visitor with a reasonable proxy for a carbon capture and storage plant. The use of VR can make significant steps in overcoming this lack of built project in the early stages of full-scale development of CCUS (or other large-scale emerging industries) globally. VR could be used in obtaining social license as it could provide much clearer context for community groups where new developments might take place. Some aspects of the tour are highly conceptualized, in particular the space in the base of the well, the diameter of the well bore and the use of bubbles to mimic CO2 movement. Typically, the CO2 would be injected as a supercritical fluid, not bubbles, but that is harder to render for the purposes of the tour. Key observations from running the tours over the course of the conference were that prior to taking part in the VR tour most attendees had not really considered what their levels of understanding of the whole of the CCUS process might be. After the tour they felt much more enlightened and comfortable to discuss those aspects; they understood better the challenges in areas that they were not so familiar with and felt better informed to discuss the different steps in the process with non-specialists. Geological storage has been much more challenging to convey through other imagery, description and information/education [1]. The perception of depth and presence of geological rock overburden as a seal to retard CO2 mobility was therefore much better understood. Areas where the visitor could interact with the location and environment were more engaging and the sense of being transported to another location or environment to interact at a site without induction training, personal protective equipment and no change in climate was not lost on those participating. The tours have now been used in a few Open House activities in relation to the CSIRO In-Situ Laboratory field trial to provide a sense of context for the local community, but a more systematic approach to testing the role of VR tours in social license is required to evaluate this approach as a mechanism to better inform the public of CCUS and its impact locally.

Dynamic modeling to understand pressure response from oil production and CO2 injection in a depleted pinnacle reef reservoir: Manual calibration using simplified resolution of reservoir heterogeneity

The Midwest Regional Carbon Sequestration Partnership has been investigating various reservoir characterization and modeling technologies as part of its commercial-scale implementation of carbon dioxide injection for geologic storage in multiple Silurian carbonate pinnacle reefs in northern Michigan, USA. This paper presents a discussion of the reservoir modeling study that was conducted for history-matching oil production and CO2 injection responses, forecasting CO2 plume migration and estimating associated storage to characterize the closed, depleted Dover-33 reef which has undergone extensive primary and secondary production. Dynamic modeling using equivalent simplified descriptions of reservoir heterogeneity were found to be numerically efficient and successfully explained the observed pressure buildup in the reef during the MRCSP CO2 injection phase. The validated history matched models are extremely useful for potential predictive modeling for considering operational optimization and evaluating subsequent production scenarios relevant to the reef.

The Midwest Regional Carbon Sequestration Partnership petroleum fields database: Compilation, utilization, and support for CCUS activities

The Midwest Regional Carbon Sequestration Partnership petroleum fields database: Compilation, utilization, and support for CCUS activities

Key Findings from the Midwestern Regional Carbon Sequestration Partnership’s (MRCSP) Large-Scale CO2-EOR/Storage Test in Michigan Basin

The Regional Carbon Sequestration Partnership program in the United States, funded by the Department of Energy’s National Energy Technology Laboratory (NETL), is a widely recognized program for advancing Carbon Dioxide Capture, Utilization, and Storage (CCUS) technologies. The Midwestern Regional Carbon Sequestration Partnership (MRCSP) is one such Partnership covering 10 states across midwestern and northeast coastal USA. Since its inception in 2003, MRCSP has completed Phase I (2003-2005) involving assessment of regional emission sources and sequestration sinks and Phase II (2005-2011) involving multiple small-scale pilot tests to evaluate the feasibility of CCUS across the region. Under Phase III, which started in 2009, the MRCSP team has focused on detailed evaluation of a large-scale demonstration project of CO2 Enhanced Oil Recovery (EOR) and associated storage. Work has also continued on the assessment of storage potential across the region by the MRCSP team. This paper provides the overarching final conclusions of the large-scale test and implications for commercial deployment. The test was conducted in the CO2-EOR fields in northern Michigan, in the Silurian age carbonate reef complex, operated by Core Energy, LLC. The CO2 supply for the EOR is from processing of the natural gas from overlying Antrim Shale formation. The CO2 is pipelined about 16 km to the injection wells and a central processing facility. The overall reef complex consists of more than 800 fields, but EOR started in a single field in the mid-1990s and has currently expanded to ten fields. In 2012, MRCSP started a comprehensive program of characterization, measurement, accounting, modeling, and monitoring to research all aspects relevant to CO2 utilization and storage in the complex with a goal of injecting at least 1 million metric tons of CO2. The reef complex includes fields which have undergone EOR (late-stage life cycle), those undergoing EOR (operational), and those where injection is underway sans production (new fields). This allowed MRCSP to deploy an evolving portfolio of characterization, monitoring, and modeling approaches, which could be customized based on individual field settings (geologic, size, production history, well configurations, and EOR plans) and incorporate lessons learned from initial reefs. The large-scale test and the MRCSP Phase II were concluded in 2020 and an extensive set of final technical and topical reports are available for future researchers and commercial CCUs developers. With the conclusion of the MRCSP Program, Battelle has started a new program to enable and accelerate CCUS deployment, called the Midwest Regional Carbon Initiative (MRCI, midwestccus.org), which covers 20 states across midwestern and northeastern US.

Carbon Storage Resource Assessment of the Mid-Atlantic U.S. Offshore Region

Carbon capture and storage (CCS) is a critical technology for ensuring a range of clean energy options are available to meet future energy demands. Offshore storage can be linked to large point-sources of carbon dioxide (CO2) while avoiding many of the logistical difficulties and potential risks encountered when siting onshore projects, especially in densely populated areas of the East Coast of the United States. Offshore storage along mid-Atlantic region was studied under the U.S. Department of Energy (DOE) funded Mid-Atlantic U.S. Offshore Carbon Storage Resource Assessment Project (MAOCSRAP) and as a subtask under the Midwest Regional Carbon Sequestration Partnership (MRCSP). The assessment was conducted as a technical collaboration between Battelle, Rutgers University, Lamont-Doherty Earth Observatory at Columbia University, state geological surveys of Delaware, Maryland and Pennsylvania, United States Geological Survey-Woods Hole Coastal and Marine Science Center, and Harvard University. Major objectives were to complete a systematic carbon storage resource assessment of the of the mid-Atlantic offshore coastal region from the Georges Bank Basin (GBB) through the Long Island Platform (LIP) to the southern Baltimore Canyon Trough (BCT), examine offshore storage risk factors, and engage industry and regulatory stakeholders through development of a Road Map to assist future project planning and implementation. Various publicly available data sets, such as seismic data, well-logs, and core data, were integrated to define geologic characteristics of candidate storage sites and calculate prospective CO2 storage resources for Cretaceous- and Jurassic-age sandstone sequences of the mid-Atlantic offshore sub-regions. The combined dataset helped to identify and map potential storage zones within sequences of the Logan Canyon, Missisauga, and Mohawk formations, as well as the regionally extensive caprock comprised of the Dawson Canyon shale. Prospective storage resource estimates and formation-specific storage efficiency values were calculated with static volumetric and dynamic methods. Regional-scale estimates range from 150 to 1136 gigatonnes (Gt) for the combined storage zones, with high estimated storage resource (≥ 2.4 megatonnes [Mt] CO2/km2) occurring in the northern BCT near the Great Stone Dome (GSD) structure. Results of local scale simplified dynamic reservoir simulation in the GSD indicate that injection rates of 1 Mt CO2/year may be sustained within the time and pressure constraints assumed for a commercial storage project. An initial, qualitative assessment of technical risk factors present in mid-Atlantic offshore areas was conducted. Overall, the mid-Atlantic offshore area benefits from the large spatial extent, thick sequences of sands, lack of previous oil and gas wellbores, and distance from populated development. Geomechanical stability, reservoir variability, and soft sediment deformation were identified as moderate risk factors in some areas. No highly critical risk factors were identified that would impede CO2 storage along the study areas. Input and participation from government, industry, and environmental groups helped to address next steps needed for future CCS project planning and implementation in the study region. Recommended near-term actions are to develop site screening through advanced geologic modeling, implement stakeholder outreach and risk mitigation strategies, identify industry and research goals, and develop regulatory pathways. Recommended mid-term actions are to validate subsurface properties with new data, conduct a cost-benefit analysis, and develop a monitoring, verification, and accounting (MVA) plan. Long term-recommended actions are to implement a plan for large-scale CCS operations using the previous findings, conduct site design, permitting, and construction, and upscale infrastructure. This project represents an important first step by completing a high-level CO2 storage resource assessment and building the knowledge infrastructure necessary to support the development of full-scale offshore carbon storage.

An Assessment of Monitoring Technologies Deployed in Multiple Carbonate Reef Reservoirs at the MRCSP Large-Scale CO2-EOR Site Michigan

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 (MT) of CO2 into a group of Silurian (Niagaran)-age pinnacle reef reservoirs in Otsego County, Michigan (USA) that are operated by Core Energy, LLC [1]. 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 undergone primary production in the 1970s and 1980s; therefore, they offer the opportunity to achieve CO2 storage through enhanced oil recovery (CO2-EOR) (associated storage) and via geologic sequestration (injection alone without production). A key objective of the MRCSP Phase III project was to evaluate the effectiveness of various monitoring technologies for use in associated storage or sequestration projects in the Niagaran pinnacle reefs. Over the period 2013 to 2020, the MRCSP Phase III project conducted monitoring using eleven different 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 study reefs operated by Core Energy. This paper discusses the effectiveness of selected monitoring technologies that had the goal of detecting/delineating the extent of CO2 in the subsurface. The results are relevant to others planning or currently conducting CO2 sequestration or associated storage projects in similar carbonate reef reservoirs.

Modeling Oil Production, CO2 Injection and Associated Storage in Depleted Oil Reservoirs: A Comparison of Approaches

The Midwest Regional Carbon Sequestration Partnership has been investigating various reservoir characterization and modeling technologies as part of its commercial-scale implementation of carbon dioxide injection for geologic storage in multiple Silurian carbonate pinnacle reefs in northern Michigan, USA. This paper compares multiple reservoir modeling approaches for history-matching oil production and CO2 injection responses, and estimating associated storage, to characterize these small spatial footprint depleted reef reservoirs. The three approaches considered are: fully compositional simulation, black-oil with pseudo-miscibility treatment, and capacitance resistance modeling (CRM). Modeling results from three reefs illustrating each modeling approach are presented, and their applicability and limitations with respect to data needs and modeling objectives are discussed.

Nexus of Water and CCS: Findings of the Water Working Group (WWG) of the Regional Carbon Sequestration Partnerships

A Water Working Group (WWG) was formed by the Regional Carbon Sequestration Partnerships (RCSPs) of the U.S. Department of Energy (DOE) in 2009 to identify and address the water-related challenges associated with the commercial deployment of carbon capture and storage (CCS) in the United States. The WWG, which consisted of a team of experts from government, academia, and industry, conducted activities to evaluate CCS process that impact water usage and supplies, identify technology gaps and opportunities, and conduct stakeholder outreach to facilitate data transfer and spur future research activities. The WWG concluded its activities in 2018.

Where is that CO2 flowing? Using Distributed Temperature Sensing (DTS) technology for monitoring injection of CO2 into a depleted oil reservoir

A Distributed Temperature Sensing (DTS) system, along with a five-level, behind-casing pressure sensing array was installed as part of the Midwest Regional Carbon Sequestration Partnership (MRCSP) large-scale carbon dioxide (CO2) storage test in a depleted Niagaran pinnacle reef oil reservoir in Northern Michigan. The reef is being monitored during its initial reservoir fill-up period as CO2 is being injected to raise the reservoir pressure for enhanced oil recovery (EOR). DTS data are analyzed with results from the initial injection of ˜101,000 metric tons of CO2, injected between January 2017 and December 2018. This paper discusses the results of real-time DTS combined with multi-level pressure monitoring. The collection, processing, and interpretation of large amounts of data from fiber-optic-based DTS provides an opportunity to obtain high-resolution information on migration of CO2 in the reservoir.

Pulsed Neutron Capture Logging: Monitoring Co2 Breakthrough in Multiple Co2-Eor Fields

Pulsed neutron capture (PNC) well logging technology was utilized in the large-scale, long-term CO2-EOR Midwest Regional Carbon Sequestration Partnership (MRCSP) to monitor CO2 breakthrough in the Michigan Niagaran reef trend. Comprehensive tool response modeling and assessment of pre- and post-CO2 injection PNC data were performed to evaluate oil, gas, and water saturation changes and potential CO2 breakthrough in monitored reefs. An examination of the different phases of the program and monitoring data are presented.

Assessing geochemical reactions during CO2 injection into an oil-bearing reef in the Northern Michigan basin

The Dover 33 Reef, part of the Niagaran Reef Complex in Northern Michigan (USA), has been the focus of an enhanced oil recovery/carbon capture utilization and storage (EOR/CCUS) project as part of the Phase III-Midwest Regional Carbon Sequestration Partnership (Gupta et al., 2013a,b). The Dover 33 structure has experienced significant CO2 flooding in the past two decades, and over the course of the current injection study (between February 2013 and July 2016) has received approximately 100 to 1000 tonnes/day into the central injection well (L-M) 1–33). As part of the geochemical monitoring effort of the study, gas and fluid samples were collected from Dover 33 reef, and several other nearby reef structures, to assess the impact of CO2 injection on the geochemical processes occurring within in the reef.The injected gas is composed of approximately 95% CO2, with a δ13CCO2 of ∼20.5‰, which is consistent with previously published compositions of Antrim shale gas, the source of the CO2. The concentrations and isotopic compositions of higher pressure gas collected from the L-M 5–33 monitoring well were similar to those measured in the injection well, but did exhibit a small but systematic shift in isotopic composition towards lower values over the course of the study, suggesting mixing and dilution between the gas in the reservoir and the injected gas. In contrast the δ13CCO2 of gas samples from the monitoring well with the lower surface pressure, L-M 2–33, are consistently lower throughout the study, ∼18.5‰, indicating that reactions with the injected CO2 are occurring within the reef or with the well casing.Fluid samples were collected to assess the extent of interaction among the injected gas, the reservoir rock, and the brine. The brine samples are acidic (pH ∼ 4.1 to 4.9) with a total salt content of nearly 400 g/L. Analysis of the isotopic composition of dissolved inorganic carbon (DIC) in the Dover 33 brine shows that δ13C is higher than the injected gas (27–33‰) suggesting that the gas is not in equilibrium with DIC in the brine, and that there has been little isotopic exchange with carbonate minerals in the reef. The water isotope composition of the brine, δ18O and δD, plot below the meteoric water line, indicating that the water is not of recent meteoric origin and has undergone isotopic exchange with both gas and minerals within the reef structure. The 87Sr/86Sr ratios of the brine samples range from 0.70865 to 0.70869, consistent with Silurian seawater composition.Geochemical modelling of the brine composition shows that the predicted CO2 solubility as DIC is much greater than the measured DIC, and that the brines are supersaturated with respect to carbonate minerals, suggesting the potential for significant trapping of CO2 in both dissolved and mineral form.

On the Path to Commercial CCS: Scaling from Field Demonstration to Regional Hub

Commercial-scale industrial Carbon Capture Utilization and Storage (CCUS) has long been an objective to reduce carbon dioxide (CO2) emissions and increase storage and production potential. As a technology, it is deemed critical for achieving CO2 reductions that can lead to Paris Agreement targets for below 2°C global average temperature increases. Many models to mitigate atmospheric CO2 emissions call for CCUS from bioenergy, also known as BECCS, as a significant contributor to help achieve these climate goals. Facilitating the development of commercial-scale projects from industrial sources of CO2 has been a strategic process across multiple phases leading ultimately to a succession of projects of increasing scale in the Central United States. Four major CCS projects in the Illinois Basin region, USA exemplify the strategic pathway defined more than a decade ago by the U.S. Department of Energy – National Technology Laboratory (US DOE). Starting in 2003, the Midwest Geological Sequestration Consortium (MGSC), one of the US DOE Regional Carbon Sequestration Partnerships, has been working to define regional CCUS potential, conducting small enhanced oil and enhanced coalbed methane projects, and conducting a large-scale deep saline CCS storage project. As a direct outcome of the Illinois Basin – Decatur Project (IBDP), a one million tonne storage demonstration, the Illinois Industrial Sources CCS Project (ICCS) has expanded infrastructure and injection potential to industrial commercial-scale. Advancing CCS even further, the CarbonSAFE Macon County and Wabash feasibility projects seek to conduct physical and social site characterization leading to the development of storage complexes with the potential to receive and store over 50 million tonnes of CO2 from single or multiple sources. These projects combined provide an excellent example of how leveraging research, public-private partnerships, resources, relationships, and experience move CCUS forward regionally resulting in infrastructure to support storage and utilization hubs. This paper provides a brief summary of CCUS projects the Illinois Basin region of the US Midwest, and discusses of areas of overlap between projects, as well as the ways in which resources and collaborations have benefitted and challenged the individual projects. Broader lessons are provided to facilitate scale-up with CCS and CCUS deployment throughout the region.

Transport of perfluorocarbon tracers in the Cranfield Geological Carbon Sequestration Project

AbstractA field‐scale carbon dioxide (CO2) injection pilot project was conducted by the Southeast Regional Carbon Sequestration Partnership (SECARB) at Cranfield, Mississippi. Two associated campaigns in 2009 and 2010 were carried out to co‐inject perfluorocarbon tracers (PFTs) and sulfur hexafluoride (SF6) with CO2. Tracers in gas samples from two observation wells were analyzed to construct breakthrough curves. In this work, we present the field data and numerical modeling of the flow and transport of CO2, brine, and tracers. A high‐resolution static model of the formation geology in the detailed area study (DAS) was used to capture the impact of connected flow pathways created by fluvial channels on breakthrough curves and breakthrough times of PFTs and SF6 tracers. We use the cubic‐plus‐association (CPA) equation of state, which takes into account the polar nature of water molecules, to describe the phase behavior of CO2–brine‐tracer mixtures. Our simulated results show good agreement for the 2009 tracer campaign in Cranfield, while a larger discrepancy emerges by 2010. The combination of multiple tracer injection pulses with detailed numerical simulations proves to be a powerful tool in constraining both formation properties and how complex flow paths develop over time. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd.

Verification Well #1: How a Deep Monitoring Well Was Used and Adapted to Meet the Evolving Monitoring Needs and Challenges at the Illinois Basin – Decatur Project

The Illinois Basin – Decatur Project is a one million tonne deep saline geologic carbon dioxide (CO2) storage project led by the Midwest Geologic Sequestration Consortium, one of the United States Department of Energy – National Energy Technology Laboratory’s Regional Carbon Sequestration Partnerships. The project is currently in the post-injection monitoring phase and is using a monitoring well known as Verification Well #1 (VW1) that was drilled to a depth of 2,201 m (7,264 ft). When the well was first completed, it included an experimental Westbay multilevel monitoring system. That system was used for about six years to collect information from 11 monitoring zones including continuous temperature/pressure and 103 fluid samples. In addition, sequential pulsed neutron logging was an essential monitoring tool to identify CO2 presence and assess the evolution of annular, wellbore, and reservoir conditions. Geochemical sampling provided detailed fluid chemistry and helped verify pulsed neutron logging results. VW1 has served as an integral data source to understand the subsurface geology, document pre-injection conditions, evaluate the performance of experimental monitoring systems, monitor responses of the reservoir to injection, provide data for multiple numerical modeling efforts, conduct research on deep brines of the Illinois Basin, and verify containment of injected CO2. During the project, the post-injection monitoring needs for VW1 were increased significantly from 7 years to 22 years. Given the significantly extended timeframe and performance issues with the experimental system, five recompletion options were assessed, and a 3-zone, Baker Hughes intelligent completion system was selected. The recompletion offered a rare opportunity to evaluate the experimental Westbay system and wellbore integrity after six years of service in a highly corrosive environment. Cement integrity across the zones exposed to carbonated fluids appeared to be unchanged. However, localized pitting of the long string casing was observed in sections within the Mt. Simon Sandstone where casing internal yield strength had an estimated average degradation of 25%. Despite the corrosive environment, the specialized well construction materials, including 13Cr casing, proved crucial in maintaining VW1 integrity for continued monitoring purposes. The Baker Hughes system was successfully installed in 2017, and VW1 is scheduled to continue operation through 2032.

U.S. DOE Regional Carbon Sequestration Partnership Initiative: New Insights and Lessons Learned

The U.S. Department of Energy's (DOE) Regional Carbon Sequestration Partnership (RCSP) Initiative was launched in 2003 to advance development and testing of effective carbon dioxide (CO2) storage technologies across the United States. DOE's National Energy Technology Laboratory (NETL) has worked closely with technical experts from the RCSPs to incorporate new findings and lessons learned from the RCSP Development Phase projects into the 2016 Revised Editions of a series of Best Practice Manuals (BPMs) on major topics associated with project implementation. The five 2016 Revised Edition BPMs cover the following topics: Site Screening, Site Selection, and Site Characterization for Geologic Storage Projects; Public Outreach and Education for Geologic Storage Projects; Risk Management and Simulation for Geologic Storage Projects; Monitoring, Verification, and Accounting (MVA) for Geologic Storage Projects; and Operations for Geologic Storage Projects. Taken separately, each topical BPM serves as a practical, stand-alone guide for conducting specific project activities. Taken together, the five BPMs are interrelated and should provide comprehensive and interdisciplinary strategies for conducting successful geologic storage projects from inception to completion.

Interpretation of Tracer Experiments on Inverted Five-spot Well-patterns within the Western Half of the Farnsworth Unit Oil Field

The Southwest Regional Partnership on Carbon Sequestration (SWP), one of the U.S. Department of Energy (U.S. DOE) seven Regional Carbon Sequestration Partnerships, is currently working to demonstrate the utilization and storage of CO2 in the Farnsworth Unit (FWU) Enhanced Oil Recovery (EOR) site under the final development phase of this U.S. DOE initiative. A component of the research is to use fluid tracers to understand the multifluid flow patterns that develop between injection and production wells via collected field data and supporting numerical reservoir models. The FWU, located in the Anadarko Basin, Ochiltree County, Texas, and being operated by Chaparral Energy, is a mature EOR water-flood field, which is currently being converted to a CO2 flow, with inverted 5-spot patterns transitioning from pure water to alternating CO2 and water floods (i.e., water alternating gas (WAG)) at an approximate rate of one every 6 to 10 months. The SWP tracer program is conducting a suite of tracer injections into the active 5-spot patterns at the FWU. Tracers have been selected to be nonreactive and either principally soluble in CO2 (gas soluble) or water (aqueous soluble). In addition to characterizing the multifluid flow behaviour within reservoir, the gas and aqueous tracers have roles in detecting any leakage from the reservoir. A total of seven unique perfluorocarbon tracer (PFT) compounds make up the suite of gas soluble tracers and eight unique naphthalene sulfonate tracer (NPT) compounds comprise the aqueous soluble tracers. All selected tracers are significantly detectable below the parts per billion concentrations, allowing for high resolution for the inter-well tests at relatively low injection volumes.

U.S. DOE/NETL Carbon Storage Program: Advancing Science and Technology to Support Commercial Deployment

Since its inception in 1997, the U.S. Department of Energy's (DOE) Carbon Storage Program, managed by the National Energy Technology Laboratory (NETL), has significantly advanced geologic storage science and technology through a diverse portfolio of applied research projects. The Program is focused on developing and advancing technologies that address the overarching technical challenges of geologic storage, with the goal to achieve technology readiness for widespread commercial deployment in the 2025–2035 timeframe. The Program approaches these challenges through integration of the technologies developed in the “Advanced Storage” component of the Program and field tested in the “Storage Infrastructure” component. The Carbon Storage Program is now well positioned to begin feasibility projects on commercial-scale saline storage complexes, building upon almost two decades of knowledge and experience gained from Storage Infrastructure field projects. An early key milestone was the implementation of the Regional Carbon Sequestration Partnership (RCSP) Initiative. Experience and knowledge gained from these field projects provide a firm foundation for future larger-scale field projects, either onshore or offshore. Perhaps most importantly, it is only by performing these field projects that the knowledge needed to identify additional subsurface reservoir and operational issues still requiring further research can be acquired.

Regionwide Outreach in a Project-level World – Lessons from the PCOR Partnership

Public acceptance is critical to the successful implementation of geologic CO2 storage projects. As such, the U.S. Department of Energy mandated that project-based outreach be included in its regional partnerships as part of its Regional Carbon Sequestration Partnership Initiative. In 2003, the Plains CO2 Reduction (PCOR) Partnership initiated a multifaceted, multilevel outreach program in tandem with its characterization and demonstration activities in the north central portion of North America. This paper discusses the role of outreach in the PCOR Partnership, methods employed, and select lessons learned over 13 years of doing public outreach.

Developing Best Practices for Evaluating Fluid Saturations with Pulsed Neutron Capture Logging Across Multiple Active CO2-EOR Fields

The Midwest Regional Carbon Sequestration Partnership (MRCSP) is leading an extensive study and monitoring effort of large-scale carbon dioxide (CO2) injection and storage during enhanced oil recovery (EOR) in depleted oil fields in the Michigan Niagara Reef Trend. Detailed monitoring of caprock and reservoir zones is vital for understanding oil, gas, and water saturations and potential migration of CO2. Baseline and repeat pulsed neutron capture (PNC) logs were collected as part of the monitoring effort and study for these storage sites. An overview of the development and enhancement of best practices for PNC logging in complex EOR fields is presented.