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Emissions were documented in a greenhouse gas emission life cycle analysis of 22 years of CO2-enhanced oil recovery (CO2-EOR) operations for a site in the Northern Michigan Basin, U.S. At the site,...

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.

Geologic CO2 sequestration and CO2 enhanced oil recovery (EOR) have received significant attention from the scientific community as a response to climate change from greenhouse gases. Safe and efficient management of a CO2 injection site requires spatio-temporal tracking of the CO2 plume in the reservoir during geologic sequestration. The goal of this paper is to develop robust modeling and monitoring technologies for imaging and visualization of the CO2 plume using routine pressure/temperature measurements.The streamline-based technology has proven to be effective and efficient for reconciling geologic models to various types of reservoir dynamic response. In this paper, we first extend the streamline-based data integration approach to incorporate distributed temperature sensor (DTS) data using the concept of thermal tracer travel time. Then, a hierarchical workflow composed of evolutionary and streamline methods is employed to jointly history match the DTS and pressure data. Finally, CO2 saturation and streamline maps are used to visualize the CO2 plume movement during the sequestration process.The power and utility of our approach are demonstrated using both synthetic and field applications. We first validate the streamline-based DTS data inversion using a synthetic example. Next, the hierarchical workflow is applied to a carbon sequestration project in a carbonate reef reservoir within the Northern Niagaran Pinnacle Reef Trend in Michigan, USA. The monitoring data set consists of distributed temperature sensing (DTS) data acquired at the injection well and a monitoring well, flowing bottom-hole pressure data at the injection well, and time-lapse pressure measurements at several locations along the monitoring well. The history matching results indicate that the CO2 movement is mostly restricted to the intended zones of injection which is consistent with an independent warmback analysis of the temperature data.The novelty of this work is the streamline-based history matching method for the DTS data and its field application to the Department of Engergy regional carbon sequestration project in Michigan.

Conventional reservoir monitoring techniques in Carbon Capture & Storage (CCS) and CO2-Enhanced Oil Recovery (EOR) sites include surface and bottomhole pressure and temperature monitoring at injection and monitoring wells, along with flow rate measurements of injected CO2. In this paper, novel monitoring techniques involving a realtime distributed temperature sensing (DTS) system and multi-depth behind-casing pressure and temperature sensors are evaluated at a CO2-EOR reef in the Northern Niagaran Pinnacle Reef Trend (NNPRT). Data from these monitoring technologies are evaluated for the purpose of monitoring bottomhole conditions in response to injection of CO2 at a nearby injection well and monitoring migration of injected CO2 within the storage formation after the monitoring well was converted to an injection well.

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.

A new approach is presented for analyzing bottom hole temperature (BHT) data from CO2 injection projects. The basic premise of the methodology is: (a) during injection, both bottom hole pressure (BHP) and BHT approach quasi-stabilized values, and (b) the ratio of these changes (from ambient conditions) is the same as the ratio of slopes from transient Horner analysis of temperature and pressure data from the subsequent warmback/falloff periods. Once the slope of the pressure Horner plot is estimated from a steady-state temperature-pressure change cross plot and the slope of a temperature Horner plot, the formation permeability can be readily determined. This provides an independent estimate of formation permeability without utilizing transient pressure data.

The MRCSP Michigan Basin Large-Scale Injection Project is evaluating CO 2 storage and utilization in a complex of closed reservoirs at various stages of production and enhanced oil recovery (EOR) life-cycle. Since 2013, MRCSP has successfully injected and monitored the net storage of more than 600,000 metric tons of CO 2 out of the goal of 1 million metric tons. A number of monitoring technologies have been tested, and various modeling approaches are being applied to evaluate CO 2 migration, injectivity, capacity, and containment.

Pressure and rate data are commonly recorded as part of a basic monitoring program in CCS projects. This paper discusses the application of multiple analytical techniques to interpret pressure and rate transient data from CO2 injection and storage operations. The techniques of interest, i.e., injection-falloff analysis, injectivity/productivity index analysis and pressure pulse arrival time analysis, are commonly used in the oil and gas industry to assess reservoir properties, but not well known in the CCS literature (especially the last two). Injection-falloff analysis involves log-log pressure derivative plotting for the falloff data and history-matching of the entire injection-falloff sequence to determine permeability. In the injectivity/productivity index analysis, rate-normalized pressure buildup is plotted against material balance time or ratio of cumulative injection to injection rate to determine the injectivity index (ratio of injection rate to stabilized pressure buildup) which can be related to the permeability-thickness product. The arrival time analysis identifies the arrival of a pressure disturbance (∼0.1 psi change from ambient) to determine the hydraulic diffusivity from which permeability can be estimated. The applicability of these techniques is demonstrated via illustrative examples from multiple wells in different pinnacle carbonate reefs undergoing CO2-EOR in Northern Michigan. The paper ends with a discussion of the relative merits of each interpretive technique, as well as recommendations that could be useful for other field projects.

Although bottom-hole temperature (BHT) data is routinely collected with bottom-hole pressure (BHP) data during CO2 injection in geological storage projects, it is seldom analyzed in a quantitative manner. However, the BHP and BHT signals do exhibit correlated behavior. This study proposes a practical approach for using BHT data from warmback (no injection) periods, in conjunction with the amplitude of BHP and BHT changes during the preceding injection event, to estimate formation permeability. The methodology is demonstrated using data from the AEP Mountaineer project in USA where CO2 injection was carried out into a saline aquifer. Estimated permeability values from the proposed approach are in good agreement with those obtained from transient pressure analysis of BHP data from the falloff period.

The carbon capture and storage (CCS) program at the American Electric Power (AEP) Mountaineer Plant Product Validation Facility (PVF) is a test program to determine the feasibility of on-site capture and geologic storage of carbon dioxide (CO2) at a coal-fired power plant. The injection wells at the AEP Mountaineer Plant are among a select few CO2 injection and storage wells to reach the post-injection site care stage in the carbon capture and storage project lifecycle. The post- injection site care program has been implemented since the cessation of injection to meet permit requirements, ensure wells demonstrate mechanical integrity, and obtain data needed to demonstrate secure and permanent storage. This program includes reservoir pressure monitoring, CO2 plume modeling, shallow groundwater monitoring, and regulatory interaction and reporting. This paper will provide an update on these program activities, including data collection and analysis, as well as share lessons learned with the CCS community.

The Midwest Regional Carbon Sequestration Partnership is conducting a large-scale CO2 injection test in a depleted Niagaran Pinnacle Reef in northern Michigan. The focus of the dynamic modeling task described in this paper is to evaluate the CO2 injectivity and storage capacity of this closed carbonate reef structure. We discuss the history-matching process to characterize the closed reservoir model using primary and secondary recovery data and its validation with the field pressures in the current CO2 injection phase. Two alternative conceptual geologic models of the reef are constructed to evaluate the level of detail necessary to efficiently model dynamic reservoir behavior without compromising geologic accuracy. We find that our initial black oil formulation under-predicts reservoir pressure and hence over-predicts injectivity during the CO2 injection phase. Transition to a compositional model is currently underway to better represent reservoir dynamics by effectively accounting for interphase and intercomponent mass transfer processes. Lessons learned from this exercise can be drawn upon for possible use in injectivity evaluation of other reefs in the region.

Monitoring an appropriate set of performance metrics is an essential part of a reservoir management strategy that seeks to maximize the efficiency of CO2-EOR floods, and benchmark the performance of the reservoir to other fields in the region. While a number of studies have outlined various options for evaluating the performance of the reservoir, many are not applicable to depleted oilfields that are commonly encumbered with limited data availability. As interest in CO2-EOR grows beyond giving new life to old fields, into a means of reducing anthropogenic CO2 emissions, metrics that enable the analyst to assess the storage capacity of the reservoir in addition to oil recovery efficiency have also become increasingly desirable. This paper will present a streamlined set of metrics that meet these objectives, along with their implementation in a dashboard-style presentation. These metrics provide complementary and non-redundant information, and crucially, are still applicable where a paucity of pressure data exists. The analyst is equipped with four groups of critical information. These are (A) flow rate and cumulative production data; (B) EOR performance trends (incremental oil recovery efficiency, CO2 storage efficiency, and net CO2 utilization factor); (C) operational performance trends (voidage replacement ratio and producing CO2-oil ratio); and (D) storage performance trends (incremental oil recovery factor vs. CO2 storage and CO2 storage capacity vs. voidage). To facilitate comparison, all metrics are normalized to percentage of original hydrocarbon pore volume (HCPV) injected. The utility of the selected set of metrics is demonstrated with data obtained from CO2-EOR activities in depleted oilfields of the Midwest Regional Carbon Sequestration Partnership (MRCSP) region. First, a nine-panel dashboard is populated using the metrics discussed for the D-33 reservoir, and will be shown to be useful in: quantifying CO2 storage capacity, highlighting reservoir performance parameters (CO2 breakthrough, oil recovery, voidage-related pressure changes during EOR etc.) and identifying CO2-flood maturity. Second, a four-panel dashboard is displayed as a comparative tool across all reservoirs in the region in order to highlight best and worst performing reservoirs and establish representative ranges for reservoir performance. Both dashboards will be useful when comparing performance against averages published in literature. This work's novelty is attributed to presenting an ideal set of performance metrics by streamlining the numerous options available. A unique dashboard-style presentation is suggested as a means of rapidly assessing oil recovery and CO2-storage performance, and collectively yielding useful insights.