CO2 Enhanced Oil Recovery Research Articles

Advances in Midland Basin Expand Boundaries of CO2 EOR in Marginal Pay Areas

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 200460, “A Case Study of SACROC CO2 Flooding in Marginal Pay Regions: Improving Asset Performance,” by John Kalteyer, SPE, Kinder Morgan, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. As one of the first fields in the world to use carbon dioxide (CO2) in enhanced oil recovery (EOR), the Scurry Area Canyon Reef Operators Committee (SACROC) unit of the Kelly-Snyder field in the Midland Basin of Texas provides a unique opportunity to study, learn from, and improve upon the development of CO2 flood technology. The complete paper reviews the history of EOR at SACROC, discusses changes in theory over time, and provides a look at the field’s future. Field Overview and Development History The first six pages of the paper discuss the field’s location, geology, and development before June 2000, when Kinder Morgan acquired the SACROC unit and took over as operator. Between initial gas injection in 1972 and 2000, approximately 1 TCF of CO2 had been injected into the Canyon Reef reservoir. Since 2000, cumulative CO2 injection has sur-passed 7 TCF and yielded cumulative EOR of over 180 million bbl. The reservoir is a primarily limestone reef complex containing an estimated original oil in place (OOIP) of just under 3 billion bbl. The reservoir ranges from 200 ft gross thickness in the south to 900 ft in the north, where the limestone matrix averages 8% porosity and 20-md permeability. The Canyon Reef structure is divided into four major intervals, of which the Upper Canyon zone provides the highest-quality pay. The field was discovered in 1948 at a pressure of 3,122 psi. By late 1950, 1,600 production wells had been drilled and the reservoir pressure plummeted, settling as low as 1,700 psi. Waterflooding begun in 1954 enabled the field to continue producing for nearly 20 years, at which time the operators deter-mined that another recovery mechanism would be needed to maximize recovery and reach additional areas of the field. The complete paper discusses various CO2 injection programs that were developed and applied—including a true tertiary response from a miscible CO2 flood in 1981—along with their outcomes. Acquisition and CO2-Injection Redevelopment In June 2000 Kinder Morgan acquired the SACROC Unit and took over as operator. Approximately 6.7 billion bbl of water and 1.3 TCF of CO2 had been injected across the unit to that date, but the daily oil rate of 8,700 B/D was approaching the field’s economic limit. An estimated 40% of the OOIP had been produced through the combination of recovery methods that each previous operator had used. Expanding on the conclusions of its immediate predecessor, the operator initiated large-scale CO2-flood redevelopment in a selection of project areas. These redevelopments were based on several key distinctions differentiating them from previous injection operations.

Technology Focus: EOR Operations (June 2021)

A long time ago, my mentor, Farooq Ali, wrote a thought-provoking paper on the unfulfilled promises of enhanced oil recovery (EOR). His essential summary: EOR had not lived up to its hype and full potential. There were more than a hundred methods and techniques proposed, but only a few had succeeded commercially. Fast-forward a few decades and into the new century, and the message and conclusions have not changed. EOR has definitely not lived up to its promise, especially from the big-picture perspective of daily oil production rates. Before the COVID-19 pandemic, the world was producing close to 100 million BOPD. Of this, only approximately 4 million BOPD was coming from EOR, and the bulk of this was from thermal. The numbers pale even when compared with shale oil, which has dominated US oil production during the past decade. So why has EOR failed so spectacularly? The answer is complex—mostly economic, less technical. It is difficult to compete against water (flooding), where the cost of the injectant is practically free. Compare this with EOR, where you have to inject something other than water—either heat, a gas or solvent, polymer, surfactant, or something exotic such as microbes. These techniques cost money and make EOR inherently expensive. They have become the Achilles’ heel of EOR. So, what is the message for those of us working in EOR? Make EOR cost-competitive, improve waterflooding, or join the sustainability bandwagon that is sweeping the world? That is the call of the hour, and for decades to come. While other EOR methods such as thermal and chemical will have a limited future, injection of carbon dioxide (CO2) for EOR will be a win/win proposition. It provides a way to sequester CO2 and produce additional oil at the same time. The oil revenues provide the “U” in “CCUS” (carbon capture, utilization, and storage) that will play a vital role in the removal of CO2. CCUS is considered by most to be an essential part of the climate-change portfolio of solutions. The papers in this feature are examples of CO2 sequestration either with EOR or in saline aquifers. One provides the EOR and storage potential in the Norwegian continental shelf. Another is a case study of improving asset performance in marginal pay regions. The third is an example that capitalizes on the US government’s 45Q tax credits for incentivizing CO2 injection. Our industry has been the custodian of subterranean reservoirs. We are the experts in managing and developing them. Why not use that expertise to find solutions for climate change by capturing and removing carbon and being part of the solution? Recommended additional reading at OnePetro: www.onepetro.org. SPE 200363 Economic Assessment of Strategies for CO2 EOR and Storage in Brownfield Residual Oil Zones: A Case Study From the Seminole San Andres Unit by Bo Ren, The University of Texas at Austin, et al. OTC 30157 Effects of CO2/Rock/Formation Brine Parameters on CO2 Injectivity for Sequestration by Muhammad Aslam Md Yusof, Universiti Teknologi Petronas, et al. SPE 202276 Is Chemical EOR Finally Coming of Age? by Eric Delamaide, IFP Technologies

Analysis of Caprock Tightness for CO2 Enhanced Oil Recovery and Sequestration: Case Study of a Depleted Oil and Gas Reservoir in Dolomite, Poland

This study addresses the problem of geological structure tightness for the purposes of enhanced oil recovery with CO2 sequestration. For the first time in the history of Polish geological survey the advanced methods, practical assumptions, and quantitative results of detailed simulations were applied to study the geological structure of a domestic oil reservoir as a potential candidate for a combined enhanced oil recovery and CO2 sequestration project. An analysis of the structure sequestration capacity and its tightness was performed using numerical methods that combined geomechanical and reservoir fluid flow modelling with a standard two-way coupling procedure. By applying the correlation between the geomechanical state and transport properties of the caprock, threshold pressure variations were determined to be a key factor affecting the sealing properties of the reservoir–caprock boundary. In addition to the estimation of the sequestration capacity of the structure, the process of CO2 leakage from the reservoir to the caprock was simulated for scenarios exceeding the threshold pressure limit of the reservoir–caprock boundary. The long-term simulations resulted in a comprehensive assessment of the total amount of CO2 leakage as a function of time and the leaked CO2 distribution within the caprock.

Vapor-liquid equilibrium and criticality of CO2 and n-heptane in shale organic pores by the Monte Carlo simulation

Thanks to the application of CO2 enhanced oil recovery (EOR) technology in shale oil production, phase behavior of CO2 and alkanes in nanopores has received considerable attention. Understanding the confinement effect on the vapor–liquid equilibrium and critical state of CO2 and alkanes is imperative to the calculation of phase behavior and prediction of oil recovery. In this work, the vapor–liquid equilibrium of pure CO2 and n-heptane (nC7) and their mixtures in shale organic pores are simulated using the Monte Carlo simulation. Compared to the bulk phase, the density of equilibrium gas is larger due to adsorption while the liquid phase density is lower because of capillary condensation. The influence of the confinement effect on the equilibrium phase composition results in the lower bubble point pressure and higher dew point pressure of the binary system. Changes in the equilibrium phase lead to a decrease in the critical temperature and pressure of single-component fluids and the minimum miscible pressure of binary system in nanopores. We fitted the critical property shift and analyzed the influence of pore size on fluid properties such as equilibrium pressure, composition, critical parameters, density distribution, etc. This study provides better insight into vapor–liquid equilibrium and critical state of CO2 and alkane in shale organic pores.

Geochemical reactions and their effect on CO2 storage efficiency during the whole process of CO2 EOR and subsequent storage

CO2-formation water-rock geochemical reactions can occur, affecting the reservoir physical properties and CO2 trapping forms during the CO2 enhanced oil recovery (CO2-EOR) process. In this paper, based on the properties of the reservoir and fluids in a high-temperature oil reservoir, a comprehensive model, including formation water evaporation, dissolution, diffusion of CO2 in water, CO2-water-rock geochemical reactions, and relation of porosity and permeability, is established to simulate the CO2 EOR process and subsequent geological storage. The geochemical reactions and CO2 trapping forms in these two stages are analyzed using this model, and the influences of reservoir heterogeneity and different CO2 injection schemes on EOR and CO2 geological storage are studied. The results show that the geochemical reactions can change reservoir porosity and permeability, but their effect is little, and most of the injected CO2 is trapped as the supercritical gas during the CO2 EOR process. During the stage of CO2 geological storage, the supercritical CO2 continuously converts into mineral form under the action of geochemical reactions, which results in the reservoir pressure decreasing. Whether the reservoir is heterogeneous or homogenous, the water-alternating-gas (WAG) scheme should be the first choice because it can enhance both oil recovery and CO2 storage efficiency in the EOR process. The injection of CO2 after the CO2 EOR process can improve the CO2 storage capacity and simultaneously maintain the reservoir pressure stabilization.

Development of an Integrated Carbon Capture, Utilization, and Storage Hub in the United States

The Integrated Midcontinent Stacked Carbon Storage Hub (IMSCS-HUB) is a first of a kind carbon capture, utilization, and storage (CCUS) project in the midwestern United States. The project is supported under the US Department of Energy’s Carbon Storage Assurance Facility Enterprise (CarbonSAFE) program. The IMSCS-HUB will collect 15 million metric tonnes (MT) per year or more in Iowa and Nebraska and transport it to saline and CO2 enhanced oil recovery (EOR) storage sites in western Nebraska, Kansas, and Texas. Sources include multiple ethanol plants (approximately 1.8 MT/Year), coal fired electric plants (approximately 12.6 MT/Year), and natural gas fired electric plants (approximately 0.6 MT/Year). The passage of an updated tax credit for storage in February 2018 provides a strong economic driver for all of the sources in the hub to develop a hub project. The tax credit provides approximately $50/T for CO2 stored in saline storage units and $35/T for CO2 stored as part of CO2-EOR production. In addition, the inclusion of many bio-energy sources such as ethanol plants allows for early implementation of the project by taking advantage of inexpensive capture ($10/MT to $12/MT) and subsidies from California’s Low Carbon Fuel Standard program. Capture cost estimates for the electric utilities is approximately $33/MT. Transport costs range from $0.6/MT to $5.40/MT. Storage costs range from $3/MT to $4/MT. The hub partners include Battelle, Advanced Resources International, Archer Daniels Midland, Nebraska Public Power District, and others. The region of the project stretching from eastern Iowa to southwestern Nebraska acts as a source corridor, where sources add CO2 to the transport network. The transportation network will consist of a common carrier trunk line designed to connect the largest sources. Smaller sources will be connected through spur lines. The final routing will be selected using the location of existing rights away and environmental factors such as resource locations the critical species habitats. SimCCS and other tools will be used to finalize the routes. The region of the project from southwestern Nebraska to southwest Kansas in a storage corridor where CO2 may be stored in either saline projects or CO2-EOR projects. South of Kansas the CO2 will be transported to Texas for utilization in CO2-EOR. Two saline storage sites and two EOR opportunities have been identified as anchor projects for the storage corridor. The anchor sites are at the northern and southern sides of the storage corridor and will act to validate the storage potential of the entire corridor. In Nebraska saline storage is being planned in Perkins county and CO2-EOR is being studied at Sleepy Hollow Field in Red Willow county. In Kansas, saline storage and CO2- EOR are being planned for Patterson-Heinitz-Hartland (Patterson) Field in Kearney County. Multiple storage formations occur vertically at each site allowing for stacked storage minimizing the surface footprint for monitoring and maximizes the use of storage resources at each site. Data from new tests wells or seismic surveys for each of the sites has been used to create detailed geologic and reservoir models. Modeling for each of the anchor saline sites indicates at least a 50 million tonne storage capacity. The CO2-EOR projects are expected to utilize 2.2 MT and 3.9 MT of CO2 and produce 4.3 and 9.8 million barrels of oil for Sleepy Hollow and Patterson Fields, respectively. The inclusion of CO2-EOR along with saline storage adds an additional economic driver for the project with an estimated revenue of $128/MT and $154/MT of CO2 utilized. The results of the first two phases of the project demonstrate the feasibility of the midcontinent hub concept that couples a diverse set of redundant sources to multiple saline and CO2-EOR projects. The results show that the economics and geology are favorable for early implementation of commercial scale CCUS. The existence of low carbon fuel standard subsidies, storage tax credits, and revenue from produced oil act as economic drivers to support the hub in addition to the climate benefit gained by storing CO2 the hub supports local agriculture and oil production helping to create public support. This presentation will discuss the project development and project economics and how they relate to both stacked saline storage and CO2-EOR in the development of a storage hub. The development of a hub project allows the transport of CO2 from areas such as Iowa that have poor storage potential to areas such as western Nebraska, Kansas, and Texas that have high storage potential. This is critical to the implementation of CCUS in the midcontinent US. The presentation will also discuss the advantage of including redundant sources and sinks to develop a CO2 market that can sustain itself as a commercial enterprise after government funding ends.

A Comprehensive Techno-eco-assessment of CO2 Enhanced Oil Recovery Projects Using a Machine-learning Assisted Workflow

Injection of CO2 gas to partially depleted oil reservoirs not only enhances hydrocarbon production but also take advances of the underground porous media for carbon storage purposes. Therefore, carbon utilization to enhanced oil recovery (EOR) projects become more and more attractive in the petroleum industry. Notably, the use of anthropogenic CO2 in EOR project could be challenging due to the capital and operational costs of carbon capture, transportation, and recycling. In the meantime, the US government offers encouraging tax policies, Section 45 Q, to oil field operators who inject a large volume of CO2 to produce oil. Thus, the project economics of the CO2-EOR project could be even more complex, especially when the oil price is low at this time. In this article, a robust machine-learning assisted CO2-EOR project optimization and design protocol is presented. The workflow aims at simultaneously optimizing the hydrocarbon recovery, carbon storage volume and project economics using a Pareto-front-based multiple-objective optimization (MOO) scheme. A solution repository containing various optimized development strategies will be structured. Moreover, the proposed workflow will investigate the project economics of the solutions by systematically considering impactive factors such as tax credits, project capital costs, oil prices, etc., and provide comprehensive recommendations to the field operators for decision-making purposes. This work employs data collected from the Farnsworth unit (FWU) in west Texas, US, as a field case to demonstrate the workflow. FWU is characterized as partially depleted oil sands undergoing water-alternative-CO2 (CO2-WAG) injection processes. A compositional numerical reservoir simulation model is established to investigate the fluid transportations dynamic of FWU. The numerical model is validated via a rigorous history-matching study using 55-year of primary and secondary (water flooding) recovery data, and 8-year of ternary recovery (CO2-WAG) data. It is worth emphasizing that the history-matched model successfully incorporates eight relative permeability curves to various spatial regions of the field. Such relative permeability curves are measured via laboratory investigations using representative core samples collected from the fields (hydraulic flow units). The history matched numerical model can be used to forecast the hydrocarbon production and CO2 storage volume using different CO2-WAG designs. In order to obtain finer optimization solutions, the field operational parameters, such as water injection rate, gas injection period, water injection periods, production well specifications, etc. of each individual well are considered as control parameters. In this way, the field operators can get detailed guidance to operate each individual well. However, the imposing of MOO requires computationally intensive procedures by totally relying on the high-fidelity numerical simulator, which engages the motivation to employ machine-learning-based proxies in the workflow. In this work, supported vector machine regression (SVR) combined with the Gaussian kernel is utilized to mimic the high-fidelity numerical model. The hyper-parameters of the SVR are optimized using Bayesian Optimization to achieve a better generalization performance. The SVR couples with Multi-objective Particle Swarm Optimization (MOPSO) protocol to structure the Pareto-front solution repository. To further eliminate the uncertainties introduced by the proxy error margins, a self-adapting scheme is integrated into the workflow to justify the Pareto-front solutions. This scheme will automatically add new sampling data to the training dataset for surrogate model development, making the optimization results more correct. Furthermore, this paper will carry comprehensive techno-eco-assessments of the optimized solutions considering the vital economic factors including the carbon capture and transporting costs, field operational cost, tax credits, oil price, etc. With the help of the proxy models, fast uncertainty analysis can be conducted to obtain stochastic results of the project net present value, rate of return and payback period. Field operators can make their decisions to design CO2-WAG projects based on both technical and economical perspectives.

Influence factors on CO2 solubility in cycloalkanes and cycloalkane volume expansion: Temperature, pressure and molecular structure

In CO2 enhanced oil recovery process, the interactions between CO2 and oil components are complex since crude oil is a mixture of n-alkanes, cycloalkanes, aromatics, resin, asphaltene and other compounds. To investigate the effects of temperature, pressure and molecular structure on CO2 solubility in cycloalkanes and the resulting cycloalkane volume expansion, the solubility of near critical and supercritical CO2 in cyclopentane (CP), cyclohexane (CH), methylcyclohexane (MCH), methylcyclopentane (MCP) and ethylcyclohexane (ECH) and the volume expansion factor of cycloalkanes at diverse temperature and pressure were measured. It was observed that increasing temperature decreases CO2 solubility, while CO2 solubility increases with pressure increasing. Compared with CP and CH, it's harder for CO2 to dissolve in their methyl or ethyl substituents. For homologues, CO2 solubility decreases with carbon number increasing. The volume expansion factor and solubility have a same variation tendency with temperature, pressure and molecular structure. The experimental results of solubility were correlated with Fornari's model and PR equation of state with the maximum average absolute relative deviation (AARD) of 2.8% and 6.8%, respectively. The excess molar volume of CO2 + cycloalkane mixtures was calculated to be negative and increases with pressure.

Prediction of CO2 Minimum Miscibility Pressure Using an Augmented Machine-Learning-Based Model

Summary Minimum miscibility pressure (MMP) is one of the key design parameters for gas injection projects. It is a physical parameter that is a measure of local displacement efficiency while subject to some constraints due to its definition. Also, the MMP value is used to tune compositional models along with proper fluid description constrained with other available basic phase behavior data, such as bubble point pressure and volumetric properties. In general, carbon dioxide (CO2) and hydrocarbon gases are the most common gases used for (or screened for) gas injection processes, and because of recent focus, they are used to screen for the coupling of CO2-sequestration and CO2-enhanced oil recovery (EOR) projects. Because the CO2/oil phase behavior is quite different than the hydrocarbon gas/oil phase behavior, researchers developed specialized correlations for CO2 or CO2-rich streams. Therefore, there is a need for a tool with expanded range capabilities for the estimation of MMP for CO2 gas streams. The only known and widely accepted measurement technique for MMP that is coherent with its formal definition is the use of a slimtube apparatus. However, the use of slimtube restricts the amount of data available, even though there are other alternative techniques presented over the last three decades, which all have various limitations (Dindoruk et al. 2021). Due to some of the complexities highlighted in Dindoruk et al. (2021) and time and resource requirements, there have been a number of correlations developed in the literature using mostly classical regression techniques with relatively sparse data using various combinations of limited input data (Cronquist 1978; Lee 1979; Yellig and Metcalfe 1980; Alston et al. 1985; Glaso 1985; Jaubert et al. 1998; Emera and Sarma 2005; Yuan et al. 2005; Ahmadi et al. 2010; Ahmadi and Johns 2011). In this paper, we present two separate approaches for the calculation of the MMP of an oil for CO2 injection: analytical correlation in which the correlation coefficients were tuned using linear support vector machines (SVMs) (Press et al. 2007; MathWorks 2020; RDocumentation 2020b; Cortes and Vapnik 1995) and using a hybrid method (i.e., superlearner model), which consists of the combination of random forest (RF) regression (Breiman 2001) and the proposed analytical correlation. Both models take the compositional analysis of oils up to heptane plus fraction, molecular weight of oil, and the reservoir temperature as input parameters. Based on statistical and data analysis techniques in combination with the help of corresponding crossplots, we showed that the performance of the final proposed method (hybrid method) is superior to all the leading correlations (Cronquist 1978; Lee 1979; Yellig and Metcalfe 1980; Alston et al. 1985; Glaso 1985; Emera and Sarma 2005; Yuan et al. 2005) and supervised machine-learning (Metcalfe 1982) methods considered in the literature (Altman 1992; Chambers and Hastie 1992; Chapelle and Vapnik 2000; Breiman 2001; Press et al. 2007; MathWorks 2020). The proposed model works for the widest spectrum of MMPs from 1,000 to 4,900 psia, which covers the entire range of oils within the scope of CO2 EOR based on the widely used screening criteria (Taber et al. 1997a, 1997b). NOTE: A correction notice has been issued for this paper and is available under the Supplementary Data section.

Modeling of CO2-LPG WAG with asphaltene deposition to predict coupled enhanced oil recovery and storage performance

Combined carbon capture and storage and CO2-enhanced oil recovery (CCS-EOR) can reconcile the demands of business with the need to mitigate the effects of climate change. To improve the performance of CCS-EOR, liquefied petroleum gas (LPG) can be co-injected with CO2, leading to a reduction in the minimum miscibility pressure. However, gas injection can cause asphaltene problems, which undermines EOR and CCS performances simultaneously. Here, we systematically examine the mechanisms of asphaltene deposition using compositional simulations during CO2-LPG–comprehensive water–alternating-gas (WAG) injection. The LPG accelerates asphaltene deposition, reducing gas mobility, and increases the performance of residual trapping by 9.2% compared with CO2 WAG. In contrast, solubility trapping performance declines by only 3.7% because of the greater reservoir pressure caused by the increased formation damage. Adding LPG enhances oil recovery by 11% and improves total CCS performance by 9.1% compared with CO2 WAG. Based on reservoir simulations performed with different LPG concentrations and WAG ratios, we confirmed that the performance improvement of CCS-EOR associated with increasing LPG and water injection reaches a plateau. An economic evaluation based on the price of LPG should be carried out to ensure practical success.

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.

Simulation Analysis of CO2-EOR Process and Feasibility of CO2 Storage during EOR

In this study, oil production and retention were observed and compared in 72 reservoir simulation cases, after which an economic analysis for various CO2 and oil prices was performed. Reservoir simulation cases comprise different combinations of water alternating gas (WAG) ratios, permeabilities, and well distances. These models were set at three different depths; thus different pressure and temperature conditions, to see the impact of miscibility on oil production and CO2 sequestration. Those reservoir conditions affect oil production and CO2 retention differently. The retention trend dependence on depth was not monotonic—optimal retention relative to the amount of injected CO2 could be achieved at middle depths and mediocre permeability as well. Results reflecting different reservoir conditions and injection strategies are shown, and analysis including the utilization factor and the net present value was conducted to examine the feasibility of different scenarios. The analysis presented in this paper can serve as a guideline for multiparameter analysis and optimization of CO2-enhanced oil recovery (EOR) with a WAG injection strategy.

Practical CO2—WAG Field Operational Designs Using Hybrid Numerical-Machine-Learning Approaches

Machine-learning technologies have exhibited robust competences in solving many petroleum engineering problems. The accurate predictivity and fast computational speed enable a large volume of time-consuming engineering processes such as history-matching and field development optimization. The Southwest Regional Partnership on Carbon Sequestration (SWP) project desires rigorous history-matching and multi-objective optimization processes, which fits the superiorities of the machine-learning approaches. Although the machine-learning proxy models are trained and validated before imposing to solve practical problems, the error margin would essentially introduce uncertainties to the results. In this paper, a hybrid numerical machine-learning workflow solving various optimization problems is presented. By coupling the expert machine-learning proxies with a global optimizer, the workflow successfully solves the history-matching and CO2 water alternative gas (WAG) design problem with low computational overheads. The history-matching work considers the heterogeneities of multiphase relative characteristics, and the CO2-WAG injection design takes multiple techno-economic objective functions into accounts. This work trained an expert response surface, a support vector machine, and a multi-layer neural network as proxy models to effectively learn the high-dimensional nonlinear data structure. The proposed workflow suggests revisiting the high-fidelity numerical simulator for validation purposes. The experience gained from this work would provide valuable guiding insights to similar CO2 enhanced oil recovery (EOR) projects.

Deposition, Diagenesis, and Sequence Stratigraphy of the Pennsylvanian Morrowan and Atokan Intervals at Farnsworth Unit

Farnsworth Field Unit (FWU), a mature oilfield currently undergoing CO2-enhanced oil recovery (EOR) in the northeastern Texas panhandle, is the study area for an extensive project undertaken by the Southwest Regional Partnership on Carbon Sequestration (SWP). SWP is characterizing the field and monitoring and modeling injection and fluid flow processes with the intent of verifying storage of CO2 in a timeframe of 100–1000 years. Collection of a large set of data including logs, core, and 3D geophysical data has allowed us to build a detailed reservoir model that is well-grounded in observations from the field. This paper presents a geological description of the rocks comprising the reservoir that is a target for both oil production and CO2 storage, as well as the overlying units that make up the primary and secondary seals. Core descriptions and petrographic analyses were used to determine depositional setting, general lithofacies, and a diagenetic sequence for reservoir and caprock at FWU. The reservoir is in the Pennsylvanian-aged Morrow B sandstone, an incised valley fluvial deposit that is encased within marine shales. The Morrow B exhibits several lithofacies with distinct appearance as well as petrophysical characteristics. The lithofacies are typical of incised valley fluvial sequences and vary from a relatively coarse conglomerate base to an upper fine sandstone that grades into the overlying marine-dominated shales and mudstone/limestone cyclical sequences of the Thirteen Finger limestone. Observations ranging from field scale (seismic surveys, well logs) to microscopic (mercury porosimetry, petrographic microscopy, microprobe and isotope data) provide a rich set of data on which we have built our geological and reservoir models.

Modeling interaction between CO2, brine and chalk reservoir rock including temperature effect on petrophysical properties

Carbon dioxide (CO2) capture and sequestration through CO2 enhanced oil recovery (EOR) in oil reservoirs is one of the approaches considered to reduce CO2 emission into the atmosphere. The injection of CO2 into a subsurface geological formation may lead to chemical reactions that may affect the formation pore structure and characteristics. In this study, the effect of CO2–brine–rock interaction on the rock petrophysical properties and mineral volume fraction was numerically investigated during CO2 injection into a chalk reservoir rock. A 3D numerical modeling and simulation were conducted using COMSOL® Multiphysics commercial software of computational fluid dynamics (CFD) to simulate CO2–brine core flooding process in a chalk core. The model was validated against a core–scale experimental data from literature. Simulation differential pressure data matched the literature experimental data closely and consistently indicating good agreement between them. Temperature effect on the performance of CO2–brine–chalk sequestration was also evaluated in the present study. Results indicated that porosity was only slightly affected by temperature increase during CO2 injection in contrast to permeability that was substantially affected by temperature. Moreover, chemical reactions enhanced as temperature increased leading to significant increase in permeability. Thus, carbonated brine sequestration excelled at elevated temperature due to increased acidity which governs the sequestration process. The developed model maybe considered as a reliable tool to optimize various operating parameters of CO2–brine sequestration.

Efficient Facilitated Transport Polymer Membrane for CO2/CH4 Separation from Oilfield Associated Gas.

CO2 enhanced oil recovery (CO2-EOR) technology is a competitive strategy to improve oil field economic returns and reduce greenhouse gas emissions. However, the arbitrary emissions or combustion of the associated gas, which mainly consists of CO2 and CH4, will cause the aggravation of the greenhouse effect and a huge waste of resources. In this paper, the high-performance facilitated transport multilayer composite membrane for CO2/CH4 separation was prepared by individually adjusting the membrane structure of each layer. The effect of test conditions on the CO2/CH4 separation performance was systematically investigated. The membrane exhibits high CO2 permeance of 3.451 × 10−7 mol·m−2·s−1·Pa−1 and CO2/CH4 selectivity of 62 at 298 K and 0.15 MPa feed gas pressure. The cost analysis was investigated by simulating the two-stage system. When the recovery rate and purity of CH4 are 98%, the minimum specific cost of separating CO2/CH4 (45/55 vol%) can be reduced to 0.046 $·Nm−3 CH4. The excellent short-to-mid-term stability indicates the great potential of large industrial application in the CH4 recovery and CO2 reinjection from oilfield associated gas.

Comparative Analysis of Four Neural Network Models on the Estimation of CO2-Brine Interfacial Tension.

During the CO2 injection of geological carbon sequestration and CO2-enhanced oil recovery, the contact of CO2 with underground salt water is inevitable, where the interfacial tension (IFT) between gas and liquid determines whether the projects can proceed smoothly. In this paper, three traditional neural network models, the wavelet neural network (WNN) model, the back propagation (BP) model, and the radical basis function model, were applied to predict the IFT between CO2 and brine with temperature, pressure, monovalent cation molality, divalent cation molality, and molar fraction of methane and nitrogen impurities. A total of 974 sets of experimental data were divided into two data groups, the training group and the testing group. By optimizing the WNN model (I_WNN), a most stable and precise model is established, and it is found that temperature and pressure are the main parameters affecting the IFT. Through the comparison of models, it is found that I_WNN and BP models are more suitable for the IFT evaluation between CO2 and brine.

Reaction of drilled-cores from the Janggi basin with CO2-saturated brine from subcritical to supercritical condition of CO2: Implications on sequestration of dissolved CO2

The CO2-brine-core reaction was studied to provide information for geological CO2 sequestration in the Janggi basin. Three drilled-core samples (two caprocks and one reservoir rock) at different depths in the basin were used for the reactions under subcritical and supercritical conditions of CO2 (10 bar–170 bar at 40 °C). Due to the dissolution of various ions from the cores during the reactions, the ion composition and concentration were changed in the brine, causing the experimentally determined solubility of CO2 in brine to change. Therefore, the change in the solubility of CO2 in brine was affected by the type of core and pressure. In addition, to simulate the effect of an additive on the CO2 solubility, alkyl-olefin sulfonate (AOS; 1 wt%), which is widely used for CO2 enhanced oil recovery (CO2-EOR), was added to the CO2-brine-reservoir rock reaction system. The addition of the surfactant contributed to improving the solubility of CO2 mainly in the high-pressure region. The change in the textural structure (mesopore and micropore) and chemical composition of core were also observed in nano-scale aspects despite the short experimental period (12 days). The introduction of AOS reduced the nano-scale structural change of the reservoir rock. The results in brine and cores can contribute to improving the understanding of CO2-brine-core reactions, because more accurate estimation of CO2 storage capacity after reactions can be feasible in designing and operating CO2 sequestration.

CO2-EOR+ in Australia: achieving low-emissions oil and unlocking residual oil resources

The petroleum industry, through the production and consumption of oil and gas, contributes to global greenhouse gas emissions. However, the industry’s leadership and experience in underground injection and storage of CO2, especially through CO2 enhanced oil recovery (CO2-EOR), which has been proposed as a possible solution to reducing atmospheric CO2 levels, has not been well acknowledged. Unlike traditional CO2-EOR, which tends to be a net carbon emitter due to the use of predominantly natural CO2, rather than anthropogenic, CO2-EOR+ focuses on storing a larger volume of CO2. Thus CO2-EOR+ not only provides a potential solution to dispose of anthropogenic emissions but at the same time reduces reliance on imported oil through increased domestic production. Increased industry interest and energy policy strategies directed at reducing and/or removing emissions from industry processes reflect the growing social and economic impetus to improve operation practices and the petroleum industry’s reputation. Residual oil zones (ROZs) below identified oil–water contacts provide an excellent target for the application of CO2-EOR+. They offer a producible residual oil resource accessible through CO2-EOR, as well as a large pore volume for CO2 storage, with efforts focused on converting ROZs into resources and reserves. Existing fields in the Surat and Cooper-Eromanga Basins are already well placed to utilise anthropogenic CO2 sources to achieve conventional CO2-EOR metrics. The ROZs in these basins will hopefully allow potential EOR projects to increase the CO2 volumes stored, per incremental barrel of oil, well past traditional levels (0.2–0.3 tCO2/bbl), and in doing so, potentially achieve net negative-emission oil.

Application of CO2 injection monitoring techniques for CO2 EOR and associated geologic storage

The Energy & Environmental Research Center (EERC), through its efforts leading the Plains CO2 Reduction (PCOR) Partnership, has successfully developed practices and technologies that can be used in future commercial-scale CO2 storage projects in different geologic formations, including both dedicated CO2 storage in saline formations and associated CO2 storage incidental to enhanced oil recovery (EOR). In this work, reservoir monitoring activities have been conducted in a large-scale CO2 EOR project to understand performance and associated storage. The activities include pulsed-neutron well logs (PNLs), 4D (time-lapse 3D) seismic surveys, and numerical simulation of injection and production. This enabled monitoring at different scales, from individual wells to field-scale reservoir assessments. The oil, water, and CO2 saturations were profiled to identify bypassed oil and high-conductivity CO2 migration pathways in the reservoir. These techniques provided actionable information, enabling better management of CO2 flooding, diagnosing performance and sweep efficiency while ensuring injected CO2 remained within the reservoir.