Metagenomic analysis of compositions and metabolic potential of microbial communities in production water from CO2-and water- flooded petroleum reservoirs

Carbon Capture, Utilization, and Storage (CCUS) technologies are pivotal in mitigating climate change by reducing CO₂ emissions from industrial sources. Among the most promising CCUS approaches is the integration of CO₂ sequestration with Enhanced Oil Recovery (EOR), which not only aids in reducing atmospheric CO₂ but also enhances hydrocarbon recovery from mature oil reservoirs. This evaluates hybrid CO₂ sequestration and EOR strategies, focusing on the optimization of CO₂ injection methods that maximize oil recovery while ensuring the long-term geological stability of the stored CO₂. CO₂ injection into oil reservoirs enhances oil recovery through mechanisms such as miscible displacement, oil viscosity reduction, and swelling effects. The study examines various CO₂ injection strategies, including continuous, cyclic, and water-alternating-gas (WAG) injection, and their effectiveness in improving oil recovery efficiency. Additionally, advanced methods like foam-assisted CO₂ injection are explored for their potential in increasing sweep efficiency and reducing CO₂ mobility, thus enhancing both hydrocarbon recovery and storage security. Ensuring the long-term stability of stored CO₂ is critical to the success of CCUS projects. The study assesses the factors influencing CO₂ retention, including capillary trapping, mineralization, and solubility trapping, and highlights the role of advanced monitoring techniques, such as 4D seismic imaging and pressure monitoring, to detect potential leakage and ensure the integrity of storage sites. This emphasizes the environmental and economic benefits of hybrid CCUS-EOR systems, which offer a dual advantage of climate change mitigation and extended hydrocarbon production. The review concludes with an analysis of the challenges and future directions for large-scale deployment, including technological advancements, cost barriers, and regulatory considerations, ultimately advocating for policy support and investment in CCUS technologies for sustainable energy production.

This paper addresses the challenge of difficulty in adjusting late-stage production in water-flooded reservoirs and proposes an integrated well network design mode for CO2 enhanced oil recovery (EOR) and storage. The well network is designed according to the full life cycle of carbon capture, utilization, and storage (CCUS), meeting the requirements of both CO2 EOR and storage phases. It extends the implementation time of CO2 EOR schemes to enhance oil recovery while ensuring effective CO2 storage, aligning with the overall strategy of global green and low-carbon development. The overall approach involves the use of a three-dimensional CO2 flooding injection and recovery well network, with progressive development in the vertical stratigraphic layers to maximize the utilization of existing old wells. The stratigraphic reconstruction involves the CO2 flooding injection and recovery well network, ensuring that new gas injection wells meet the requirements for CO2 injection processes and production rates, while also serving as replacements for gas injection in other stratigraphic layers. Production wells make use of the original old wells, and well completion methods are adjusted to achieve the development of replacement layers. The "top injection, middle production, bottom support" three-stage development method is designed to fully utilize the high points of reservoir microstructures and bottom water energy. Finally, well network optimization is achieved through streamline tracking simulation methods. The proposed technology has been applied in the CO2 enhanced oil recovery plan for the L reservoir. Initially focusing on CO2 flooding for oil recovery and shifting to CO2 storage later, it is projected to achieve a cumulative CO2 injection of tens of millions of tons over 46 years (including 40% recycled injection), with a displacement factor reaching 1.57PV. After deducting the recycled carbon amount, the cumulative carbon storage exceeds 6 million tons, affecting a volume of 0.96PV. The accumulated gas production over phases is 2.141 billion cubic meters, and the cumulative incremental oil production exceeds 3 million tons. The CO2-to-oil exchange rate is 0.32 tons of crude oil per ton of CO2, representing a 25.10 percentage point increase compared to the water flooding scheme in terms of oil recovery efficiency. The "Integrated Well Network Design for CO2 EOR and Storage" proposed in this paper provides an effective means of implementing CCUS technology in oilfield production, offering technical support for the achievement of integrated CO2 EOR and storage objectives. This allows for a smooth transition from CO2 EOR to storage in oil reservoirs, requiring minimal or no adjustment of the well network, thereby reducing the complexity of adjustment plans and processes. Simulation of the scheme and on-site experimental results also demonstrate the effectiveness of this technology.

Carbon Dioxide (CO2) injection is a common process used to increase hydrocarbon production in oil and gas fields, which is known as the enhanced oil recovery (EOR) process. This paper presents modeling of a carbon capture, utilization and storage (CCUS) project using an integrated operation and optimization approach. In this case study, the subsurface system consists of two different reservoirs, a gas condensate and an oil reservoir. The products from the two reservoirs are processed in a single surface processing facility. The CO2 will be captured from both reservoirs and injected into the oil reservoir after being processed in the surface facility. The CO2 from various capture processes will produce different types of residual components, and the effects of different compositions of the injected CO2 stream on field economic revenue will be studied. The verification of extra cost by increasing the CO2 mole fraction in the recycle system is modeled in the economic cost equation. The final surface separation products will be condensate (oil), natural gas liquid (NGL), and sales gas. Various derivative-free optimization methods will be used to maximize the net present value (NPV) of the CO2 EOR project. The decision variables are the multi-stage separator pressure conditions (surface parameters) and the CO2 injection rate (sub-surface parameter). Optimization results using different optimization methods will be compared to determine the best field operating parameters. The possibility of combination with water injection will also be investigated to determine the best injection scenarios. An integrated analysis of the CO2 injection process provides a thorough and comprehensive understanding of the performance of the complete CO2 injection value chain. Optimization at the field scale provides insights into the subsurface response to field scale parameter variations. The integrated approach presented in this paper will provide a basis to evaluate CO2 EOR scenarios compared to other injection strategies, such as surfactant or polymer injections.

Photochemical process destroys toxic organics in wastewater

Integrated Monitoring of China’s Yanchang CO2-EOR Demonstration Project in Ordos Basin

The development of carbon emission reduction technologies and clean energy utilisation are two critical drivers for reducing and controlling greenhouse gas (GHG) emission from human activities. Carbon capture, utilisation, and storage (CCUS) is an established and crucial emission reduction technology capable of achieving near-zero-emission from fossil fuels. Hydrogen, a zero-carbon fuel, provides energy security while improving air quality. However, hydrogen is commonly derived from fossil fuels with significant associated CO2 emission. Hence, this study investigates the feasibility of integrating CCUS in the hydrogen industry, particularly from technical, sustainability, and policy perspectives. This study also critically reviews existing CCUS and hydrogen production technologies and discusses the prospects and challenges of each. Studies show that CO2 enhanced oil recovery (CO2-EOR) and CO2 enhanced coal-bed methane recovery (CO2-ECBM) are promising CCUS technologies in China, while producing clean hydrogen from fossil fuels with CCUS and water electrolysis are ideal development route. Specifically, this study proposes the coupling technical route of CCUS + SMR (steam methane reforming) and CCUS + CTH (coal-to-hydrogen) to accelerate carbon emission reduction by 2050 considering their promising carbon reduction potential and the ratio of hydrogen with CCUS. Besides, CO2 hydrogenation integrated chemical production is becoming increasingly popular to achieve carbon emission reduction and low-carbon economy. However, the relatively high costs and lack of hydrogen transportation infrastructure is currently the major bottleneck restricting the development of CCUS and hydrogen industry. Therefore, government subsidies, standardised operation of the carbon market, and technological innovation are useful strategies to address this issue.

With the determination towards sustainable growth, PTTEP has a commitment to achieve Net Zero Greenhouse Gas Emissions by 2050. Therefore, the Carbon Capture Utilization and Storage (CCUS) project in the Gulf of Thailand was initiated to evaluate the CO2 storage capacity in Bongkot and Arthit fields. Three categories of storage potential were considered including shallow aquifers and depleted gas reservoirs together with storage potential in oil rim reservoirs by using CO2 enhanced oil recovery (CO2-EOR) method. The storage potential in shallow aquifer was targeted on porous rock located between seabed and top producing reservoirs which were identified in seismic and/or well data and reached by existing platforms. For the inventory of depleted gas reservoirs, the cumulative gas production volume was allocated to an individual reservoir, which signified storage size and injectivity of reservoir. The depleted gas reservoirs were focused on ones where a great amount of gas has been produced. For the CO2-EOR candidates, all oil rim reservoirs were reviewed and included in the study. The calculation of oil gain, CO2 injection requirement, and CO2 storage potential were based on the statistical data of Water-Alternating-CO2 fields. The inventory of CO2 storage potential from three categories were compiled with the information of 1) platform name, 2) remaining reserves, 3) distance from processing platforms, and 4) CO2 storage volume. After considering the CO2 storage potential, two platforms were considered as the most suitable for two fields equipped with CO2 removal units. In addition, the CCS development study considered an option to improve CO2 removal performance of the membrane in order to recover more hydrocarbon from flared gas. After the preliminary technical evaluation, the detailed study with reservoir simulation will be conducted in order to ensure the injectivity at reservoir level, the optimization of injection well number, and the integrity of containment. The injection plan will be formulated, and the investment cost estimation of CCS project can be refined accordingly. This CCUS study was initiated to reduce the CO2 emission from production fields under PTTEP. Currently, there are more than 20 CCUS projects around the world with only a few projects at the stage of CO2 injection. It requires good collaboration among subsurface and surface teams to increase confidence in storage suitability assessment. This project provides an example of multi-disciplinary integration and robust workflow starting from CO2 storage identification, volume calculation, to candidate ranking for further detail study.

CO2 geo-sequestration can significantly contribute to the reduction of greenhouse gas emissions. Out of all geological CO2 storage sites, mature oil fields are often considered primary targets for CO2 sequestration as one of Carbon Capture, Utilisation and Storage (CCUS) approaches where the operation cost can be offset by enhancing oil recovery and utilising the existing facilities. However, a geological formation with large volumetric capacity (pore volume) is not necessarily an appropriate candidate for CO2 storage and CO2 injectivity plays equally an important role for site selection to store CO2. Therefore, evaluation of CO2 dynamic storage capacity (injectivity) and ultimate CO2 enhanced oil recovery (EOR) are key elements for a successful CO2 storage – EOR project. CO2 EOR was considered as a suitable tertiary oil recovery approach after very short and inefficient primary and secondary oil recoveries in Yanchang oil field, the second largest tight oil field in China, located at Ordos Basin in north western China. This paper describes the acquisition of essential dynamic data from a reservoir in Yanchang oil field to evaluate its CO2 injectivity/dynamic storage capacity. For that, numerical reservoir simulation was utilised to model and history match the target reservoir. The history matched model was then used to numerically perform several testing scenarios resulting in the selection and design of the most appropriate test. A unique two-stage well testing approach was proposed to inject water and CO2 into one well and observe the pressure at two monitoring wells for a total testing period of about one year. It accurately estimates formation effective permeability in both the water flooded zone (test stage 1) and the CO2 flooded zone (test stage 2) at the injecting well. Also, it qualitatively estimates the water and CO2 fronts in the reservoir as well as CO2 injectivity using data at the injecting well. The radius of investigation (ROI) significantly increases by adding two monitoring wells to the existing injecting well. Using two monitoring wells also identifies heterogeneities and lateral anisotropy in the reservoir. The recently acquired field data, as part of this well testing program, indicate that the reservoir characteristics at the monitoring wells are significantly different from each other, suggesting the existence of considerable heterogeneity/anisotropy in the reservoir. The results generated by this well test are included in the reservoir model to reduce uncertainties for the future CO2-EOR field development plan. Finally, more informative decisions can be made on whether or not a field is suitable for a CO2-EOR project to unlock further oil resources from tight formations.

Oil reservoirs can represent extreme environments for microbial life due to low water availability, high salinity, high pressure and naturally occurring radionuclides. This study investigated the microbiome of saline formation water samples from a Gulf of Mexico oil reservoir. Metagenomic analysis and associated anaerobic enrichment cultures enabled investigations into metabolic potential for microbial activity and persistence in this environment given its high salinity (4.5%) and low nutrient availability. Preliminary 16S rRNA gene amplicon sequencing revealed very low microbial diversity. Accordingly, deep shotgun sequencing resulted in nine metagenome-assembled genomes (MAGs), including members of novel lineages QPJE01 (genus level) within the Halanaerobiaceae, and BM520 (family level) within the Bacteroidales. Genomes of the nine organisms included respiratory pathways such as nitrate reduction (in Arhodomonas, Flexistipes, Geotoga and Marinobacter MAGs) and thiosulfate reduction (in Arhodomonas, Flexistipes and Geotoga MAGs). Genomic evidence for adaptation to high salinity, withstanding radioactivity, and metal acquisition was also observed in different MAGs, possibly explaining their occurrence in this extreme habitat. Other metabolic features included the potential for quorum sensing and biofilm formation, and genes for forming endospores in some cases. Understanding the microbiomes of deep biosphere environments sheds light on the capabilities of uncultivated subsurface microorganisms and their potential roles in subsurface settings, including during oil recovery operations.

Two major challenges in CO2 enhanced oil recovery (EOR) are the high mobility of CO2 and reservoir heterogeneity. High CO2 mobility, related to the low density and viscosity of CO2, compared to in-situ fluids can cause viscous fingering, gravity override, and flow in thief zones resulting in poor reservoir sweep efficiency and low oil recoveries. Mobility control foam can improve CO2 EOR and CO2 storage potential by mitigating unfavorable CO2 properties and reducing the impact of reservoir heterogeneity. CO2 foam injection involves injecting a foaming agent (surfactant) with CO2 to generate stable foams in porous media. This work presents an incremental physical upscaling approach that moves from the pore- to core- to field-scale for characterizing and optimizing foam systems for CO2 mobility control, EOR, and CO2 storage. An additional focus was to visualize and describe in-situ fluid saturation dynamics during CO2 storage processes. We address the challenges associated with transferring CO2 foam EOR technology offshore, using lessons learned from an ongoing onshore pilot in the Permian Basin of west Texas. The aim is to encourage co-optimized CO2 EOR and long-term CO2 storage foam technology as part of carbon capture, utilization, and storage (CCUS) for offshore applications.

To achieve the net-zero emission goal of 2050, implementing carbon capture, utilization, and storage (CCUS) technology has proven to be crucial. The CCUS processes integrate multidisciplinary domains such as chemical, subsurface engineering, economics, and environmental science. Therefore, the entire value chain must be examined to understand the viability of a CCUS project. In Kansas, a CCUS opportunity is ongoing, which involves capturing CO2 directly from a nearby ethanol plant for CO2–enhanced oil recovery (EOR) and CO2 storage. This paper provides an overview of the Stewart Field Unit (SFU) CO2–EOR and CO2 storage project from the perspective covering direct industrial CO2 capture to underground usage and storage evaluation. First, we reviewed the techno-economics of industrial CO2 capture and utilization in Kansas to corroborate small-scale point-to-point economic evaluation of captured CO2 for CO2–EOR and storage. The FECM/NETL CO2 Transport Cost Model was used to estimate the CO2 capture and compression cost. Next, for the subsurface engineering aspect, we developed a field-scale compositional reservoir and flow model to simulate the primary, secondary, and CO2 injection phases of the SFU. The field-scale reservoir model incorporated hydraulic fractures that underwent compaction/dilation during the injection production phases, with severe near-wellbore damage as one of the underlying physical-chemical mechanisms. A representative equation of state was used and tuned using experimental fluid data. The model's primary, secondary, and tertiary recovery phases were historically matched successfully by modification of directional permeability, relative permeability curves, and near-wellbore damage. Furthermore, we proposed an economic framework to determine the sustainable economic profitability of the SFU project using the net present value (NPV) economic indicator. The cumulative recovery factors for primary, secondary, and tertiary stages are 11.5%, 29%, and 32%, respectively. Furthermore, it has been observed that 45% of the injected CO2 has been sequestered in the SFU. The low recovery rates during the CO2-EOR phases can be attributed to formation damage caused by water sensitivity, the formation of scales, and issues with wellbore integrity. A baseline case and two other CO2-WAG cases were forecasted after the conclusive historical match, focusing strategically on developing the field's eastern or western sections. The constraints on CO2 availability and the logistics of CO2 transportation necessitated this approach. These proposed regional WAG cases yielded an incremental oil recovery factor of approximately 1, 3, and 3.5% for the baseline, west, and east section scenarios, respectively. For both west and east section WAG cases, more than 40% of the injected CO2 would be stored in the formation. Consequently, economic analyses were carried out on the result to show the viability of the WAG projects with or without tax credit inclusion under the current economic conditions. The NPVs show that the SFU WAG project is only economically favorable, including a $80/metric ton tax credit for the cases studied. This research provides a comprehensive framework for assessing viable small-scale carbon capture, utilization, and storage projects in other geologically similar fluvial morrow formations.

Technology Focus Last year in this focus on CO2 applications, I (as others have) connected enhanced oil recovery (EOR) as an enabling business foundation and a possible way forward to accomplish carbon capture and storage (CCS) as a business investment. This year, in an address to the CCS conference in Pittsburgh, Pennsylvania, US Department of Energy (DOE) Assistant Secretary of Fossil Energy Charles McConnell encouraged the CCS industry to help operators establish a salient business case between CO2 EOR and usage and sequestration. Creating a technical lead in CO2 EOR and other usage technologies establishes an opportunity to commercialize the technologies that could be in high demand in the years to come, particularly in coal-reliant developing countries such as China and India. The technologies needed to accomplish carbon capture, utilization, and storage (CCUS) require expertise in science and engineering that, in some cases, are not completely matured or, at least, require a different focus and commitment in science and business to affect CCUS. An acceptable return on investment will depend on economic CO2 capture and largely on regulatory stability. Administratively, the US Environmental Protection Agency proposed a carbon pollutions standard for new power plants, which will have to meet 1,000 lbm of CO2 per electrical megawatt-hour produced. Older coal plants average approximately 1,768 lbm of CO2 per megawatt-hour but are exempt from the standard, as are plants permitted to begin construction within a year. A typical natural-gas electricity-generation plant emits 800 to 860 lbm of CO2 per megawatt-hour. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 15029 An Integrated Reservoir-Simulation/Geomechanical Study on Feasability of CO2 Storage in M4 Carbonate Reservoir, Malaysia by Rahim Masoudi, Petronas, et al. CMTC 151027 NETL CO2-Injection and -Storage Cost Model by T.C. Grant, US Department of Energy, et al. SPE 154539 Evaluation of the CO2-Storage Capacity of the Captain Sandstone Formation by Min Jin, Heriot-Watt University, et al. SPE 145440 Monitoring on CO2 EOR and Storage in a CCS Demonstration Project of Jilin Oil Field China by Shaoran Ren, China University of Petroleum, et al. CMTC 151716 The Longannet to Goldeneye Project: Challenges in Developing an End-to-End CCS Scheme by P.J. Garnham, Shell, et al.

The carbon, capture, utilization and storage (CCUS) is a technology that allows the use of fossil fuels to energy generation and reduction the CO2 emissions to the atmosphere simultaneously. As part of this technology, CO2 can be used as an assessment for the oil industry, as well as an Enhanced Oil Recovery method by injecting CO2 in the oil reservoirs (CO2-EOR). An advantage of using the CO2-EOR is that oil and gas fields in production, either depleted or mature fields, can be targets to implement a storage project after the CO2 injection and oil production. However, not all fields are suitable to implement the CO2-EOR project and a screening process to select fields that can use the EOR method should carefully be chosen. To perform this screening is a hard task due to the need to gather enough data to the analysys, which the population to be studied might be huge, becoming difficult to collect all data needed. The aim of this paper is to present a quick screening process to select oil fields for CCUS, reducing the population studied. A study case and methodology was carried out, consisting in perform a quick screening and the analysys of reservoir data using a real fluid sample collected from a oil reservoir in Reconcavo basin. This data is primary data and was collected from a company. First, the fluid was characterized and the minimum miscibility pressure (MMP) was performed using the Rising Bubble apparatus (RBA). In addition, it was used CMG-Winprop to match the experimental and simulation data for MMP, and MMP was also calculated using the proper correlation developed for the Reconcavo. After that, the MMP was analysed by screening criteria to evaluate if the reservoirs criteria collected were significant for applying the process. The quick screening process was appropriate to show the potential of a basin to use CO2-EOR and to propose this method of previous studies at the Reconcavo were used as a guide. Even if the result is negative for the CO2-EOR, the studied reservoir can be used only for CO2 storage, and other criteria needed to be analyzed. Medium and small companies in the petroleum areas can use this quick process to do a preliminary study at the basin to select potential fields to apply the CO2-EOR, having a small population to study can reduce the costs of a big process that is the viability study of a project. Petroleum agencies and energy and technology departments can use this process as well to promote public energy policy and perform preliminary studies at the Reconcavo Basin to prove its potential to be used as sites for carbon sequestration to reduce CO2 emissions to the atmosphere.

Comparative numerical study on the co-optimization of CO2 storage and utilization in EOR, EGR, and EWR: Implications for CCUS project development

Cleaner coal and greener oil production: An integrated CCUS approach in Yanchang Petroleum Group