CO2 EOR Research Articles

Techno-economic-environmental study of CO2 and aqueous formate solution injection for geologic carbon storage and enhanced oil recovery

As carbon capture, utilization, and storage (CCUS), carbon-dioxide enhanced oil recovery (CO2 EOR) has inherent shortcomings, such as inefficient oil recovery and carbon storage, and low storage security with mobile CO2. This paper presents a techno-economic-environmental analysis of using formate species, a product of CO2 electrochemical reduction, as an alternative carbon carrier for sequestration and EOR in a carbonate oil reservoir in the Gulf of Mexico Basin. CO2 injection, water-alternating-CO2 injection, and aqueous formate solution injection were compared using a compositional reservoir simulation model and an economic calculator. Formate solution injection yielded greater levels of oil recovery and net carbon storage, where the carbon-bearing species resided in the dense aqueous phase without having to rely on petrophysical trapping mechanisms (structural and capillary). The enhanced oil production, net carbon storage, and storage security can be promoted by providing formate-based CCUS with more incentives (e.g., greater tax credit) in comparison to CO2-based CCUS for EOR and the manufacture of chemicals and products. In establishing carbon storage incentive policies and regulations, policymakers should include alternative carbon carriers.

Reservoir Simulations of Hydrogen Generation from Natural Gas with CO2 EOR: A Case Study

This paper addresses the problem of hydrogen generation from hydrocarbon gases using Steam Methane Reforming (SMR) with byproduct CO2 injected into and stored in a partially depleted oil reservoir. It focuses on the reservoir aspects of the problem using numerical simulation of the processes. To this aim, a numerical model of a real oil reservoir was constructed and calibrated based on its 30-year production history. An algorithm was developed to quantify the CO2 amount from the SMR process as well as from the produced fluids, and optionally, from external sources. Multiple simulation forecasts were performed for oil and gas production from the reservoir, hydrogen generation, and concomitant injection of the byproduct CO2 back to the same reservoir. EOR from miscible oil displacement was found to occur in the reservoir. Various scenarios of the forecasts confirmed the effectiveness of the adopted strategy for the same source of hydrocarbons and CO2 sink. Detailed simulation results are discussed, and both the advantages and drawbacks of the proposed approach for blue hydrogen generation are concluded. In particular, the question of reservoir fluid balance was emphasized, and its consequences were presented. The presented technology, using CO2 from hydrogen production and other sources to increase oil production, also has a significant impact on the protection of the natural environment via the elimination of CO2 emission to the atmosphere with concomitant production of H2.

Origin, distribution, and CO2 EOR and CO2 storage resource assessment of selected residual oil zone fairways in the Illinois Basin

Residual Oil Zones (ROZs) are volumes of rock with low, largely immobile, oil saturations that provide opportunities for low carbon intensity oil production via carbon dioxide enhanced oil recovery (CO2-EOR) and associated CO2 storage. Oil shows of varying degree have been observed throughout the Illinois Basin (ILB). This work is the first to assess these shows as ROZs.In the ILB, the distribution of ROZ fairways and prospects is controlled by the geologic setting and oil migration history of the basin. ILB ROZ fairways that are stratigraphically proximal to the source rock are generally widespread whereas fairways developed in formations with a greater thickness of intervening strata are more discrete, an indication of influence from fault systems and fracturing associated with major structures. Within these fairways, 41 ROZ prospects were defined across three formations (Tar Springs Sandstone, Cypress Sandstone, Carper Sandstone) containing a best estimate (P50) of five billion barrels (bbls) of original oil in place (OOIP). For context, this volume is 35% of the estimated 14.1 billion bbls of OOIP in the conventional reservoirs in the ILB. In comparison to the Permian Basin, the ILB ROZ OOIP volume is 20% of the estimated 25 billion bbl of ROZ OOIP within a nine-county area of the San Andres Formation.The CO2-EOR resource of the ILB ROZ prospects exceeds 518 million bbls of oil using CO2 injection via pattern flooding. Associated CO2 storage is estimated to be 411 million tonnes of CO2. This study builds on past efforts to establish the CO2-EOR and associated CO2 storage resource potential of the ILB and presents a methodology that can be used to assess ROZ resources in other parts of the world.

Enhanced oil recovery via dissolution of low molecular weight PDMS in CO2 during immiscible gas injection in matrix-fracture system

Oil recovery in natural fracture reservoirs can be improved by reducing the capillary force during the gravity drainage process in matrix-fracture system. In the current study, a modified gas was generated via dissolution of low molecular weight poly(dimethyl siloxane) (PDMS, average Mw 3780 g/mol, 10000 – 50000 ppm) in CO2 to enhance oil recovery at 50 °C or 70 °C and 3000 psi. Cloud point measurements indicated that PDMS dissolved in CO2 at pressures less than 3000 psi, which was below the minimum miscibility pressure (MMP) of ∼3600 psi at 70 °C determined with the vanishing interfacial technique. The solution density increased from 669.6 kg/m3 for pure CO2 to 780.3 kg/m3 for CO2/PDMS (50000 ppm) at 70 °C and 3000 psi, thereby reducing the density difference between the CO2-rich fluid and crude oil (ρo=865.2 kg/m3) in matrix-fracture system. Also, CO2-oil interfacial tension (IFT) was reduced from 65 to 15 dyn/cm via the dissolution of 50000 ppm PDMS in CO2. Therefore, it led to the CO2 diffusion coefficient increased in both reservoir-fluid saturated porous media and bulk oil scenarios 3–4 fold and 4–7 fold respectively in comparison to pure CO2 injection. These PDMS-induced changes reduced the capillary effects in gas-invaded zone, which consequently led to an increase in oil recovery of 25% points (from 31% to 56%) compared to pure CO2 injection in the case of capillary continuity during gravity drainage tests. For the field-scale, because the PDMS can dissolve in CO2 at pressures and temperatures which are commensurate with CO2 EOR, it is a promising CO2-philic chemical for increasing CO2 density and improving CO2 diffusion coefficient in gas invaded zone compared to conventional CO2 injection.

Synergistic Optimization of CO2 EOR and Sequestration in Heavy Oil Reservoirs through Cooperative Strategies

Synergistic Optimization of CO2 EOR and Sequestration in Heavy Oil Reservoirs through Cooperative Strategies

Investigation of gravity influence on EOR and CO2 geological storage based on pore-scale simulation

Gravity assistance is a critical factor influencing CO2–oil mixing and miscible flow during EOR and CO2 geological storage. Based on the Navier–Stokes equation, component mass conservation equation, and fluid property–composition relationship, a mathematical model for pore-scale CO2 injection in oil-saturated porous media was developed in this study. The model can reflect the effects of gravity assistance, component diffusion, fluid density variation, and velocity change on EOR and CO2 storage. For non-homogeneous porous media, the gravity influence and large density difference help to minimize the velocity difference between the main flow path and the surrounding area, thus improving the oil recovery and CO2 storage. Large CO2 injection angles and oil–CO2 density differences can increase the oil recovery by 22.6% and 4.2%, respectively, and increase CO2 storage by 37.9% and 4.7%, respectively. Component diffusion facilitates the transportation of the oil components from the low-velocity region to the main flow path, thereby reducing the oil/CO2 concentration difference within the porous media. Component diffusion can increase oil recovery and CO2 storage by 5.7% and 6.9%, respectively. In addition, combined with the component diffusion, a low CO2 injection rate creates a more uniform spatial distribution of the oil/CO2 component, resulting in increases of 9.5% oil recovery and 15.7% CO2 storage, respectively. This study provides theoretical support for improving the geological CO2 storage and EOR processes.

Insights into CO2 huff-n-puff mechanisms from laboratory experiment and single-well pilot test in the Lucaogou tight oil reservoir, Jimsar sag, China

CO2 huff-n-puff has been accepted as an effective technique to improve oil recovery in tight oil reservoirs. Even though CO2 EOR mechanisms were extensively investigated from laboratory experiments, the links of experimental results to field-scale performance have not been widely investigated as few pilot tests were conducted. In this study, laboratory experiments and CO2-huff-n-puff pilot test were performed. First, phase behaviors of the Lucaogou crude oil and oil-CO2 mixtures were investigated via Pressure-Volume-Temperature (PVT) tests including flash evaporation, constant composition extension (CCE), and CO2 injection and slim tube tests, respectively. Experimental results showed that due to the higher concentration of the intermediate components, the saturation pressure of the Lucaogou crude oil is 6.18 MPa, which is much smaller than the initial and current formation pressures. The oil viscosity decreased from 24.8 mPa s to 3.0 mPa s and swelling factor increased to 1.848 after about 85 mol% CO2 dissolved. Moreover, slim tube test showed the minimum miscible pressure of the Lucaogou crude oil is 24.28 MPa, which is smaller than the current formation pressure, indicating multi-contact miscibility could be reached easily. Second, fracturing fluid imbibition and CO2 huff-n-puff experiments were carried out to evaluate the performance of CO2 EOR after fracturing. The oil recovery factor increased after imbibition time and the number of huff-n-puff cycles, and was impacted by petrophysical properties, like porosity and pore structure. In addition, performance of CO2 huff-n-puff pilot test in the J30 well was reported. Approximately 1.9% of original oil in place was recovered after one huff-n-puff cycle, showing a significant potential of CO2 EOR in the Lucaogou tight formation. Analysis of oil production rate, composition and density of produced oil shows the dominant EOR mechanisms in the early production stage were miscibility and CO2 vaporization, then viscosity reduction. Findings from this study will provide insights on CO2 EOR in tight oil reservoirs.

Assessing the potential of CO2 huff ‘n’ puff technology for enhanced oil recovery and CO2 sequestration in tight oil reservoirs

Fossil fuels utilization will produce a large amount of CO2, which causes a series of environmental problems. However, the exhaust CO2 can be used to achieve oil recovery improvement (CO2 EOR), while simultaneously allowing for the geological storage of CO2. For the unconventional reservoir, CO2 huff ‘n’ puff (HNP) is a potential technology showing promising results in laboratory experiments, while its effectiveness in enhancing oil recovery and CO2 sequestration at the reservoir scale remains uncertain. Thus, further research is needed to evaluate the CO2 HNP performance for its implementation. In this paper, we conducted a numerical simulation of the CO2 HNP process in a real tight oil reservoir (1800 m × 350 m × 10m in size) to assess its potential for improving oil recovery, CO2 injectivity, and CO2 sequestration. The results show that the accumulative oil production increased by more than 20% after the implementation of CO2 HNP. Meanwhile, CO2 HNP in tight oil reservoirs is proven capable to achieve CO2 injectivities of more than 4×107 SCm3 and CO2 storages of more than 5×106 SCm3. We designed 3 CO2 HNP schemes and found that the largest CO2 storage does not occur in the optimal scenario for oil production. A new type of CO2 HNP evaluation system considering oil production and storage capacity needs to be established. The results of the article suggest that CO2 HNP can achieve an oil production increase and CO2 storage in tight reservoirs, which has a positive significance for the sustainable development of environmental protection.

Synergistic effects of silica aerogels and SDS nanofluids on CO2 sequestration and enhanced oil recovery

This study explores the combined application of hydrophobic silica aerogels and SDS to enhance CO2 storage capacity and oil recovery. Experimental data highlighted a marked increase in CO2 solubility within silica aerogel-SDS nanofluids compared to brine and SDS solutions. Molecular dynamics simulations revealed CO2 adsorption into nanopores. Silica aerogel nanoparticles extended CO2 foam half-life by 6 % versus 62 % decline for sole SDS foam from 30 to 140 °C. Adjusting the SDS to nanoparticle ratio affects foam properties, with a ratio of 1.5 yielding optimal results. Core flooding experiments demonstrated a 75 % rise in CO2 trapping efficiency using the nanofluids over SDS solutions. Two-dimensional tests showed aerogel-SDS foam surpassed SDS foam flooding by 12 % incremental oil recovery in upper layers, attributed to enhanced profile control. The combined agents present an effective approach for geological CO2 storage and EOR optimization.

An experimental study of CO2 injection strategies for enhanced oil recovery and geological sequestration in a fractured tight sandstone reservoir

Carbon dioxide enhanced oil recovery has been considered and tested in unconventional oil reservoirs due to its additional environmental benefits from simultaneous CO2 geological sequestration. However, it will require a proper injection strategy to overcome unfavorable sweep efficiency in CO2 displacement, which is even magnified in unconventional oil reservoirs due to strong heterogeneity caused by natural and artificial fractures. In this study, we investigated three immiscible CO2 injection strategies at reservoir conditions using tight fractured sandstone cores from the Ordos Basin, China: water alternative gas injection, cyclic CO2 injection, and CO2 foam/surfactant alternative gas injection. A pressurization and miscible CO2 injection were then added after each injection strategy to examine the influence of residual liquid distributions on the miscible displacement efficiency after the tested injection schemes. The core plugs with comparable porosity and permeability were selected, and all cores reached a similar recovery factor (∼11%) after primary CO2 flooding. We found that the cyclic CO2 injection had best performance, with the highest incremental and accumulative oil recovery at 23.6% and 32.26%. Its relatively higher sweep efficiency indicated a uniform CO2 distribution at the end of the cyclic injection, which further led to the highest incremental recovery of 4.94% in the following miscible injection. Comparable CO2 storage capacities were observed in the three fractured core samples (12.21%, 12.98%, and 9.71%, respectively) after completing the miscible displacements. In general, cyclic CO2 injection is recommended as an effective CO2 EOR and geo-storage in tight fractured rocks.

Effects of Shale Pore Size and Connectivity on scCO2 Enhanced Oil Recovery: A Molecular Dynamics Simulation Investigation.

The differences in pore width distributions and connectivity of shale reservoirs have significant influences on supercritical carbon dioxide (scCO2)-enhanced oil recovery (CO2 EOR) in shale. Herein, the molecular dynamics simulation was adopted to investigate the microscopic mechanism of CO2 EOR in the shale nanopores with different pore size width distributions and pore connectivity. The results show that the pore connectivity has significant effects on the oil displacement, and the recovery efficiency is ordered as: connected pore > double pore > single pore for the 3 nm pore, which are 91.32, 74.43, and 65.93%, respectively. Therefore, the increase in pore connectivity can significantly improve the recovery efficiency of the small pore of the connected pore system. For the shale reservoirs with different pore width distributions, the oil recovery rate of large pores is generally higher than that of small pores. In addition, the displacement of oil in the small pore of the double pore system is accelerated due to the pushing effect of the discharge fluid from the large pore. The results furnish a certain theoretical support for the research of the microscopic mechanism of CO2 EOR in the shale pore with different pore width distributions and connectivity and the exploit of shale oil.

Study of the impact of various porous media on pore space utilization and CO2 storage by injection of microbubbles into oil reservoirs

CO2 capture and storage technology have the potential to help reach net zero emissions. CO2-enhanced oil recovery (CO2 EOR) is a favourable method. Limited pilot testing has provided preliminary evidence that the unique physical properties of gas microbubbles (MBs) can be used to improve pore utilization efficiency. In this study, supercritical CO2 injection at 0.05 mL/min into sand samples with different grain sizes under reservoir conditions was investigated by nuclear magnetic resonance (NMR). The spatial distribution of the CO2 and oil and the dynamic pore occupancy mechanism were determined for the first time, and the results from normal bubbles (NBs) and MBs were compared. The results show a more significant left shift of the transverse relaxation time in the case of MB injection, which means that CO2 can easily occupy a wide range of large pore spaces. Dynamic changes in the oil volume in the four types of pores classified by the transverse relaxation time indicate that the oil in large pores is flushed earlier when MB is injected and that the CO2 saturation in minimal pores (T2 relaxation time range from 5 ms to 100 ms) and small pores (T2 relaxation time range from 100 ms to 500 ms) increases. The cumulative oil volume fraction decreases by 9.0% when injecting MBs. From the perspective of carbon storage, the gas storage potential is significantly enhanced within low-permeability sand when injected with MBs. The maximum volume of free CO2 was enhanced by 16.9% in this case. In addition, the storage efficiency is enhanced up to 5.1% for low-permeability sand and 1.6% for medium-permeability sand. However, bubble flow is not as advantageous in high-permeability sand. Considering dissolution trapping, the storage efficiency reaches 26.3%.

Influences of diffusion and advection on dynamic oil-CO2 mixing during CO2 EOR and storage process: Experimental study and numerical modeling at pore-scales

Influences of diffusion and advection on dynamic oil-CO2 mixing during CO2 EOR and storage process: Experimental study and numerical modeling at pore-scales

Application of CCUS in India: Designing a CO2 EOR and storage pilot in a mature field

Numerous mature oil and gas reservoirs around the world, along with added financial benefit, present a tremendous benefit of CO2 EOR and storage, especially in the regions where tax benefits and policies related to the CCS is limited. This work presents the first effort of CO2 EOR and storage in a mature oil field in India through a comprehensive application of laboratory study, reservoir static modeling, dynamic simulation, pilot design, and techno-economic sensitivity analyses. Through this case study, the technical feasibility of CO2 EOR and associated storage was assured for the first time through a novel approach of combining various subsurface and surface data with laboratory analyses. Almost no analog was available for CCUS on the same-age rock from a young thrust belt setting. The various vintages of core to seismic scale data posed a great challenge for effective integration. The solution approach to these issues included combining flow physics, fluid chemistry, geological concepts and digital modeling with practical engineering data analyses. Temporal change of oil composition in this reservoir due to the long production history had created some challenges for determination of CO2 miscibility. It was estimated through the lab study and modeling that the miscibility can be achieved near 3000 psi due to its altered oil composition resulted by years of production. To arrest the reservoir pressure decline, a pre-EOR water injection was identified as an immediately need to re-pressurize the reservoir and achieve miscibility of injected CO2. Comprehensive analysis of various subsurface and surface data integrating geoscience and engineering techniques have allowed for a consistent and applicable 3D description of reservoir, which was critical to identify suitable areas with appropriate remaining oil saturation, chemistry, and reservoir pressure. The history matching-calibrated-simulation model was utilized to evaluate the performance of various development scenarios of the identified area. Specifically, CO2 injection in a sector of geological model was performed using Todd-Longstaff miscible flood scheme. Upon comparing the proposed scenarios, a CO2 injection pilot in Pattern-1 was identified, with one injector and three producers over ∼60 acres area. This pilot uses 150 Metric Ton/day (MT/D) of CO2 captured and processed from an existing facility and transported about 70 km to the field location. The CO2 will be injected continuously into this pilot area for 5 years, and the well switches back to water injection afterward. Around 1.1 MMSTB incremental oil will be recovered in next 10 years, corresponding to 11.7% of OOIP in the flooded area. Up to 268,275 MT of CO2 will be sequestered in the reservoir. The learnings from this first ever study of its kind in India set the benchmark for data analysis, integration, and case specific approaches. The success and knowledge base from this endeavor will tremendously help and encourage further expansion of CCUS activities in India.

Investigation of CO2 storage and EOR of alternating N2 and CO2 injection using experiments and numerical simulation

The feasibility of N2 alternating CO2 injection was investigated for improving CO2 storage and oil production. Schemes of continuous CO2 injection and N2 alternating CO2 injection were evaluated using laboratory experiments and numerical simulation. According to the core flooding experiments, the CO2 storage factor and enhanced oil recovery of N2 alternating CO2 flooding were 2.1% and 7.1% lower than continuous CO2 injection. The larger the N2 slug volume in N2 alternating CO2 injection, the lower the EOR and CO2 storage factor due to the reduction of CO2 concentration in the gas phase and CO2 solubility in oil and water. However, the N2 slugs in N2 alternating CO2 injection significantly reduced mobility differences between different flowing zones, and thus can increase the gas swept area in an oil reservoir. The gas swept area of the oil reservoir under N2 alternating CO2 injection mode is 1.78 times that of continuous CO2 injection, resulting in a 44% higher cumulative oil production. Besides, the scheme of N2 alternating CO2 injection was optimized and resulted in 19.6% more CO2 storage than continuous CO2 flooding at a field scale. This study provides valuable experimental and theoretical support for improving CO2 storage and oil production in an oil reservoir.

Novel Way to Predict the MMP of a CO2–Oil System Using Stacking Models

CO2-enhanced oil recovery (EOR) is an important development method for the third oil recovery stage, which occupies a certain position in carbon capture, utilization, and storage (CCUS). CO2–EOR has two kinds of displacement states in the reservoir, namely, miscible displacement and immiscible displacement, and the recovery of miscibility is far better than that of immiscible flooding. Minimum miscible pressure (MMP) plays a crucial role in whether the CO2–oil system can achieve miscibility, so accurate MMP prediction is required to formulate the reservoir development plan. Traditional methods such as slim tube experiments are expensive and time-consuming. Empirical formulas perform slightly inferiorly in terms of accuracy and range of use. In recent years, machine learning, which uses more, has improved in accuracy, but the performance of this prediction still needs to be further optimized. The work used a stacking approach, one of the ensemble models, to filter and fuse several basic machine learning models to further improve the regression effect of MMP data. First, the correlation analysis and variance inflation factor of the MMP data in the dataset are carried out, and the redundant data are excluded for the correlation and collinearity problems. A total of 147 pretreated MMP data were then regressed using 7 baseline models, whose results were preliminarily screened and combined with empirical formula data to form a new dataset. After that, the final output result is obtained through a stacking model and evaluated. In addition to fitting curves, the results of the Stacking model demonstrate the improvement of the stacking model in MMP prediction from three aspects: mean absolute error (MAE), root-mean-square error (RMSE), and decision coefficient (R2).

Compressing Natural Gas - Carbon Capture - EOR (CAGAR) Innovation: Cost Effective Sustainable Flare Gas Utilization to Boost Oil Production

Drilling natural gas (CNG) is a promising environmentally friendly gasoline substitute. It is produced at a reasonable price. Flaring, on the other hand, emits 300 million tons of CO2 into the environment wasting vital energy resources. As a result, rather than releasing CO2 into the atmosphere, it is used to boost oil production as a CO2 EOR to fulfill global oil demand that continues to rise. To achieve a sustainable oil and gas production by reducing greenhouse gasses (GHG) through flaring reduction innovations comprising gas purification and carbon capture that utilizes the associated gas as a viable compressed natural gas (CNG) and enhanced the oil recovery. Natural gas linked with crude oil (CH4 dominated) is processed in two units. The first one is a gas purification unit where natural gas is purified in compressor, Acid Gas Removal Unit (AGRU), dehydration unit, and hydrocarbon recovery producing viable CNG. In the flaring unit gas is burned converting the CH4 to CO2. Flared gas is captured in a Carbon Capture Storage (CCS). Furthermore, CO2 is centralized in the EOR-System to be injected into the reservoir as CO2-EOR by interacting with oil causing oil to swell and reduce its viscosity leading to oil flow easier through the pores. This research elucidates that CAGAR could produce 2,970 mmbtu/d of CNG. Beside producing profitable products, CAGAR also boosted oil production by adding an extra 21,369.6 bbl/d oil recovery. According to the results, the production of the CAGAR method of flare gas utilization is the most economical technology with an annual sales from oil recovery and CNG of 455,768,373 USD so that CAGAR get a profit before tax of 248,288,632.81 USD and a profit after tax of 207,479,740.57 USD with a parameter calculation is a positive NPV, IRR of 30.26% including the cash flow and present value start to be positive in the 3rd year when the system starts operating. CAGAR has a payback period of 2.7 years. Technical and economic analysis shows there improved oil recovery and improved environmental protection. So it can be concluded that CAGAR has good prospects and deserves to be implemented.

New CO2 and Hydrogen storage site marketing: How to make your storage site unique and attractive?

Today we met the situation, when our knowledge and expertise are far away from marketing – an ability to sell our knowledge to the end-user (public, policymakers, governments, and small and big enterprises). This study aimed to attract stakeholders by proposing new techno-ecological synergy concept of geological storage of CO2 (CGS) and hydrogen (UHS) in a cost-competitive, self-supporting storage site.The “story of success” of the offshore geological structure E6 in Latvia has started from an invisible point on the European map, oil-bearing but not very promising geological structure to the unique and one of the best cost-competitive, self-supporting, conceptual techno-ecological examples of a possible synergy of storage concepts with renewables energies.Using detailed petrophysical, mineralogical and geochemical analyses of the Cambrian Series 3 Deimena Formation reservoir sandstones in this structure, the CO2 storage capacity was estimated with different levels of reliability from a conservative 158 Mt (106-252 Mt) up to an average optimistic average of 396 Mt (264-631 Mt). The theoretical CO2 storage capacity in the oil-bearing limestones of the Upper Ordovician Saldus Formation was estimated at the end of the Enhanced Oil Recovery cycle using the CO2 (CO2-EOR) as an average of 110 Mt (65-144 Mt). The E6 structure was estimated as the most prospective and the largest for CO2 geological storage in the Baltic Region with a total average CO2 storage capacity of about 500 Mt.Time-lapse numerical seismic modelling was applied to analyze the feasibility of CO2 storage monitoring in the E6. The novelty of this approach was the coupling of the chemically induced petrophysical alteration effect of CO2-hosting rocks, measured in the laboratory during the CO2 injection-like experiment, with time-lapse numerical seismic modelling. According to changes in the amplitude and two-way travel times in the presence of CO2, reflection seismic could detect CO2 injected into the deep aquifer formations even with low CO2 saturation values. Our results showed the effectiveness of the implemented time-lapse rock physics and seismic methods in the monitoring of the CO2 plume evolution and migration in the E6.The new concept of techno-ecological synergy of the CCUS project with different eco-friendly renewable energy recovery technologies, which support circular economy targets, is presented. The concept of the CCUS project includes six innovative elements of techno-ecological synergy: (1) CGS, (2) Geothermal energy recovery during CO2 geological storage (CPG), (3) CO2-EOR, (4) underground hydrogen storage (UHS), (5) solar energy and (6) wind energy recovery. This concept should maximise efficiency, minimize the carbon footprint of the full-chain CCUS process and demonstrate the “winx” situation (where “x” is a number of additional benefits of the project).We demonstrated an example of the project supporting also a win5 global situation (that is, a win-win scenario with a minimum of five potential global outcomes): greenhouse gas emissions (GHGE) reduction, (2) economic profitability, (3) increased CO2 storage capacity, (4) public acceptance and (5) retargeting of oil and gas businesses.Small wind offshore floating plant installed around the rig and solar panels covering free surfaces of the rig and a compact geothermal plant using CO2 (20 times smaller than a conventional plant) will produce renewable energy added to the project electricity net to cover the energy needs of the project. The excess energy will be used by compact hydrogen production plant established directly on the rig. The produced hydrogen could be stored underground and when needed, transported by ship to the port. For the first time, we estimated hydrogen storage capacity in the E6-B, the smaller compartment of the E6 offshore structure as 30 Kt.This scenario is a basis for the new concept of CO2 and hydrogen storage site marketing: how to retarget fossil fuel business (the depleted oil and gas fields) into the storage-targeted and renewable energy business, permitted to achieve the carbon-free energy transition using principles of circular economy and sustainable use of resources and environment.

Characteristics of water alternating CO2 injection in low-permeability beach-bar sand reservoirs

Water flooding can be ineffective in highly heterogeneous low-permeability beach-bar sand reservoirs. The introduction of CO2 flooding helps boost the oil production of the reservoirs but only in an early stage. During the late stage of flooding, gas channeling would occur. Water alternating gas (CO2) (WAG) process can be used to delay gas channeling and improve the effect of CO2 injection, though its adaptability to beach-bar sand reservoirs remains unclear. In order to clarify CO2 injection characteristics in these reservoirs, experiments were carried out in high-temperature high-pressure NMR on-line displacement experiment apparatus to simulate different flooding modes on synthetic cores that can reflect the vertical heterogeneity of beach-bar reservoirs. Different CO2 injection modes were implemented on these cores and the displacement characteristics and residual oil distribution features during both WAG injection and continuous CO2 injection were analyzed quantitatively and qualitatively. The results show that the scheme of WAG injection after continuous CO2 injection can obtain better oil displacement efficiency than that of the scheme of continuous CO2 injection after WAG injection, but there is no significant difference in respect of oil displacement efficiency of WAG flooding between the mode of bar-injection – beach-production (injection into bar sand – production from beach sand) and the mode of beach-injection – beach-production (injection into and production from beach sand), with the former mode having a higher oil recovery rate. The wider pore-size distribution range of microscopic residual oil after WAG injection shows great potential of enhancing oil recovery from subsequent continuous gas injection. When WAG injection is implemented prior to continuous CO2 injection, the displacement effect of the latter is more significant. This research may provide a theoretical basis for CO2 EOR in this type of reservoirs.

Study Describes Challenges, Opportunities of CO2 EOR in China

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209468, “CCUS In China: Challenges and Opportunities,” by Hu Guo, China University of Petroleum; Xiuqin Lyu, Sinopac Northwest Oil Field Company; and En Meng, China University of Petroleum, et al. The paper has not been peer reviewed. One of the most attractive carbon capture, usage, and storage (CCUS) applications in China is that of carbon dioxide (CO2) enhanced oil recovery with captured CO2 (CCS EOR). CO2 EOR with captured CO2 presents an important path for China. The complete paper reviews the progress of CCUS technology in China. The current challenges of CCS EOR include high capture costs, small scale, low incremental oil recovery, and huge capital input. The costs can be significantly reduced when the scale is enlarged to the commercial level and transportation costs are further reduced by pipelines or trains. Importance of CCUS At the time of writing, 49 CCUS pilots or field tests had been conducted or were under construction in China. CCUS demonstration projects were small-scale, and no projects involving more than 1.0 million tons of CO2 per year (mtpa) were conducted. 1.3 million tons of CO2 were estimated to be injected in 2020 for EOR use. The authors reference a study that mentions nine CO2 EOR projects. Among these, the Jilin oilfield project was notable for its size of 2.0 million cumulative tons of CO2 injected. CO2-enhanced coalbed methane was also an attractive option for China, and several field tests were conducted by CNOOC and its partners. Another notable CCUS demonstration project involved the Shaanxi Jinjie power plant. This was the largest coal-fired power postcombustion (PC) CO2-capture project, with a capture capacity of 0.15 mtpa. The project began in November 2019. In January 2021, equipment installation was completed. By June of 2021, 168 trial operations had been passed. The captured CO2 will be used for EOR. This demonstration project will gain knowledge to reduce PC CO2 emissions, a great challenge for China because the majority of electricity is based on coal combustion. Gas processing and power plants rank first for the US in terms of CCUS project numbers. Power plants also rank first in the number of CCUS projects for China, but the number of natural-gas-processing projects was much less.