CO2 Injection Rate Research Articles

Evaluation of Relationship Between Post-injection Plume Stability and Leakage Risks

One of the critical questions for geologic CO2 storage is how long should a storage site be monitored after the injection is stopped. A storage site operator is required to demonstrate that the storage site is evolving towards long-term stability and the injected CO2 as well as reservoir pressure do not pose any threat including to the groundwater. Migration and evolution of injected CO2 plume depend on site-specific geologic structure, storage reservoir properties as well as operational conditions. While injected CO2 plume may continue to evolve after injection is stopped, its dynamic evolution does not directly imply imminent leakage risk. Leakage risks depend on multiple factors including not only CO2 presence but also reservoir pressure and the characteristics of potential leakage pathways. We performed a modeling based study to evaluate the relationship between post-injection plume migration and leakage risks. Our hypothetical case study is based on the Rock Springs Uplift in southwestern Wyoming in USA. We used a numerical model to perform multiple sets of reservoir simulations each with 29 equi-probable realizations of reservoir permeability heterogeneity, simulating different injection scenarios. We applied newly developed moment-based plume mobility metrics to characterize the migration and evolution of injected CO2 plume. The plume mobility metrics provided detailed analyses of the effect of reservoir permeability heterogeneity and CO2 injection rate on spatial and dynamic evolution of CO2 and overpressure plume. Next, we assessed the potential leakage risks using the integrated assessment modelling approach developed by US DOE’s National Risk Assessment Partnership (NRAP). The combined leakage risk assessment and plume mobility analyses results indicate that lack of CO2 plume stability (or non-zero plume mobility) may not directly imply groundwater aquifer endangerment and the leakage risks are dependent on multiple factors, including presence of wells and their locations and types. This paper is a condensed version of a peer-reviewed paper by Pawar et al [1] published in the International Journal of Greenhouse Gas Control.

Developing the world’s largest CO2 Injection System – a history of the Gorgon Carbon Dioxide Injection System

The Gorgon CO2 Injection System is a key element of the Gorgon LNG Project on Barrow Island. Two gas fields currently supply the LNG plant including the Gorgon Field, which contain c. 14% CO2 content. Rather than vent the separated reservoir CO2 into the atmosphere, the Gorgon JVPs undertook to develop the CO2 Injection System, which was designed and constructed to inject around 3.5 million tonnes per annum into the Dupuy Formation, a Jurassic sandstone unit below Barrow Island in the Barrow Sub-basin. Chevron Australia Pty Ltd (Chevron), as operator on behalf of the Gorgon joint venture participants, has been working on the development of the project, through early concept select, appraisal, final concept selection, detailed design, construction, commissioning and now early operations. This work commenced in 2003, with project approvals in 2009. Since then, 17 wells have been drilled, pipelines and compression facilities constructed and installed, baseline monitoring data acquired, and injection operation has commenced. It is expected that the Gorgon CO2 Injection System will have a 40-plus year lifespan. The volume and rate of CO2 injection makes it the largest CO2 injection project for geological storage undertaken to date. Early results indicate that the injectivity is better than originally forecast. Chevron and the Gorgon joint venture participants will continue to monitor performance against expectations and revise assumptions, models and forecasts over time.

CO <sub>2</sub>-Brine Co-Injection in Carbonate Aquifers Using Geothermal Doublets

In the aim to reduce GHG emissions, CO2 storage in deep and large saline aquifers has been recognized as a technology being able to abate drastically CO2 emissions and participate to the ‘two-degree scenario (2DS)” strategy. Current challenges are focused on increasing CO2 storage capacity from Mega-Tones to Giga-Tones in order to have a sensible impact on the reduction of CO2 atmospheric concentration and global warming. Numerous large-scale facilities will have to be deployed in coming years through regional or state hubs to capture, transport and store a CO2 coming from various industrial feeds: natural gas processing, fertilizer production, steel manufactures, cement plants, hydrogen production, wood or biomass boilers, BECCS, etc. When these CCS hubs are far from small to medium CO2 industrial emitters (+/- 100 kt/year), local CCS projects could also be considered through small size CO2 geological storages: depleted hydrocarbon reservoirs or aquifers. A CO2-brine co-injection in geothermal doublets could be for example an alternative process for low-intensity CO2 storage. A geothermal doublet consists in two wells drilled within a “hot” aquifer: a hot water producer and a cold-water injector separated around 1 000 to 2 000 m away. The main idea of this process is to inject a CO2 dissolved in water at surface, within normal geothermal operations for several years before breakthrough at the producer occurs (or economic re-circulation limit is attained). Injected CO2 concentration will be constrained by its solubility limit at the injection conditions (pressure, temperature and salinity). In this work, numerical modelling was done using CO2STORE option of ECLIPSE simulator. In order to evaluate the process feasibility and efficacy, a synthetic 3-D gridded geological model was build using various bibliographical data on typical geothermal installations. A sensitivity analysis in the synthetic model was performed in order to determine key parameters that maximize the CO2 storage capacity and breakthrough time at the producer. Initial reservoir temperature, injection temperature, injection rate, CO2 molar fraction at injection and gas relative permeability endpoint (Krg) were evaluated. Experimental design technique permitted to identify injection rate and CO2 molar fraction as the most relevant parameters in the process. Four operational scenarios were evaluated: (i) continuous CO2-brine co-injection: two injection rates were studied (200 and 300 m3/h); (ii) seasonal-varying brine-CO2 co-injection: 100 m3/h during spring/summer and 200 m3/h during fall/winter periods; (iii) alternated brine and brine- CO2 co-injection: normal geothermal operations during 6-months and brine- CO2 co-injection the others 6-months evaluated at two injection rates (200 and 300 m3/h); (iv) continuous CO2 injection: classical CO2 injection in supercritical state at equivalent CO2 injection rate that CO2-brine co-injection cases. As mentioned before, injection CO2 molar fraction is one of the key parameters in the process. Higher the injection CO2 molar fraction leads in higher the storage capacity. On the other hand, lower the temperature higher the solubility, so lower temperatures are preferred in order to maximize storage capacity. For all cases, injection temperature was fixed at 50°C and two molar fractions were evaluated (1.5 and 2 %). When solubility limit is reached at injection conditions a dense phase is formed in the aquifer (CO2 in super-critical state), that decrease storage capacity. It was also evidenced that reducing injection rate also prevents the development of free CO2 dense phase. Scenario (ii) resulted in the optimum storage capacity and the longest breakthrough time in the producer. The heterogeneity of the carbonate reservoirs is considered as a main challenge on the process performance, therefore a sensitivity analysis considering different geological scenarios was also performed considering different facies extension during the static model generation. It was shown that heterogeneities in the reservoir can affect negatively CO2 storage capacity when high permeability channels create preferential flow paths between injector and producer. Typical modelling in geothermal applications using homogeneous geological features was also evaluated resulting in very optimistic breakthrough time (ten-times longer than heterogeneous models). Spacing between wells was also addressed, by considering three spacing: 1000, 1500, 2000 m. Results showed that the longer the spacing the better the storage capacity due to breakthrough retardation. This study demonstrates that the combination of geothermal operation and CO2 co-injection can be suitable for small to medium GHG emitters while validated simulation software can be used to properly design the optimum operational strategy if a detailed geological model is used.

Performance Optimization of CO2 Huff-n-Puff for Multifractured Horizontal Wells in Tight Oil Reservoirs

In this paper, the sensitivity factors of CO2 huff-n-puff for multifractured horizontal wells (MFHWs) in tight oil reservoirs were investigated through an experimental test and numerical simulation. The pressure-volume-temperature (PVT) experiment and the slim tube experiment are used to understand the interaction mechanism between CO2 and crude oil, and the minimum miscibility pressure (MMP) of the CO2-crude oil system is 17 MPa. The single-well model was firstly established to analyze the sensitivity factors on production performance of MFHWs by using CO2 huff-n-puff. The controlling factors of CO2 huff-n-puff for MFHWs in tight oil reservoirs were divided into three categories (i.e., reservoir parameters, well parameters, and injection-production parameters), and the impact of individual parameter on well performance was discussed in detail. The range of reservoir parameters suitable for CO2 huff-n-puff of MFHWs is obtained. The reservoir permeability is from 0.1 mD to 1 mD, the reservoir thickness changes from 10 m to 30 m, and the reservoir porosity is from 7% to 12%. Based on the reservoir parameters of the target reservoir, the reasonable well and fracture parameters are obtained. The sensitivity intensity was followed by the horizontal well length, fracture conductivity, fracture spacing, and fracture half-length. CO2 injection-production parameters are further optimized, and the sensitivity intensity was followed by the single-cycle cumulative CO2 injection rate, the soaking time, the injection rates, and the production rates. It provides a reference for parameter optimization of CO2 huff-n-puff for MFHWs in tight oil reservoirs.

Enhanced gas recovery by CO2 injection: Influence of monovalent and divalent brines and their concentrations on CO2 dispersion in porous media

This study aims to experimentally investigate the roles of different brine types and concentrations on the longitudinal dispersion coefficient (KL) during enhanced gas recovery by CO2 injection. Core flooding process was used to simulate the displacement of CH4 by supercritical CO2 in a Buff Berea core sample at a pressure and temperature of 1400 psig and 50 °C respectively, and a CO2 injection rate of 0.3 ml/min. Individual NaCl, KCl, CaCl2 and MgCl2 solutions were prepared as test brines with ionic strengths (IS) of 1M, 2M, and 3M. The results revealed that, at lower IS of 1M, MgCl2 and CaCl2 brines had the lowest KL while the monovalent brines showed relatively higher KL. Divalent brines showed a higher degree of salting out effects at higher concentrations resulting in higher KL. The salting and drying out effects of divalent brines were responsible for higher CH4 recovery at 2M IS as CH4 comes out of solution. A hyperbolic-type relationship exists between the two properties (KL and IS), where KL decreases from 0 to 1M IS, and then increases sharply at IS > 1M – this behaviour is most pronounced in the divalent brines. Lowest contamination of the recovered CH4 was found to be between formation water salinities of 5–15 wt%, regardless of salt type, during EGR by CO2 injection and sequestration. This study will not only present new knowledge on EGR process but will also provide an avenue for establishing a screening criterion based on formation water salinity for effective EGR process. This is a first experimental investigation which establishes the relationship between salt types and concentration and the KL in porous media.

Numerical simulation and optimization of injection rates and wells placement for carbon dioxide enhanced gas recovery using a genetic algorithm

The aim of CO2 enhanced gas recovery (CO2-EGR) is to extract more natural gas from depleted gas reservoirs and simultaneously sequestrate large amount of CO2. To achieve these dual objectives, the optimization of CO2 injection strategy in CO2-EGR is proposed to achieve maximum benefit. Thus, the focus of this work is to study CO2-EGR by numerical simulation and optimization. For this purpose, a 3D reservoir model with ‘five-spot’ well pattern (an injection well and four production wells) is established for simulations using the multiphase simulator TOUGH2, and the main focus is on optimization of CO2 injection rate and well placements by coupling the genetic algorithm (GA) with TOUGH2. Simulations are performed to determine the optimal injection rate for both two types of injection wells placements, one vertical injection well with number of perforations at various depth and orthogonal horizontal wells on top of the reservoir. The results show that multipoint perforations in the vertical injection well and the horizontal injection wells with appropriate length show improvement in natural gas recovery and CO2 storage compared to the injection location at the reservoir bottom. More importantly, the optimized injection rate determined by GA-TOUGH2 can substantially improve the natural gas recovery factor for both vertical and horizontal well injection. After computing a number of optimized cases, it’s shown that the case employing the horizontal injection wells with optimized injection rate of 0.0778 kg/s achieves the maximum recovery of 67.21% and maximum CO2 storage efficiency of 69.54%, equal to 23.88 × 106 kg of natural gas exploited from the depleted reservoir and 74.52 × 106 kg of CO2 stored in pore volume of 1.81 × 106 m3 of the reservoir. This case also has minimum injection pressure jump of 0.08 MPa thereby reducing the risk of formation fracture and CO2 leakage. However, by conducting a simple cost/benefit analysis, it is determined that this optimally performing case is not the best economically because of higher drilling cost of horizontal well compared to a vertical well. It is found that a vertical well with two suitably placed perforations with optimized injection rate of 0.1025 kg/s is economically superior since the previously used production wells can be reused for CO2 injection, which can therefore reduce both the equipment and the drilling costs. It is hoped that the findings of this work should provide some insights into the optimization of CO2-EGR with maximum economic benefit for implementation in industrial practice.

Assessment of relationship between post-injection plume migration and leakage risks at geologic CO2 storage sites

We performed a numerical modeling study focused on the relationship between post-injection plume migration and leakage risks at geologic CO2 storage sites. We use the model for Rock Springs Uplift in southwestern Wyoming as our hypothetical case study. We performed multiple sets of reservoir simulations, each with 29 equi-probable realizations of reservoir permeability heterogeneity, simulating different injection scenarios. Three different CO2 injection rates and an open and compartmentalized reservoir are evaluated. We applied newly developed moment-based plume mobility metrics to characterize migration and evolution of injected CO2 plume. We applied the integrated assessment model developed by the National Risk Assessment Partnership (NRAP-IAM-CS) using the results of reservoir simulations of CO2 and overpressure to quantify potential CO2 and brine leakage through wells and resulting groundwater aquifer impacts. The plume mobility metrics provide detailed analyses of the effect of reservoir permeability heterogeneity, CO2 injection rate, and compartmentalization on CO2 plume and overpressure areas, velocities, and spreading. Based on leakage risk assessment our results indicate that lack of injected CO2 plume stability (or non-zero plume mobility) may not directly imply groundwater aquifer endangerment and the leakage risks are dependent on multiple factors beyond CO2 plume stability including presence of wells and their locations and types.

Analysis of Microseismicity and Reactivated Fault Size to Assess the Potential for Felt Events by CO2 Injection in the Illinois Basin

ABSTRACTThe results of monitoring of carbon dioxide (CO2) injection at the Illinois Basin—Decatur Project (IBDP) and the companion Illinois Industrial Carbon Capture and Sequestration Sources (IL-ICCS) project—have shown that reservoir response to fluid pressure changes can vary significantly at different injection locations within the same reservoir. Predrill reservoir characterization is important to identify potentially seismogenic faults. However, interpretations of newly reprocessed 3D seismic reflection data illustrate the challenges related to their identification in a region dominated by faulting with small vertical offsets. Faults interpreted in the 3D seismic volume range from ∼300 to 1200 m wide and are in the same size range as faults that could have been the source of historical events up to Mw 2.7 in central Illinois. The array of monitoring sensors that was installed for the IBDP continues to collect data, as injection operates in IL-ICCS, the second injection well. CO2 injection rates for the IL-ICCS well are on average 1.7 times the rates injected in the IBDP well, but a significantly reduced rate of induced seismicity is observed. This article presents results of passive seismic monitoring for the duration of the project to date, integrating active and passive seismic data to develop a new interpretation of the subsurface structure at the Decatur site that explicitly identifies pathways for fluid flow into the basement leading to induced seismicity, and provides a geological explanation for the sharp reduction of induced seismicity during injection at higher rates into the second well. The use of seismic moment to estimate the length of seismogenic slip planes in the local subsurface suggests that faults large enough to produce felt seismicity are unlikely to be present at or near the Decatur site.

Great SCO2T! Rapid tool for carbon sequestration science, engineering, and economics

CO2 capture and storage (CCS) technology is likely to be widely deployed in the coming decades in response to major climate and economics drivers: CCS is part of every clean energy pathway that limits global warming to 2 ​°C or less and receives significant CO2 tax credits in the United States. These drivers are likely to stimulate the capture, transport, and storage of hundreds of millions or billions of tonnes of CO2 annually. A key part of the CCS puzzle will be identifying and characterizing suitable storage sites for vast amounts of CO2. We introduce a new software tool called SCO2T (Sequestration of CO2Tool, pronounced “Scott”), a dynamic CO2 injection and storage model, to rapidly characterize saline storage reservoirs. The tool is designed to rapidly screen hundreds of thousands of reservoirs, perform sensitivity and uncertainty analyses, and link sequestration engineering (injection rates, reservoir capacities, plume dimensions) to sequestration economics (costs constructed from around 70 separate economic inputs). We describe the novel science developments supporting SCO2T including a new approach to estimating CO2 injection rates and CO2 plume dimensions as well as key advances linking sequestration engineering with economics. We perform a sensitivity and uncertainty analysis of geology parameter combinations—including formation depth, thickness, permeability, porosity, and temperature—to understand the impact on carbon sequestration. Through the sensitivity analysis, we show that increasing depth and permeability both can lead to increased CO2 injection rates, increased storage potential, and reduced costs, while increasing porosity reduces costs without impacting the injection rate (CO2 is injected at a constant pressure in all cases) by increasing the reservoir capacity. Through uncertainty analysis—where formation thickness, permeability, and porosity are randomly sampled—we show that final sequestration costs are normally distributed with upper bound costs around 50% higher than the lower bound costs. While site selection decisions will ultimately require detailed site characterization and permitting, SCO2T provides an inexpensive dynamic screening tool that can help prioritize projects based on the complex interplay of reservoir, infrastructure (e.g., proximity to pipelines), and other (e.g., land use, legal) constraints on the suitability of certain regions for CCS.

Geomechanical modeling for CO2 geologic sequestration in Asmari reservoir—south of Iran

Due to releasing large amount of greenhouse gases in the atmosphere, some countries were committed to control the expansion of these gases into the environment. The best way to solve this issue is carbon capturing and sequestration (CCS). Injection of CO2 into the depleted reservoirs is one of the most favorite recommended solutions. Iran contains variety of depleted reservoirs. This makes good opportunity for geological sequestration of CO2. However, lack of caprock integrity may result in leakage of gas from the reservoir and could endanger the entire project and lead to serious problems. In this paper, a 3D reservoir and geomechanical models are built for a reservoir in Asmari formation that is sealed by Gachsaran-1 caprock. The parameters that are investigated in this challenging reservoir are vertical displacement of caprock, pore pressure changes, horizontal stresses changes, and finally caprock integrity during injection process. The caprock integrity has been studied by Mohr-Coulomb failure criterion, but we observed no failure. In addition, the variation of rock parameters such as poison ratio and young modulus was investigated on the integrity of caprock. The results illustrated that the caprock integrity in this reservoir is not significantly sensitive to above parameters. However, it is sensitive to the horizontal/vertical stress ratio changes. The increase of this ratio would increase the possibility of failure. The vertical displacement of caprock funds to be about 22 mm. The critical rate of CO2 injection is determined approximately 35.5 kiloton/month after 10 years of injection, which makes this reservoir a suitable option for the geological sequestration.

Evaluation of CO2 Storage in a Shale Gas Reservoir Compared to a Deep Saline Aquifer in the Ordos Basin of China

As a new “sink” of CO2 permanent storage, the depleted shale reservoir is very promising compared to the deep saline aquifer. To provide a greater understanding of the benefits of CO2 storage in a shale reservoir, a comparative study is conducted by establishing the full-mechanism model, including the hydrodynamic trapping, adsorption trapping, residual trapping, solubility trapping as well as the mineral trapping corresponding to the typical shale and deep saline aquifer parameters from the Ordos basin in China. The results show that CO2 storage in the depleted shale reservoir has merits in storage safety by trapping more CO2 in stable immobile phase due to adsorption and having gentler and ephemeral pressure perturbation responding to CO2 injection. The effect of various CO2 injection schemes, namely the high-speed continuous injection, low-speed continuous injection, huff-n-puff injection and water alternative injection, on the phase transformation of CO2 in a shale reservoir and CO2-injection-induced perturbations in formation pressure are also examined. With the aim of increasing the fraction of immobile CO2 while maintaining a safe pressure-perturbation, it is shown that an intermittent injection procedure with multiple slugs of hug-n-puff injection can be employed and within the allowable range of pressure increase, and the CO2 injection rate can be maximized to increase the CO2 storage capacity and security in shale reservoir.

Investigation on CO2 permeation in water-saturated porous media with disordered pore sizes

CO2 sequestration in saline aquifers is considered to be a promising method for climate mitigation. Studies of the subsurface flow mechanisms of CO2–brine are important for evaluation of sequestration potential and security. However, this process is complicated by the intrinsic heterogeneity of reservoir rocks. The main objective of this study was to identify CO2 distribution and saturation related to changing injection conditions, and to comprehensively compare the characteristics of different drainage processes, under small scale heterogeneous condition. An X-ray computed tomography machine and a micromodel were introduced to investigate the CO2/brine drainage process from pore to core scale in a wide range of injection rates at static and transient states, respectively. Four types of drainage experiments were conducted. Horizontal and vertical (upward) flow directions in a micromodel setup at ambient conditions and vertical (upward and downward) flow directions in a core-flood setup at in-situ conditions. Based on experimental results, it is found that, a higher injection rate gives rise to a higher displacement efficiency but a lower sweep efficiency. The stability of CO2 displacing front become weak with drainage development. The difference in pore structure leads to different CO2 saturation variation with CO2 injection rates change. Even the sand pack is almost homogenous at core scale, the impact of heterogeneous porosity is enhanced with increasing flow rates in upward drainage, while it weakens in downward drainage.

Field scale numerical modeling of heat extraction in geothermal reservoir based on fracture network creation with supercritical CO2 as working fluid

In geothermal reservoirs, the typically low natural permeability needs to be stimulated for an efficient heat extraction. In this work, the stimulation of heat extraction as well as the associated CO2 sequestration in geothermal reservoirs is studied, based upon supercritical CO2-EGS (enhanced geothermal system) concept in a 3D continuum anisotropic damage-permeability model under thermal–hydraulic–mechanical framework. The developed approach has been applied into the planned Dikili EGS project in Turkey. The simulation results show that a fracture network with a stimulated reservoir volume of 8.71 × 107 m3 is created by injecting 90,000 kg CO2 in 250 h. A priority channel with high gas saturation in the fracture network is formed during heat extraction because of the viscosity difference between CO2 and water. In general, for both water and CO2 injection, the driven pressure and average thermal capacity shows a positive correlation with injection rate, while the eventual produced temperature shows a negative correlation with injection rate. In comparison with water as working fluid for heat extraction, CO2 owns some benefits like low driven pressure and high eventual produced temperature. Besides, a positive correlation between sequestrated CO2 mass and injection rate is observed. Approximately 950, 000 tons of CO2 are geologically sequestrated under injection rate of 100 kg/s over 30 years of production period.

Subcore Scale Fluid Flow Behavior in a Sandstone With Cataclastic Deformation Bands

AbstractAccurate determination of petrophysical and multiphase flow properties in sandstones is necessary for reservoir characterization, for instance for carbon dioxide and hydrogen storage in geological formations or for enhanced oil recovery. Several studies have examined the effect of heterogeneities, such as fractures, bedding planes, and laminae, on core‐scale fluid flow. However, the influence of deformation bands that commonly occur in high porosity sandstones is poorly understood. In this study, we consider a core sample of Navajo sandstone characterized by diagonally oriented deformation bands and two laminae perpendicular to the core axis, as determined from micro X‐ray computed tomography (micro‐CT). Positron emission tomography is used to derive the single phase hydrodynamic properties of the core. A CO2 drainage experiment is conducted in the water‐saturated core and imaged with a medical X‐ray CT scanner. Medical CT enables CO2 saturation quantification with increasing CO2 injection rate. Experimental results and the accompanying numerical simulations indicate that both the laminae and the deformation bands act as capillary barriers, with the laminae forming weaker capillary barriers than the deformation bands. The deformation bands have lower permeability and porosity due to grain crushing, and a very high capillary entry pressure that inhibits CO2 migration across the bands. At the reservoir scale, deformation bands form conjugate sets and are often present in thick anastomosing clusters that define lozenge‐shaped compartments. These findings have important consequences for subsurface fluid flow. For example, the presence of deformation bands may reduce the storage capacity and injectivity in carbon storage reservoirs.

Improving Oil Recovery Through Fracture Injection and Production of Multiple Fractured Horizontal Wells

Abstract Well production rates decline quickly in the tight reservoirs, and enhanced oil recovery (EOR) is needed to increase productivity. Conventional flooding from adjacent wells is inefficient in the tight formations, and Huff-n-Puff also fails to achieve the expected productivity. This paper investigates the feasibility of the inter-fracture injection and production (IFIP) method to increase oil production rates of horizontal wells. Three multi-fractured horizontal wells (MFHWs) are included in a cluster well. The fractures with even and odd indexes are assigned to be injection fractures (IFs) and recovery fractures (RFs). The injection/production schedule includes synchronous inter-fracture injection and production (s-IFIP) and asynchronous inter-fracture injection and production (a-IFIP). The production performances of three MFHWs are compared by using four different recovery approaches based on numerical simulation. Although the number of RFs is reduced by about 50% for s-IFIP and a-IFIP, they achieve much higher oil rates than depletion and CO2 Huff-n-Puff. The sensitivity analysis is performed to investigate the impact of parameters on IFIP. The spacing between IFs and RFs, CO2 injection rates, and connectivity of fracture networks affect oil production significantly, followed by the length of RFs, well spacing among MFHWs, and the length of IFs. The suggested well completion scheme for the IFIP methods is presented. This work discusses the ability of the IFIP method in enhancing the oil production of MFHWs.

Enhancement of bitumen recovery from the oil sand in an alkaline solution using ultrasound irradiation and carbon dioxide

Herein, we demonstrated the enhancement of bitumen recovery from the oil sand in a concentrated alkaline solution using ultrasound irradiation and carbon dioxide. The alkaline solution allowed the separation of bitumen and sand; however, it was difficult to collect bitumen via aeration. CO2 exhibited a high contact angle for bitumen even at a high pH. Therefore, we attempted to use CO2 for bitumen recovery under ultrasound irradiation, increasing the number of collisions between bitumen and the CO2 bubbles; thus, the bitumen recovery ratio exhibited a high value of approximately 70% even at a low CO2 injection rate of 20 ml min−1.

Leveraging operational information from wastewater injection wells to evaluate CO2 injection performance for carbon storage applications in the Appalachian Basin

AbstractGeologic parameters, geophysical logging, injection testing, and operational metrics from wastewater injection wells were integrated to develop a preliminary design of a carbon storage facility in the Appalachian Basin. A scattered group of 10–20 commercial wastewater injection wells dispose off produced water from oil and gas wells in the region, utilizing a sequence of stacked deep saline formations for injection zones. These wastewater injection wells provide practical benchmarks for understanding the feasibility of carbon dioxide (CO2) storage. Geologic models were developed based on characterization data from the wastewater injection wells. Reservoir simulations were calibrated according to injection testing and operational data from the wastewater injection wells. Long‐term operational data on injection flow rates and pressures measured in the wastewater injection wells were especially useful to evaluate the performance of carbon storage applications. The simulations were used to estimate injection pressures, radius of CO2 saturation, and pressure response for industrial scale CO2 storage applications. Results were also used to provide a design basis in terms of number of injection wells, well spacing, area of review, injection system components, monitoring plan, and CO2 pipeline distribution system. The analysis demonstrates that there is sufficient injectivity in the deep saline formations in the west‐central Appalachian Basin to store commercial volumes of anthropogenic CO2. The geologic system appears suitable for supporting CO2 injection rates of 0.5–1.0 million metric tons per year at injection pressures below formation fracture pressure in a single well. The long‐term operational data of wastewater injection wells within the study area suggested a lower permeability‐thickness values than indicated by initial reservoir tests. A workflow for developing realistic permeability values for input into reservoir simulations is presented. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

Effect of CO2 injection on interfacial tension of oil-formation water system under high temperature and pressure

The interfacial interaction between CO2 and oil and water is one of the important factors affecting the effect of CO2 enhanced oil recovery. Taking dead oil in Zhoucheng Oilfield as an example, the variation of interfacial tension between crude oil-carbonated water two-phase system and oil-formation water two-phase system was studied by pendant drop method. The influence of different CO2 saturation on the equilibrium interfacial tension of oil-formation water system and changes of equilibrium interfacial tension between crude oil-carbonated water system and crude oil-formation water system were analyzed. Moreover, previous studies did not reflect the experimental phenomena of extracting light hydrocarbons from oil droplets by CO2 through gas-water interface. This paper provides experimental research and analysis for this experimental phenomenon. The results show that the equilibrium interfacial tension of crude oil-carbonated water system decreases with the increase of pressure, and the dissolution and diffusion of the system becomes more and more obvious with the increase of pressure. The medium exchange occurs between oil and carbonated water, and the phenomenon of partial miscibility occurs. There is a threshold pressure value between crude oil and formation water with different CO2 saturation. Each group of samples has its threshold pressure and optimum CO2 injection rate. It’s not that the more CO2 injection, the better oil displacement effect. This research provides a reference for us to save the cost of CO2 flooding.

CO2 injectability and CH4 recovery of the engineering test in qinshui Basin, China based on numerical simulation

An important CO2-ECBM (CO2 enhanced coalbed methane) engineering test will be carried out in #3 coal seam of Qinshui basin, China this year. This study is a preliminary work of CO2-ECBM engineering test with an aim at optimizing the engineering proposal and evaluating the effectiveness of CO2-ECBM. In this study, considering the competitive adsorption and diffusion of CO2 and CH4, seepage of gas and water, coal deformation, the dynamic evolution of coal seam porosity and permeability, and heat conduction and convection between coal and fluid, a fully coupled THM (thermo-hydro-mechanical) mathematical model for CO2-ECBM was established. The modelling was followed by a detailed discussion of the engineering well group’s CO2 injection and CH4 output characteristics under different CO2 injection pressures. The results confirm that CO2 injection has a positive effect on improving CH4 production. Within the simulated time, the CH4 recovery was enhanced by 4.26%–12.80%. Although the CO2 injectability of the engineering well group reduced significantly due to the drop in permeability near the CO2 injection well, the engineering well group has considerable CO2 storage potential. Under simulation conditions, the CO2 storage capacity for single CBM well is up to 0.73×105 - 2.54×105 m3 (standard temperature and pressure, STP). Increasing CO2 injection pressure can expand the coverage of CO2, thereby significantly improving the CH4 production rate and CO2 storage capacity. In addition, the permeability decrease caused by CO2 injection mainly affects the CO2 injection rate and storage capacity with weak influence on CH4 production and recovery.

Carbon dioxide transport in radial miscible flooding in consideration of rate-controlled adsorption

As an important technology in improving oil recovery, CO2 miscible flooding has achieved great success in many oil fields. However, studies on CO2 transport in porous media are mostly based on equilibrium adsorption in one-dimensional displacement where rate-controlled adsorption is not taken into consideration. In this work, we develop a radial convection–dispersion model, which simultaneously combines rate-controlled adsorption, convection, and dispersion. Based on this model, four dimensionless groups representing CO2 dispersion, adsorption capacity, flow rate, and kinetic rate groups are proposed for the first time. Subsequently, the Barakat–Clark forward and backward difference methods are combined to solve the mathematical model. CO2 concentration and adsorption at different positions in the porous media (including the effluent concentration and adsorption histories) are then calculated. Furthermore, the effects of the parameters on CO2 transport behavior are studied in detail. The results reveal that CO2 gradually moves forward with the increase in the CO2 injection volume. Once CO2 reaches a certain position, its concentration there increases and an S-shaped curve is formed. Moreover, the adsorption capacity at this position also increases significantly, and the changing rate is much higher than CO2 concentration. CO2 effluent concentration grows more uniform, and the breakthrough occurs earlier with increased dispersion velocity and CO2 injection rate and decreased adsorption capacity and adsorption rate. The mathematical model developed in this study is of great importance in predicting CO2 transport behavior in radial miscible flooding.