Miscible CO2 Research Articles

Genetic algorithm to optimize miscible water alternate CO2 flooding in heterogeneous clastic reservoir

Genetic algorithm to optimize miscible water alternate CO2 flooding in heterogeneous clastic reservoir

Mechanisms of Miscible and Immiscible scCO‌2 Displacement Efficiency: Analytical Evaluation of Experimental conditions

CO2 injection has proven to be one of the most successful EOR (Enhanced Oil Recovery) methods, as compared with other injection gases CO2 miscibility with oil is easier to achieve. During gas injection into reservoirs, oil might be bypassed on either a micro- or macroscopic scale because of different types of heterogeneities. In this work, the performance of first-contact-miscible (FCM) and immiscible (IM) CO2 injections were investigated experimentally using outcrop sandstone core samples. Decane was also used as the hydrocarbon phase as it has a relatively low minimum miscibility pressure (MMP) with CO2 (12.4 MPa). Core flooding experiments were conducted at two pressures of 17.2 MPa and 9.6 MPa and the common temperature of 343 K. Furthermore, analytical calculations of dimensionless numbers are used to study the dominant forces and mechanisms which are correlated with the results of the core flooding experiments. The impacts of gravity, swelling and vaporization on the end results were inferred from the oil recoveries, variations in the pore pressure and dimensional analysis. For CO2 injection in homogeneous core samples, a maximum recovery of 93.5% and 76% was achieved for the FCM and IM displacements, respectively. The higher recovery results of FCM is attributed to the vanishing capillary pressure between displacing and displaced phases. Dimensional analysis showed that the flow is at the capillary-gravity equilibrium at immiscible conditions, while there is dominance of gravity-viscous forces at miscible conditions.

Coupled miscible carbon utilization-storage processes in fractured shales

Geological carbon storage and utilization is commonly-accepted as the most feasible approach to mitigate carbon emissions in energy transition period. Shale reservoirs attract special attentions due to their huge amounts of reserves and wide distributions worldwide. In the meantime, improved technologies are required to implement the production and storage projects in the shale reservoirs because dramatic changes of phase and production properties occur and most conventional methods become inapplicable. Here, first, a field-scale numerical reservoir simulation is developed to model the miscible CO2 utilization in the fractured shale reservoirs. Second, an analytical nanoscale-extended theory model is proposed to calculate a series of basic physiochemical properties and production parameters by including the intermolecular interactions and confinement effects. Third, the CO2 post-production storage is specifically investigated in fractured shale reservoirs. All models developed in this study are compared with and verified by the literature data. Continuous CO2 injection is applied for an 800-day EOR process in the fractured shale reservoir. With the production time, the reservoir oil saturations and pressures become lower, while the gas saturations and cumulative oil productions/oil recovery factors become higher. Moreover, the confinement effect is beneficial to enhance oil productions. The miscible CO2 injection is achieved through, at least in majority, the vaporization process based on the compositional analysis results. On the other hand, in comparison with the conventional reservoirs, the shale reservoirs with nanopores are proven to be more promising for the post-production CO2 storage due to larger caprock sealing pressure, maximum storage height, and storage capacity. The amount of CO2 trapped in the reservoir with confinement is three time as large as that without confinement. Overall, this study provides numerical simulation and analytical theory for the investigation and application of the coupled processes of miscible CO2 utilization and post-production geological storage in fractured shales.

Determination of miscible CO2 flooding analogue projects with machine learning

Using analogue reservoirs for comparison and benchmarking is a comprehensive method for ensuring accurate measurement and gaining a better understanding of potential oil recovery enhancement prospects. The approach of leveraging information from analogue reservoirs is extended to CO 2 EOR project management in this study. We present a novel application of machine learning clustering algorithms to the rapid identification of analogues for new projects without having to sift through massive amounts of data. We use machine learning clustering methods to group successfully executed miscible CO 2 flooding projects into clusters of projects with similar fluid/reservoir characteristics and to identify analogues for new target projects. Porosity, permeability, oil gravity and viscosity, reservoir pressure and temperature, minimum miscibility pressure (MMP), and depth were all input parameters. Data from nearly 200 miscible CO 2 EOR projects around the world were clustered using the Agglomerative Hierarchical Clustering Algorithm (HCA), K-Means, and K-Median techniques. To reduce information redundancy in high-dimensional data, Principal Component Analysis was used as a pre-processing step. Three evaluation indices (the Davies Bouldin, Calinski Harabasz, and Silhouette Coefficient Scores) were used to compare the efficiency of the clustering algorithms and choose the best one for this dataset. A Principal Component – weighted Euclidean distance similarity metric was computed using three existing miscible CO 2 flooding projects (Weyburn, Hansford Marmaton, and Paradis) as test cases to confirm the clustering results. The clustering analysis identified five different classes of miscible CO 2 projects, each with its reservoir and fluid characteristics. Type 1 projects, in general, are those that are carried out primarily in shallow carbonate reservoirs at the lowest temperatures and pressures of any database project with typical porosity and permeability. More than 60% of Type 2 projects are in sandstone reservoirs. They are at shallower depths with lower temperatures, pressures, porosities, and permeabilities than project Type 4. Type 3 projects are typically undertaken in carbonate reservoirs with medium depths and temperatures but the highest reservoir pressures. This project type has medium porosity and permeability. In comparison to project Type 2, Type 4 primarily consists of projects conducted in sandstone formations at great depths with high reservoir temperatures and pressures. The porosity and permeability of these project types are average. Finally, Type 5 projects are typically undertaken in sandstone formations at average depths, temperatures, and pressures, but with the greatest porosity and permeability of all project types. In addition to the clustering analysis, the distance similarity metric used in this work identified projects that were most like the test miscible CO 2 flooding project cases. Key rock and fluid properties, well types, and best infill drilling strategies, recovery improvement strategies, and production performance can all be learned from identified analogue projects. This data can be used to improve the operational, technical, field, and well-planning decisions for new CO 2 flooding projects. The workflow demonstrated in this paper is easily adaptable to data sets from other flooding projects. • K-Means clustering model can be used effectively to categorize miscible CO 2 flooding projects. • The global miscible CO 2 flooding projects in collated dataset can be broadly divided into five classes by K-means clustering model. • A calculated Principal Component – weighted Euclidean distance similarity metric can be used to successfully validate cluster groupings. • Ideal analogue projects with similar fluid and reservoir properties can be identified with K-Means and the distance-based metric

Mechanistic simulation of fracture effects on miscible CO2 injection

Miscible injection of carbon dioxide (CO2) into oil reservoirs as an Enhanced Oil Recovery (EOR) method has proved to be highly advantageous. According to the volume of the world's recoverable oil resides inside the fractured reservoirs, investigation of the controlling parameters in the efficient injection of miscible CO2 is of paramount importance, mainly owing to the intricacies and complexities associated with this process. This complexity in fractured reservoirs arises due to the presence of two distinct media for fluid transfer (i.e., matrix and fracture network) and the corresponding differences in fluid velocities. Accordingly, performance of miscible carbon dioxide injection in these reservoirs was investigated through mechanistic simulation model in the form of dual-porosity (DP), and dual porosity-dual permeability (DPP). Moreover, due to limited supply and high injection costs of this gas in its pure form, performance of the miscible CO2 injection combined with C1, N2, and H2S was also surveyed and compared to pure gas injection case. A sensitivity analysis was also performed based on fracture porosity, fracture horizontal and vertical permeability, matrix horizontal permeability, block height shape factor, matrix capillary pressure, and impure injected components in DP and DPP models, showing that matrix horizontal permeability and capillary pressure have the greatest, and porosity has the lowest impact on miscibility performance and oil recovery in these models. In the end, after investigating the effect of different injection cases on miscibility performance and oil recovery, it was concluded that the highest oil recovery in miscible gas injection obtained through optimization of a gas composition having the lowest minimum miscibility pressure (MMP) and the lowest density.

Oil production enhancement, asphaltene precipitation and permeability damage during CO2-SAG flooding of multi-layer sandstone reservoirs

The process of CO2-SAG flooding involves conventional miscible CO2 flooding until breakthrough (BT), followed by a period of CO2 soaking or shut-in, and then a continuation of the miscible CO2 flooding. The SAG process provides different improvements in the oil recovery for different positions of each layer in multilayer reservoirs, and has different effects on the distribution of pore throat blocking and adsorption of asphaltene to mineral surfaces. In this paper, both miscible CO2-SAG and conventional CO2 flooding experiments have been carried out at reservoir conditions and on multi-layer systems composed of 3 long cores each with increasing porosities and permeabilities, which were connected in parallel. After CO2-SAG flooding oil recovery factors (RF) of the low, medium and high permeability cores were 7.7%, 8.3%, and 7.6% higher compared to the RFs after CO2 flooding, respectively. The respective fractional oil production (FOP) of each long core was 10.6%, 27.7%, and 61.6% after CO2-SAG flooding, with less difference between each long core than for CO2 flooding. After CO2 flooding, the permeability of the high permeability core at the injection end dropped by 24.5–25.8%, which is 5.5–14.3% higher than the value at the outlet. The permeability decrease due to CO2-SAG flooding was 0.7–9.7% higher than that due to CO2 flooding, and the distribution of permeability decline was more homogeneous. The contribution of the total permeability decrease attributable to asphaltene particle blockage due to CO2 flooding was 84.7–62.7%, 5.2–10.1% higher than that due to CO2-SAG flooding, gradually decreasing along the flow direction. Complex two-phase flow of oil and gas is more likely to cause pore throat blockage instead of causing the adsorption of asphaltene precipitation.

Experimental study on the diffusion characteristics of the miscible ScCO2/oil system based on the droplet interface shrinkage behavior

Determination of the diffusion coefficient of a miscible Supercritical CO2 (ScCO2) and oil system is substantial for guiding the CO2 EOR and greenhouse gas geological storage practices. Based on the oil droplet interface shrinkage behavoir after reaching miscibility with the surrounding CO2, the diffusion coefficients of a miscible ScCO2/paraffin system were measured with the Dynamic Pendant Drop Volume Analysis (DPDVA) technique. A refined diffusion coefficient derivation model was proposed and validated for the CO2/oil system at the Minimum Miscibility Pressure (MMP) points. The measurements were performed under pressure range of 9–21 MPa and temperature range of 40.6–81.2 ℃. Exponential relationships have been obtaind between the diffusion coefficient and the pressure and the intrinsic oil viscosity, revealing the fact that the diffusion rate increases significantly with the system pressure after reaching miscibility. On the other hand, it is found higher temperature could retard the diffusion process between the ScCO2 and the oil phases under miscible conditions.

Miscible Water Alternating Gas CO2 Injection Performance Analysis as Efforts to Improve Oil Recovery Factors in Field CW

The Enhanced Oil Recovery (EOR) method aims to increase oil production. One of the EOR methods is CO2 injection. CO2 injection mechanism is by expanding the volume of oil, reducing viscosity, and reducing the mobility ratio. The purpose of the study was to compare the recovery factor gain in the waterflood, Miscible CO2 Continuous injection, and Miscible WAG CO2 injection methods with a three-dimensional simulation methodology using CMG Compositional software in the CW Field. From the CW field, a sectoral model was chosen to be studied, namely the area of the CW-A well and the CW-B well because the two areas have different reservoir conditions. The optimal injection well pattern for the CW-A Well area and the CW-B Well area is Inverted Five Spot. CO2 injection is said to be miscible because the injection pressure and reservoir pressure are above MMP (2800 psi) and mixing occurs between CO2 and oil to form a homogeneous phase. The optimal CW-A (Low Permeability) well area using the 4 PV CO2 Continues Injection scenario (injection rate 31.8 Mscf/d) produces an RF of 61.18%. Optimal CW-B (High Permeability) Well Area using CO2-WAG 2 PV injection scenario in 90 days (3 months) cycle, WAG Ratio 1:3 (injection water rate 20,036.84 bwpd and gas injection rate 33.75 Mscf/d) produces RF of 61.76%.

Experimental study of oil recovery from pore of different sizes in tight sandstone reservoirs during CO2 flooding

The investigation of tight oil reservoirs has become a significant area of interest in unconventional oil development. CO 2 flooding is considered an effective oil recovery method for tight oil reservoirs as it can significantly increase oil recovery when it reaches supercritical condition and becomes miscible with oil. Although extensive research has been conducted on CO 2 flooding, the oil recovery from pore of different sizes in tight sandstone reservoirs at different pressures has not been thoroughly investigated. In this study, we analyzed the petrology features and the pore structure of a reservoir using casting section and scanning electron microscope (SEM) images. Subsequently, three cores with different permeability from the reservoir were subjected to CO 2 flooding experiments at different pressures. A nuclear magnetic resonance (NMR) spectrometer was used to quantify the oil recovery. Amott-Harvey index was measured to study the effect of CO 2 flooding on core wettability. Results indicate that the total oil recovery and the oil recovery of smaller pores increase as the pressure increasing. The oil recovery of the larger pores does not increase continuously. The oil recovery of the smaller pores is more dependent on pressure than that of the larger pores, and the total oil recovery is related to the oil recovery of smaller pores. Meanwhile, the supercritical and miscible CO 2 has a positive effect on oil recovery. After CO 2 becoming supercritical and miscible, the cores still have potential to produce more oil with the pressure increasing. As the pore structure is playing a significant role in oil recovery, the core with a higher proportion of the volume of larger pores is relatively easy to produce more oil at low pressure. Amott-Harvey index shows CO 2 flooding can significantly reduce the hydrophilicity of cores. This study reveals the mechanism of pressure effect on oil recovery during CO 2 flooding in tight sandstone reservoirs. The results can be used to improve the efficiency of reservoir development. • The features and the pore structure of a tight sandstone reservoir were analyzed using casting section and SEM images. • NMR was used to quantify the oil distribution before and after CO 2 flooding to explain the oil recovery of tight reservoirs. • The oil recovery of tight oil reservoir is strongly related to pore structure as well as CO 2 injection pressure. • CO 2 flooding can significantly reduce the hydrophilicity of cores with the increase of pressure.

Geochemical Investigation of CO2 Injection in Oil and Gas Reservoirs of Middle East to Estimate the Formation Damage and Related Oil Recovery

The injection performance of carbon dioxide (CO2) for oil recovery depends upon its injection capability and the actual injection rate. The CO2–rock–water interaction could cause severe formation damage by plugging the reservoir pores and reducing the permeability of the reservoir. In this study, a simulator was developed to model the reactivity of injected CO2 at various reservoir depths, under different temperature and pressure conditions. Through the estimation of location and magnitude of the chemical reactions, the simulator is able to predict the effects of change in the reservoir porosity, permeability (due to the formation/dissolution) and transport/deposition of dissoluted particles. The paper also presents the effect of asphaltene on the shift of relative permeability curve and the related oil recovery. Finally, the effect of CO2 injection rate is analyzed to demonstrate the effect of CO2 miscibility on oil recovery from a reservoir. The developed model is validated against the experimental data. The predicted results show that the reservoir temperature, its depth, concentration of asphaltene and rock properties have a significant effect on formation/dissolution and precipitation during CO2 injection. Results showed that deep oil and gas reservoirs are good candidates for CO2 sequestration compared to shallow reservoirs, due to increased temperatures that reduce the dissolution rate and lower the solid precipitation. However, asphaltene deposition reduced the oil recovery by 10%. Moreover, the sensitivity analysis of CO2 injection rates was performed to identify the effect of CO2 injection rate on reduced permeability in deep and high-temperature formations. It was found that increased CO2 injection rates and pressures enable us to reach miscibility pressure. Once this pressure is reached, there are less benefits of injecting CO2 at a higher rate for better pressure maintenance and no further diminution of residual oil.

Study on Oil and Gas Amphiphilic Surfactants Promoting the Miscibility of CO2 and Crude Oil.

In order to cope with the global climate crisis, carbon capture, utilization, and storage are the key technologies to achieve carbon neutrality, and it is an elegant geological utilization method for the oil and gas industry to improve the recovery rate of crude oil by using CO2. However, in practical applications, the problem of low miscibility of CO2 and crude oil, resulting in low oil displacement efficiency, cannot be avoided. Thus, finding an appropriate method to increase the utilization rate of CO2 is a worth in-depth study. In light of this, this paper carries out the study on improving the CO2 flooding efficiency by using oil and gas amphiphilic surfactants. First of all, according to the molecular structure theory and the solubility experiment of surfactants in CO2, five kinds of surfactants and two kinds of additives with good performance of oil and gas were selected. Then, three experiments were conducted to explore the mechanism of the selected surfactants. The main mechanism of promoting the miscibility of CO2–crude oil is to reduce the interfacial tension of the oil and gas phases, followed by increasing the volume expansion of crude oil and reducing the viscosity of crude oil. Finally, through the slim tube displacement experiment, the oil displacement efficiency effect of adding the compound systems of SPO5/n-pentanol was simulated. The results show that the oil displacement efficiency is significantly higher than that of pure CO2 flooding, and the pressure of miscibility reduces at the same time. The selected reagents have a good effect of promoting miscibility. Therefore, this is an effective method to improve the geological utilization of CO2.

Carbon Capture Utilization for Biopolymer Foam Manufacture: Thermal, Mechanical and Acoustic Performance of PCL/PHBV CO2 Foams.

Biopolymer foams manufactured using CO2 enables a novel intersection for economic, environmental, and ecological impact but limited CO2 solubility remains a challenge. PHBV has low solubility in CO2 while PCL has high CO2 solubility. In this paper, PCL is used to blend into PBHV. Both unfoamed and foamed blends are examined. Foaming the binary blends at two depressurization stages with subcritical CO2 as the blowing agent, produced open-cell and closed-cell foams with varying cellular architecture at different PHBV concentrations. Differential Scanning Calorimetry results showed that PHBV had some solubility in PCL and foams developed a PCL rich, PHBV rich and mixed phase. Scanning Electron Microscopy and pcynometry established cell size and density which reflected benefits of PCL presence. Acoustic performance showed limited benefits from foaming but mechanical performance of foams showed a significant impact from PHBV presence in PCL. Thermal performance reflected that foams were affected by the blend thermal conductivity, but the impact was significantly higher in the foams than in the unfoamed blends. The results provide a pathway to multifunctional performance in foams of high performance biopolymers such as PBHV through harnessing the CO2 miscibility of PCL.

The miscible behaviors and mechanism of CO2/CH4/C3H8/N2 and crude oil in nanoslits: A molecular dynamics simulation study

Using molecular dynamics simulations, we have investigated the miscible behaviors of different gas (CO2, N2, CH4, C3H8) and different crude oils in nanoslits at 413 K and 60 MPa. In this study, the effect of gas type, the polarity and the chain length of crude oil on the miscible process of gas and crude oil is explored. The simulation results show that CO2, CH4, C3H8 and N2 are more miscible with apolar crude oil than polar crude oil due to the stronger interaction between polar crude oil and silica surface. It is worth noting that the solubility of polar crude oil in CO2 phase is higher than that in hydrocarbon gas phase and N2 phase. In addition, it is found that the chain length of crude oil could affect the dissolution of crude oil in hydrocarbon gas and N2. In contrast, it has a negligible effect on the miscibility of crude oil and CO2. The simulation results could provide valuable guidance for enhancing oil recovery in the development of deep and ultra-deep reservoirs.

Effects of miscible CO2 injection on production recovery

Carbon dioxide (CO2) injection is implemented into the reservoir to further improve the oil production efficiency, by mixing with oil at reservoir condition, and becomes miscible. The miscibility affects the oil to become swelled and less viscous and thus easily flow through the reservoir. Most of the (CO2) EOR projects has higher recovery factor in miscible condition. Therefore, this article aims to determine the effects of the miscible (CO2) injection on production recovery in the Cornea Field. The Cornea Field is located in Browse Basin, Western Australia. It is a simple trap structure which is elongated and formed by unfaulted drape anticline over an eroded high basement. The importance of this research is that (CO2) injection has not been implemented in the Cornea Field since it is a complex reservoir. However, research showed that there was a high potential production recovery in this field. Therefore, research needs to be conducted to determine the effectiveness of the (CO2) injection on production recovery in this field. The model was validated, by comparing MMP obtained from the simulation model and correlation methods. The MMP of this reservoir is above 38 Bar. Sensitivity analysis on reservoir pressure, reservoir temperature and (CO2) injection rate was investigated. Oil production increases with the increase in reservoir pressure and reservoir temperature. As the (CO2) injection rate increases, oil production also increased. From the result, hence, this study should contribute to the knowledge gap in Cornea Field.

CO2 mobility control improvement using N2-foam at high pressure and high temperature conditions

The high mobility of CO2 in porous media is an issue in most subsurface CO2 projects worldwide, demonstrated by uncontrolled and rapid migration through the reservoir, early well breakthroughs and poor sweep efficiency. Improved mobility control of CO2 is needed to accelerate and improve the value-creation from subsurface CO2 projects, both in terms of energy produced and volumes of CO2 stored. Field-proven conformance and mobility control techniques, such as foam, provide a cost-effective and sustainable alternative to overcome geological and process constraints observed with CO2 flow in reservoirs.In this laboratory study, we have investigated CO2 mobility control by foam in sandstone core samples at typical North Sea reservoir conditions, 220 barg and 100°C, respectively. Two important aspects related to any field application of foam have been evaluated and discussed: I) Can strong CO2-foams be generated at reservoir conditions using AOS surfactant? If not, II) can relatively simple modifications to the foam system be made to improve foam properties and CO2 mobility control?Our results show that only high-mobility CO2-foams with low degree of CO2 mobility reduction are obtained at 220 barg and 100°C. An easy way to improve the foam properties at reservoir conditions is suggested by changing the gas-phase in foam to nitrogen (N2). The N2-foams display improved foam generation performance, larger mobility control in terms of mobility reduction factors (MRF) and ability to block subsequent CO2 injection.An alternative strategy for applying foam for CO2 conformance and mobility control in subsurface CO2 projects, which emerges from this study, is to initiate the foam treatment with nitrogen followed by subsequent CO2 injection to change the main direction of CO2 flow to enhance the displacement area or reduce uncontrolled CO2 production between the injecting and producing wells (as illustrated in the graphical abstract). The possible mechanisms explaining the observed differences in foam properties using CO2 versus N2, including implications that could be helpful for future studies and CO2 field applications are discussed further in more detail.The efficiency and limitations of miscible CO2 flooding to recover oil and simultaneously store CO2 after extensive water flooding are also demonstrated in this article, which are relevant to enhanced oil recovery (EOR) and subsequent CO2 storage applications, known as the Carbon Capture Utilization and Storage (CCUS).

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

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

Life-Cycle Optimization of the Carbon Dioxide Huff-n-Puff Process in an Unconventional Oil Reservoir Using Least-Squares Support Vector and Gaussian Process Regression Proxies

SummaryIn this work, we investigate the efficient estimation of the optimal design variables that maximize net present value (NPV) for the life-cycle production optimization during a single-well carbon dioxide (CO2) huff-n-puff (HnP) process in unconventional oil reservoirs. A synthetic unconventional reservoir model based on Bakken Formation oil composition is used. The model accounts for the natural fracture and geomechanical effects. Both the deterministic (based on a single reservoir model) and robust (based on an ensemble of reservoir models) production optimization strategies are considered. The injection rate of CO2, the production bottomhole pressure (BHP), the duration of injection and the production periods in each cycle of the HnP process, and the cycle lengths for a predetermined life-cycle time can be included in the set of optimum design (or well control) variables. During optimization, the NPV is calculated by a machine learning (ML) proxy model trained to accurately approximate the NPV that would be calculated from a reservoir simulator run. Similar to the ML algorithms, we use both least-squares (LS) support vector regression (SVR) and Gaussian process regression (GPR). Given a set of forward simulation runs with a commercial compositional simulator that simulates the miscible CO2 HnP process, a proxy is built based on the ML method chosen. Having the proxy model, we use it in an iterative-sampling-refinement optimization algorithm directly to optimize the design variables. As an optimization tool, the sequential quadratic programming (SQP) method is used inside this iterative-sampling-refinement optimization algorithm. Computational efficiencies of the ML proxy-based optimization methods are compared with those of the conventional stochastic simplex approximate gradient (StoSAG)-based methods. Our results show that the LS-SVR- and GPR-based proxy models are accurate and useful in approximating NPV in the optimization of the CO2 HnP process. The results also indicate that both the GPR and LS-SVR methods exhibit very similar convergence rates, but GPR requires 10 times more computational time than LS-SVR. However, GPR provides flexibility over LS-SVR to access uncertainty in our NPV predictions because it considers the covariance information of the GPR model. Both ML-based methods prove to be quite efficient in production optimization, saving significant computational times (at least 4 times more efficient) over a stochastic gradient computed from a high-fidelity compositional simulator directly in a gradient ascent algorithm. To our knowledge, this is the first study presenting a comprehensive review and comparison of two different ML-proxy-based optimization methods with traditional StoSAG-based optimization methods for the production optimization problem of a miscible CO2 HnP.

Numerical investigations of foam-assisted CO2 storage in saline aquifers

CO2-foam injection is a promising technology for reducing gas mobility and increasing trapping within the swept region in deep brine aquifers. In this work, a consistent thermodynamic model based on a combination of the Peng-Robinson equation of state (PR EOS) for gas components with an activity model for the aqueous phase is implemented to accurately describe the complex phase-behavior of the CO2-brine system. The phase-behavior module is combined with the representation of foam by an implicit-texture (IT) model with two flow regimes. This combination can accurately capture the complicated dynamics of miscible CO2 foam at various stages of the sequestration process. The Operator-Based Linearization (OBL) approach is applied to improve the efficiency of the highly nonlinear CO2-foam problem by transforming the discretized nonlinear conservation equations into a quasi-linear form based on state-dependent operators. We first validate our simulation results for enhanced CO2 dissolution in a small domain with and without the presence of a capillary transition zone (CTZ). Then a 3D unstructured reservoir is used to examine CO2-foam behavior and its effects on CO2 storage. Simulation studies show good agreement with analytical solutions in both cases with and without CTZ. Besides, the presence of a CTZ enhances the CO2 dissolution rate in brine. Foam simulations show that foams can reduce gas mobility effectively by trapping gas bubbles and inhibit CO2 from migrating upward in the presence of gravity, which in turn improves the sweep efficiency and opens the unswept region for CO2 storage. In the long run (post-injection), with the increasing effects of dissolution, the mechanism of residual trapping, due to the presence of foam, may not be significant. This work suggests a possible strategy to develop an efficient CO2 storage technology.

Oil production performance and reservoir damage distribution of miscible CO2 soaking-alternating-gas (CO2-SAG) flooding in low permeability heterogeneous sandstone reservoirs

Miscible CO 2 -SAG flooding is an enhanced form of CO 2 flooding, which mitigates the inadequate CO 2 -crude oil interaction by adding a CO 2 soaking period just after CO 2 breakthrough (BT). The addition of the soaking process results in improvements in the recovery of residual oil during the secondary CO 2 flooding process, which may vary across the reservoir, and lead to differential changes in the distribution of permeability decline and wettability variation due to asphaltene precipitation. In this work, CO 2 -SAG and simple miscible CO 2 flooding experiments were carried out at reservoir conditions (90 °C, 23 MPa) on low permeability long composite cores with progressively decreasing permeability in the direction of injection. The results show that the overall oil recovery factor (RF) was 72.8% after CO 2 -SAG flooding, 11% higher than simple miscible CO 2 flooding (61.8%). The oil RFs of individual core plugs decreased progressively along the core (i.e., with decreases in initial permeabilities). The inadequate interaction occurs more for those cores with low permeability and high residual oil saturation close to the outlet. Consequently, recovery is improved more in lower permeability cores, particularly in medium sized pores of these cores. By contrast, the permeability decline of core plugs after CO 2 -SAG flooding was 8–20%, 1.0–4.5% higher than that after simple miscible CO 2 flooding. The permeability decline of the cores close to the injection end showed a slight increase, and continued to decrease along the injection direction after CO 2 flooding. However, the overall decline in core permeability at the injection end was greater than that at the outlet. The soaking process led to a more homogeneous distribution of permeability decline and a greater increase in permeability decline. The distribution of wettability variation was consistent with the distribution of residual oil saturation after CO 2 flooding. The wettability variation was larger and the cores in middle had the biggest values after SAG flooding. • Oil recovery is improved more for lower permeability cores at the outlet, particularly in medium sized pores after SAG flooding. • The soaking process leads to a greater increase in permeability decline due to asphaltene precipitation. • The distribution of wettability variation is consistent with the distribution of residual oil saturation after CO 2 flooding.

Geomechanical analysis of formation deformation and permeability enhancement due to low-temperature CO2 injection in subsurface oil reservoirs

Several benefits of CO2 injection are reported in the literature such as its ability to mitigate greenhouse gas emissions and the increase in oil recovery at a low cost. However, the correlated reservoir-engineering problems with low-temperature CO2 injection including formation damage and leakage risk are still uncertain and has not been comprehensively investigated. This research examines the effect of low-temperature CO2 on lowering of formation breakdown pressure, and the associated formation damage from a geomechanical prospective. This study presents the coupling of the equilibrium stress equation, the system energy balance equation, continuity equation, and saturation equation to develop thermoporoelastic model for the reservoir rock. We determined the cooling-induced formation damage due to decrease in temperature and thermal stresses, formation contraction and tensile stresses, and examine its effects on formation properties, stresses, joint and fracture stability. We observed that low-temperature CO2 would create a low thermal stress region and thus the formation could fail in tension. This process might increase formation permeability but it would decrease the stability of reservoir, basement and caprock. We analyzed several factors affecting formation deformation such as injection rate for both miscible and immiscible CO2 flooding, formation porosity, depth, temperature, and formation breakdown pressure. We also compared our results and findings with experimental data, finding excellent match and similar consequences. Furthermore, as a sequence of low-temperature CO2 injection, the initial formation breakdown pressure was initially at 2560 psi and it reduced to 1928 for immiscible case and 1270 psi for miscible case in the selected case study. We also propose that shallow reservoirs should be avoided for CO2 capture and storage because of stability issues.