CO2 Channeling Research Articles

CO2-EOR and storage in a low-permeability oil reservoir: Optimization of CO2 balanced displacement from lab experiment to numerical simulation

CO2 flooding can enhance oil recovery associated with CO2 storage, but its performance is often damaged by the gas channeling due to reservoir heterogeneity and the large CO2 mobility. Most current research focuses on chemical agents to prevent CO2 channeling, while there is less attention to reservoir engineering methods. In this study, a concept of balanced displacement was introduced to delay the gas channeling and achieve balanced development in a multi-layer and low-permeability block Y21. A series of lab experiments and numerical simulations were conducted to explore the best CO2 flooding scheme by considering three aspects of optimization. Layer grouping and well pattern and spacing adjustment were applied to seek for balanced utilization of geological reserves; gas channeling plugging and mobility control measures were taken to increase the CO2 swept volume; and the pressure control and injection-production optimization were carried out to improve the oil displacement efficiency. The results show that CO2 can reach miscible with crude oil in block Y21 under the original formation pressure, but gas breakthrough quickly occurs along the hydraulic fractures to the top of the structure. To obtain a balanced displacement, the layers of block Y21 should be divided into two groups for separate development. The current well pattern and spacing are suitable for CO2 flooding, which need not be adjusted. WAG injection with acid-resistant gel particles and foaming agents can be used to inhibit gas channeling. These measures can significantly improve the CO2 displacement profile in block Y21. The oil recovery factor can be increased by 10.01%, and 5.41 × 104 tons of CO2 can be stored. This study can provide valuable guidance for CO2-EOR and storage in low-permeability oil reservoirs.

A novel dual-network CO2-responsive particle gel for mitigating CO2 channeling and leakage in hydrocarbon recovery and carbon storage

In this work, we developed and systematically evaluated a novel dual-network CO2-responsive preformed particle gel (DN-CRPPG) to address CO2 channeling and leakage in hydrocarbon recovery and carbon sequestration. The work was proven an effective effort to overcome the insufficiency of traditional channeling-control chemicals due to severe dehydration and degradation in contact with CO2. We focused on placement and plugging behavior of the DN-CRPPG in fractured reservoirs under various circumstances. Results of high-pressure vessel test show that DN-CRPPG expanded further when exposed to supercritical CO2. The responsive swelling ability was enhanced with the increase of pressure. Core flooding and plugging experiments show significantly improved CO2-channeling control ability compared with traditional non-responsive particle gels. Three key mechanisms were observed to be responsible for the improved performance. First, the CO2-responsive behavior resulted in volume swelling of DN-CRPPG. Therefore, the void spaces among the particles were occupied by the swelled gel particles, making the DN-CRPPG exhibit an in-situ self-reinforcement behavior in plugging ability. Second, the dual network structure with a relatively rigid network and a more flexible one enhances its mechanical ability and resistance to CO2 flush. Third, the CO2-repsonsiveness enabled the new gel a remarkably higher resistance to CO2 than that to water, while traditional gel is the opposite. This behavior is favorable for balancing the mobility of CO2 and water as the fact that CO2 itself is much more mobile due to low viscosities. Significant CO2 breakthrough mitigation and oil recovery improvement were demonstrated after treatment with the new gel (>30 %). This work is supposed to provide guidance for improving the success of hydrocarbon recovery and carbon storage by more effectively mitigating CO2 channeling and leakage.

A Study on the Plugging Effect of Different Plugging Agent Combinations during CO2 Flooding in Heterogeneous Reservoirs

Gas channeling control is key to improving CO2-flooding efficiency. A traditional plugging system has disadvantages, such as poor adaptability and stability, leading to the poor plugging effect of CO2 channeling in heterogeneous reservoirs and difficulty in controlling the subsequent CO2 injection pressure. To achieve a significant plugging effect and effectively control the subsequent CO2 injection pressure, a heterogeneous physical model of gas channeling in a horizontal well was established, and plugging experiments were conducted using four different combinations of plugging agents during CO2 flooding. Three evaluation parameters were defined, including the temperature field variation coefficient (TFVC), medium-permeability diversion rate (MPDR), and subsequent injection pressure coefficient (SIPC). The plugging effect of different combinations of plugging agents during CO2 flooding in heterogeneous reservoirs was analyzed. The results show that the plugging effect after using a combination of plugging agents was significantly better than after using a single plugging agent, and different plugging agent combinations had distinct characteristics. The strong–medium–weak (S-M-W) combination had the best MPDR for subsequent CO2 flooding, but the SIPC was the highest. The strong–weak–strong–weak (S-W-S-W) and weak–strong–weak–strong (W-S-W-S) combinations could effectively control the SIPC. These results indicate that plugging using the S-W-S-W and W-S-W-S combinations can achieve an effective plugging effect and reasonably control the subsequent CO2 injection pressure. This work provides a personalized design scheme for effective gas channeling control and maintenance of appropriate injection pressure during CO2 flooding in heterogeneous reservoirs.

Rheological properties and gas channeling plugging ability in CO2 flooding of a hydrophobic nanoparticle-enhanced smart gel system constructed with wormlike micelles

Carbon Dioxide capture, oil displacement and Storage (CCUS-EOR) projects inject captured carbon dioxide into developed reservoirs suitable for gas displacement. However, due to the strong heterogeneity of the reservoir, the CO2 channeling is seriously. In this study, using tung oil as renewable chemical raw material, environmentally friendly surfactants and hydrophobic nano-SiO2 were synthesized as the main components of smart gel system. Fourier transform infrared (FT-IR), nuclear magnetic resonance spectrum (NMR) and thermogravimetric analysis (TGA) were used to characterize the chemical structure. The smart gel system was obtained through the CO2 response experiment. The system can cycle back and forth between low and high viscosity multiple times, and a good temperature resistance and salt resistance. The results of rheological experiments and dynamic light scattering show that the nanoparticles promote the growth and entanglement of WLMs. The plugging capacity and auxiliary CO2-EOR performance of the system were evaluated through the laboratory displacement test. The intelligent response system has good gas channeling plugging ability, plugging efficiency reaches 97 %, and CO2 flooding oil recovery efficiency increases by 22.2 %. In addition, in the acute toxicity assessment, the bio-based gel system from plants showed slightly toxic, which is expected to become a new generation of green oilfield chemicals.

Investigation of Polymer-Assisted CO2 Flooding to Enhance Oil Recovery in Low-Permeability Reservoirs.

CO2 flooding is a favorable technical means for the efficient development of low-permeability reservoirs, and it can also contribute to the realization of net-zero CO2 emissions. However, due to the unfavorable viscosity ratio and gravity overriding effect, CO2 channeling will inevitably occur, seriously affecting its storage and displacement effects. This paper conducts a systematic study on the application of polymer-assisted CO2 flooding in low-permeability reservoirs. Firstly, the polymer agent suitable for low-permeability reservoirs is optimized through the viscosity-increasing, rheological, and temperature- and salt-resistant properties of the solution. Then, the injectivity performance, resistance-increasing ability, and profile-improving effect of the polymer solution were evaluated through core experiments, and the optimum concentration was optimized. Finally, the enhanced oil recovery (EOR) effects of polymer-assisted and water-assisted CO2 flooding were compared. The results show that the temperature-resistant polymer surfactant (TRPS) has a certain viscosity-increasing performance, good temperature resistance performance, and can react with CO2 to increase the solution viscosity significantly. Meanwhile, TRPS has good injection performance and resistance-increasing effect. The resistance increasing factor (η and η') of TRPS-assisted CO2 flooding increases with increased permeability, the concentration of TRPS solution, and injection rounds. Considering η' and the profile improvement effect comprehensively, the application concentration of TRPS should be 1000 mg/L. The EOR effect of TRPS-assisted CO2 flooding is 8.21% higher than that of water-assisted CO2 flooding. The main effective period is in the first and second rounds, and the best injection round is three. The research content of this paper can provide data support for the field application of polymer-assisted CO2 flooding in low-permeability reservoirs.

Reservoir heterogeneity controls of CO2-EOR and storage potentials in residual oil zones: Insights from numerical simulations

Residual oil zones (ROZs) have large potential for CO2 enhanced oil recovery (EOR) and geologic storage. During CO2 injection, the migration of CO2 in ROZs controls the performance of both EOR and storage. However, it has not been clearly visualized and understood that how geological heterogeneity factors control the transport of CO2 in ROZs. In this study, the oil recovery performance and geologic storage potential during continuous CO2 injection in a representative ROZ are studied based on geostatistical modelling and high-fidelity three-phase flow simulation. We examined the influence of autocorrelation length of permeability, global heterogeneity (Dykstra–Parsons coefficient), and permeability anisotropy on cumulative oil recovery and CO2 retention fraction. Simulation results indicate that, as the permeability autocorrelation length increases, the cumulative oil recovery and CO2 storage efficiency decrease. This results from the accelerated migration of CO2 along high permeability zones (i.e., gas channeling). The increase in global heterogeneity and permeability anisotropies can lead to low oil recovery and poor CO2 sequestration performance, depending on the degree of CO2 channeling. The net utilization ratio of CO2 (CO2 retained/oil produced) unfavorably increases with both autocorrelation length and Dykstra–Parsons coefficient, but decreases with the increase in kv/kh. Such a decrease is attributed to enlarged swept volume induced by gravity override. The study provides important implications for field-scale CO2 EOR and storage applications in ROZs.

From nonionic to zwitterionic: Novel CO2-responsive zwitterionic wormlike micelles based on zwitterionic surfactant and bola-type asymmetric diamine

CO2 enhanced oil recovery (CO2-EOR) is one of the CO2 utilization methods which can also geo-sequestrate greenhouse gases. Due to the weak adsorption on rock surface and excellent viscoelasticity performance, CO2-responsive zwitterionic wormlike micelles (WLMs) has been recognized as a promising method to control CO2 channeling. A novel CO2 responsive zwitterionic WLMs was developed by blending N-octadecyl-N,N-dimethyl-3-ammonio-2-hydroxy-1-propane-sulfonate (OHSB), N,N,2,2-tetramethyl-1,3-propanediamine (TADPA) and sodium salicylate (NaSal). The responsive behaviors induced by varying agents (CO2 and HCl) are systematically studied by rheology tests and cryo-TEM measurements. The molecular structures of products are confirmed by 1H and 13C NMR. Moreover, the responsive mechanism is discussed in detail. The OHSB/NaSal/TADPA system shows morphological transformations between spherical micelles (a good flowing capacity) and WLMs (conducive to plugging) before and after purging CO2. The viscoelasticity and molecular structure of the system with CO2 bubbling is different from that with HCl titration, because TADPA molecules can react with CO2 to form a novel zwitterionic product: NH+(CH3)2-CH2-C(CH3)2-CH2-NHCO2− (TAH+DPACO2−, 78.95 %–83.52 %). This work provides a new strategy for the design of CO2-responsive zwitterionic WLMs and their applications in CO2 utilization schemes, including clean fracturing, mobility control, and CO2 foam flooding, etc.

Experimental Evaluation of Combined Plugging System for CO2-Improved Oil Recovery and Storage

High-performance CO2-improved oil recovery (IOR) and storage technology is one of the most promising measures for global oilfield companies to achieve zero carbon targets. Due to the severe heterogeneity of most petroleum reservoirs and the significant density difference between CO2 and reservoir fluid, the efficiency of CO2-IOR and storage is usually limited. In this paper, a high-temperature and high-pressure 30 cm core displacement experiment was used to study the CO2 conformance control performance of both the single- and the combined plugging system in long sandstone cores. The single systems evaluated included polymer gels, CO2 foams, and CO2-responsive thickening polymer (CO2-RTP) systems. The combined systems were pairwise combinations of the three of them. Results show that the pressure rise and maximum breakthrough pressure of the gel system were the highest among three single-plugging systems. Its plugging efficiency was the highest, reaching 86.13%. At the same time, its gas production reduction rate was also the highest, reaching 95.71%. In the parallel 30 cm core plugging experiments, three combined plugging systems all showed excellent plugging and CO2 conformance improvement performance. Among them, the combined plugging systems containing polymer gels had larger plugging efficiency, and their gas production reduction ratios reached about 90%. Compared with single systems, the combined plugging systems had the advantages of easy injection and in-depth propagation, which can significantly improve CO2 conformance and oil recovery. The research results of this study can provide the experimental understanding and theoretical guidance for the current tricky oilfield problems of CO2 channeling.

Laboratory investigation of the influence of fractures on CO2 flooding

CO2 injection is a promising method for low-permeability reservoirs. CO2 is much easier to inject underground compared with water. The solubility of CO2 in oil decreases the oil density and viscosity, leading to an enhancement of the oil recovery. CO2 flooding could achieve the dual purpose of developing oil effectively and reducing greenhouse gas. Therefore, this technique has both economic and social benefits and is an essential technology for achieving green development. Natural fractures are widely developed in low-permeability reservoirs, and artificial fractures are often used to improve oil development. These fractures have a significant influence on flow patterns during CO2 flooding. In addition, fractures are also one of the key factors of CO2 channeling. Therefore, the influence of fractures on CO2 flooding pressure distribution, fluid composition, and displacement efficiency needs to be studied. In this work, a CO2 flooding experiment was implemented to test the pressure distribution and outlet composition changes during CO2 flooding under different fracture lengths and apertures. The experiment shows that a long and wide fracture could effectively reduce the injection-production pressure difference. However, fractures also had a negative effect on oil development. Fracture length and aperture had a significant effect on the gas phase composition at the outlet, but had little effect on the oil phase composition.

Visualization study of CO2-EOR in carbonate reservoirs using 2.5D heterogeneous micromodels for CCUS

Carbon dioxide enhanced oil recovery (CO2-EOR) is one of the significant technologies to increase oil production and also to reduce greenhouse gas emissions. Carbonate reservoirs distribute widely in the world and show an extremely potential for CO2 geological sequestration and enhanced oil recovery, which is a promising technology for CCUS. However, the complex interfacial properties and strong heterogeneity of carbonate reservoirs lead to serious CO2 channeling, resulting in poor carbon sequestration. Microfluidic experiments in synthetic characterization of strongly heterogeneous reservoirs are a novel method to study multiphase flow in porous media. In this study, a heterogeneous micromodel was prepared using sequential photolithography and calcium carbonate (CaCO3) in-situ growth technique, which was used to construct CaCO3 layer by crystallization on the microchannel surface. The micromodel was represented by a 2.5-dimensional (2.5D) network of pores and fractures at different depths, which was used to simulate the natural structure of carbonate reservoir. The morphological and structural characteristics of the 2.5D micromodel were characterized using scanning electron microscopy, atomic force microscopy, and profilometer. The surface wettability was characterized by determining the contact angle. The results showed that a 1–2 μm layer of CaCO3 grew on the microchannel surface, and the channel surface tended to hydrophobicity. The flow behavior of CO2 in reservoirs and the capacity of foam to control CO2 mobility were simulated using 2.5D micromodels. Among them, CO2 channeling is more obvious and realistic in micromodel. Accordingly, foams with and without nanoparticles (NPs) armor were used to control CO2 mobility. The bubble disproportionation, and liquid drainage of bare surfactant foam induced gas–liquid separation in fractures and pores. Subsequent big and soft bubbles illustrated poor CO2 mobility control performance, and the micro-fractures and pores were not effectively swept and stored with CO2. Extremely stable CO2 foam was obtained with the construction of NPs-armor on foam films, more conducive to the trapping of CO2 in bubbles. The findings of this study can help understand complex CO2 flow behavior in carbonate reservoirs and presents a promising method with NPs-armor stabilized CO2 foams for carbon sequestration and enhanced oil recovery in carbonate reservoirs.

CO2-responsive gel particles and wormlike micelles coupling system for controlling CO2 breakthrough in ultra-low permeability reservoirs

CO2 flooding in ultra-low permeability reservoirs is an effective means to boost oil production, while the complex fractures formed by fracturing in the initial development stage induce severe CO2 channeling. Therefore, a CO2-responsive coupling system, which coupled CO2-responsive gel particles (CRPGP) with CO2-responsive wormlike micelles (CTWM) was prepared to restrain CO2 breakthrough. To testify the EOR capacity during CO2 flooding of the responsive coupling system, the interaction between CRPGP and CTWM, and responsiveness of coupling system was investigated, followed by core flooding and rock slab flooding experiments. Experiment results showed that after the coupling system was exposed with CO2, the particle size of CRPGP increased, spherical micelles of CTWM transformed to wormlike micelles, CRPGP and CTWM were integrated through hydrophobic association among wormlike micelles and hydrophobic chains in CRPGP, and the coupling system’s apparent viscosity increased from 10.4 mPa·s to 2339 mPa·s. Moreover, 0.5 pore volume (PV) CO2-responsive coupling system injection and further CO2 flooding could dramatically boost oil production in fractured cores and rock slabs, which was primarily ascribed to the aggrandizement of sweeping volume resulting from the plugging effect of CRPGP and mobility ratio improvement of the coupling system. Compared with single slug plugging of fractures, multi-stage regulation of fractures could establish a higher-pressure gradient, and more crude oil in the matrix was activated with enhanced oil recovery (EOR) of 22.8%. All the experimental results demonstrated that the CO2-responsive coupling system has great EOR capacity during CO2 flooding, which provided novel insights for ultra-low permeability reservoirs EOR technology that incorporated with CO2 resource utilization and storage.

Dual Benefits of Enhanced Oil Recovery and CO2 Sequestration: The Impact of CO2 Injection Approach on Oil Recovery

Injection of CO2 to enhance oil recovery is widely used due to its multiple advantages such as mobilizing the oil and sequestration of carbon dioxide. Injection of CO2 can enhance oil recovery by reducing oil viscosity and improving overall fluid mobility. However, several problems are associated with CO2 injection such as viscous fingering, gravity override, and CO2 channeling that results in early gas breakthrough, low sweep efficiency, and low ultimate oil recovery. In this study, dual benefits of CO2 injection are presented: enhancing oil recovery and sequestering carbon dioxide. In this work, different scenarios of field scale simulation were conducted to evaluate oil recovery during CO2 injection, and the CMG (Computer Modeling Group) software package was used. Three main scenarios were examined which are CO2 injection into the reservoir, CO2 injection into the aquifer, and CO2 injection into the aquifer followed by waterflooding. Also, three well configurations were utilized—all injectors and producers are drilled vertically, all wells are drilled horizontally, and vertical injectors and horizontal producers are used. Therefore, the oil recovery profiles were examined for nine scenarios over a 20-year period. In all simulated models, CO2 injection was started at the residual oil saturation (Sor) conditions, to represent the cases of depleted oil reservoirs. The results indicated that the highest oil recovery of 73% of the original oil-in-place (OOIP) can be achieved by injecting CO2 into the reservoir, utilizing vertical injectors and producers. While injecting CO2 into aquifers can significantly enhance oil recovery by around 68–70% of the OOIP, using horizontal wells can provide more oil recovery (67.7%) than that using vertical wells (54.8%), in the same conditions. Moreover, around 7,928 tons of carbon dioxide can be sequestered in underground formations, on average. Finally, CO2 injection outperformed the conventional waterflooding, where 68 and 12% of the OOIP were obtained, respectively. Overall, injection of CO2 into the depleted reservoir can provide dual benefits of CO2 sequestration and improved oil recovery. CO2 can be injected into the water zone resulting in a slow release of CO2 which will reduce the fluid viscosity, enhance oil recovery, and reduce the greenhouse effect.

Experimental Study of CO 2 Responsive Enhanced Foam System

The channeling of CO2 seriously affects the development effect of CO2 flooding technology. In response to this problem, the construction of the CO2 responsive enhanced foam system and the evaluation of its channeling performance have been carried out. The foaming agent is optimized by the stirring method, the CO2 responsive enhanced foam system is constructed based on the optimization of foam agent, and the rheological performance test and the enhanced oil recovery experiment are carried out to study the stability mechanism and channeling plugging performance of the responsive enhanced foam system. The developed responsive enhanced foam system formula is 0.1 wt% AOS foaming agent + 4 wt% small molecule amine. The viscosity of this system is close to that of water before exposure to CO2, and the viscosity can increase by more than 18 times corresponding to CO2. The CO2 responsive enhanced foam system has obvious shear thinning characteristics, and its rheological equation conforms to the power law fluid rheological model. The enhanced foam system has stronger viscoelasticity than conventional foams. The foam comprehensive value of the enhanced foam system can reach more than 11 times that of the conventional foam system, which can effectively inhibit the CO2 channeling of heterogeneous low permeability reservoirs and improve the development effect of CO2 flooding in low permeability reservoirs.

Utilizing macroscopic areal permeability heterogeneity to enhance the effect of CO2 flooding in tight sandstone reservoirs in the Ordos Basin

Carbon dioxide-enhanced oil recovery (CO2-EOR) technology has been proven to be effective approach for enhancing oil recovery and has been used in conventional reservoirs since 1970s. Tight sandstone reservoir has poor petrophysical properties, and the complex diagenetic processes that make the reservoir highly heterogeneous resulted in posing significant challenges to CO2-EOR technology. This paper investigated the effects of macroscopic permeability heterogeneity on the efficiency of CO2-EOR by laboratory experiments and field data analysis. The permeability heterogeneity of the reservoir matrix in the study area was evaluated. The results reveal that the matrix permeability range from 0.001 mD to 15 mD, with a mean approximant 1 mD, Beside common thin bedding laminations, the areal permeability varies significantly in a short distance, which is typical for a tight sandstone reservoir. The Triassic Yanchang Formation (200–1400 m thick) is a major petroliferous stratigraphic section in the Ordos Basin. It consists of complete lacustrine sedimentary cycles with clastic sediments. From bottom to top, it can be divided as Chang 10 to Chang 1 members. The low porosity, low permeability, low oil saturation, anomalously low reservoir pressure, and high reservoir heterogeneity makes application of enhanced oil recovery techniques in this formation challenging. The submerged distributary channel core sample with various permeability from the Chang 4+5 sandstone reservoir in Shanbei area of the Ordos Basin were utilized in the laboratory CO2-EOR experiments to study the impact of heterogeneity on CO2 flooding. The results show that the mode of high–low permeability (i.e., the injection well located in the higher permeability area and the production well located in the low permeability area) can ensure the gas injection capacity, maintain a high pressure level throughout the production period, and increase the oil displacement efficiency, which breaks the conventional understanding. Conventional understanding holds that high permeable pore path or fractures developed on the injection area are prone to CO2 channeling, and high permeable pore path or fractures developed on the production area are conducive to oil flow and output increase. Therefore, oil well fracturing is often carried out in the field, and fracturing of injection well is not recommended. However, our experimental research and field application found that the traditional guiding ideology is not conducive to improve oil recovery, but the high–low permeability model which is put forward in this paper can not only enhance CO2 injectivity, but also is beneficial to high formation pressure level and full interaction between gas and crude oil. It also can be confirmed from oilfield that the application of high-low permeability model with high-heterogeneity reservoir could effectively improve the effect of CO2 flooding in tight sandstone reservoirs.

Microstructure and Formula Optimization of Co2 Flooding Composite Gel in Supercritical Carbon Dioxide

Injection of CO2 into low permeability reservoirs tend to both enhance the oil recovery effectively and reduce the CO2 emissions. However, the reservoir heterogeneity, reservoir cracks and viscous fingering lead to CO2 channeling occuring during the process of CO2 flooding. Four parameters (CO2 pressure, simulation temperature, reaction time, and concentrations of reactants) were optimized through L16(44) orthogonal experiment, and the most appropriate conditions for inorganic gel were also acquired simultaneously as follows: reaction pressure 9.0 MPa, reaction temperature 32.01, reaction time 14.0 h, and sodium silicate mass concentration 4.0%. The compound gel was synthesized by the method of blending sodium silicate solution with an acrylamide system in supercritical CO2. The microstructure of the compound gel was researched through environmental scanning electron microscopy (ESEM), and the results showed that, in supercritical CO2, the inorganic gel particle equaly dispersed in the organic gel network inside the structure, thus the support framework of the organic polymer chain was formed and the strength of the compound gel was finally enhanced.

Integrated CO2-Foam Pilot in a Heterogeneous Carbonate Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190204, “An Integrated CO2 Foam EOR Pilot Program With Combined CCUS in an Onshore Texas Heterogeneous Carbonate Field,” by Z.P. Alcorn, SPE, and S.B. Frederiksen, University of Bergen; M. Sharma, University of Stavanger; A.U. Rognmo, SPE, University of Bergen; T.L. Føyen, SPE, University of Bergen and SINTEF; and M.A. Fernø, SPE, and A. Graue, SPE, University of Bergen, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed. A carbon-dioxide (CO2) -foam enhanced-oil-recovery (EOR) pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Previous field tests with CO2 foam report varying results because of injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. A more-integrated multiscale methodology was required for project design to further understand the connection between laboratory- and field-scale displacement mechanisms. East Seminole Field The East Seminole Field in the Permian Basin of West Texas was discovered in the early 1940s with an estimated 38 million barrels of original oil in place (OOIP). The field was developed throughout the 1960s, producing 12% OOIP through pressure depletion. Water floods began in the early 1970s and continued into the 1980s with strategic infill drilling, reducing the well spacing from 40 to 20 acres. Tertiary CO2 floods began in inverted 40-acre, five-spot patterns in 2013 in the eastern portion of the field. Miscible CO2 injection initially increased oil production and reservoir pressure. However, rapid CO2 breakthrough, high producing gas/oil ratio (GOR), and CO2 channeling was soon observed in peripheral production wells. CO2 performance suffers because of reservoir heterogeneity and unfavorable mobility ratios between injected CO2 and reservoir fluids, resulting in poor areal sweep efficiency, high producing GOR, and CO2 channeling. As seen in other areas of the Permian Basin, tilted fluid contacts, presumably resulting from basin activity or a breach of seal, have created a deeper residual oil zone (ROZ). These zones are thought to have been naturally waterflooded through hydrodynamic dis-placement and have been shown to contain considerable immobile oil (20 to 40% OOIP) that can be mobilized by CO2 flood. Thus, the residual oil saturation in the ROZ is similar to waterflooded zones and establishes it as an economically attractive target for tertiary CO2 recovery efforts.

CO2-cyclic solvent injection (CO2-CSI) and gas/waterflooding in the thin post-CHOPS reservoirs

In this paper, a new combined CO2-cyclic solvent injection (CO2-CSI) and gasflooding (GF) process is proposed as an effective enhanced oil recovery (EOR) process in the post cold heavy oil production with sand (CHOPS) reservoirs. The synergy of the CO2-CSI and GF is explored and compared with that of the CO2-CSI and waterflooding (WF). A total of ten sandpacked laboratory tests were conducted to study and compare the production performances of the WF, CO2-CSI, combined CO2-CSI and GF/WF after the primary production. In the combined CO2-CSI and GF/WF processes, CO2/water is injected post, at the same time with, and prior to the CO2-CSI in the CSI + GF/WF, simultaneous (CSI + GF/WF), and GF/WF + CSI, respectively. Also the effect of CO2 injection rate is studied by injecting CO2 at three different flow rates in the CSI + GF. It is found that CO2-CSI + GF or CO2-CSI + WF performs better than the CO2-CSI or WF alone due to the extended foamy-oil flow. The combined CO2-CSI and WF outperforms the combined CO2-CSI and GF in terms of the heavy oil recovery factor (RF), heavy oil production rate, and cumulative gas-oil ratio (GOR). CO2 channeling is hindered by the subsequently injected water. In the combined CO2-CSI and GF, however, strong free-gas flow adversely affects the foamy-oil production in the later cycles of the CSI and in the subsequent GF. The best fluid injection timing in terms of the heavy oil RF is to inject CO2/water immediately after each cycle of the CSI production. A moderate CO2 injection rate gives the highest heavy oil RF of the CSI + GF. In conclusion, the combined CO2-CSI and GF/WF process is capable of recovering the remaining oil in the post-CHOPS reservoir.

Self-assembled microspheres feasibility study for conformance control in high temperature and high salinity reservoirs

This paper investigated the micro-structure and swelling and heat tolerance of DCA (divinylbenzene-co-acrylamide) microsphere and its self-assembly ability at high temperature, high salinity, oil-water system. Heterogeneous cores have been used in displacement experiment to evaluate the conformance control effectiveness of DCA microsphere. The result suggested that DCA microsphere has a hollow structure and many oligomer chain segment on the microsphere surface extending into the aqueous solution. The particle size of microsphere has strong stability. DCA microsphere can tolerate temperature up to 260 °C and still self-assemble in an oil-water system at high temperature and high salinity condition; DCA microsphere can self-assemble in the core into microspherical clusters used for conformance control of injected water, resulted in subsequent water flooding pressure increase of tenfolds and oil recovery enhancement of 9.53%; DCA microsphere exhibit effective conformance control of CO2 and control well CO2 channeling. CO2 displacement with conformance control using DCA microspheres has 15.8% higher oil recovery than direct CO2 displacement. DCA self-assembled microsphere can improve development of high–temperature, high-salinity heterogeneous reservoir and provide an aid for enhanced oil recovery.

Enhanced heavy oil recovery via surfactant-assisted CO2 huff-n-puff processes

CO2 huff-n-puff suffers from sharp decrease of recovery factor (RF) after the second cycle. The major objective of this paper was to study the key parameter and mechanism of surfactant-assisted CO2 huff-n-puff process (SACHP) as an enhanced oil recovery (EOR) method after the second cycle. In this study, two kinds of surfactants were used as viscosity reducer and foaming agent. The effects of the key parameters on RF, such as gas-liquid ratio, slug size, order of injections and soaking time were investigated through huff-n-puff experiments. The mechanisms of SACHP were studied by analyzing the produced fluid and oil sand after the SACHP experiments. The huff-n-puff experiments indicated that the combination of foaming agent and viscosity reducer was optimal for SACHP, and can improve ultimate RF by 13% compared to CO2 huff-n-puff. The recommended injection parameters for SACHP were 0.2 PV and 0.1 PV for CO2 and the surfactant solution, respectively. A larger slug size and an excessive soaking time have little effect on the ultimate RF. The SACHP caused the asphaltene content reduction in the produced oil and the asphaltene precipitation in the reservoir. The foaming agent can effectively control CO2 channeling and increase the swept range by 16.7%. The viscosity reducer can improve the displacement efficiency and the mobility of oil by forming emulsion. The synergistic effect of the surfactants and CO2 improved the ultimate RF. Therefore, the results of this study suggested that SACHP is a viable technique for EOR.

Behavior of CO2/water flow in porous media for CO2 geological storage

A clear understanding of two-phase fluid flow properties in porous media is of importance to CO2 geological storage. The study visually measured the immiscible and miscible displacement of water by CO2 using MRI (magnetic resonance imaging), and investigated the factor influencing the displacement process in porous media which were filled with quartz glass beads. For immiscible displacement at slow flow rates, the MR signal intensity of images increased because of CO2 dissolution; before the dissolution phenomenon became inconspicuous at flow rate of 0.8mLmin−1. For miscible displacement, the MR signal intensity decreased gradually independent of flow rates, because supercritical CO2 and water became miscible in the beginning of CO2 injection. CO2 channeling or fingering phenomena were more obviously observed with lower permeable porous media. Capillary force decreases with increasing particle size, which would increase permeability and allow CO2 and water to invade into small pore spaces more easily. The study also showed CO2 flow patterns were dominated by dimensionless capillary number, changing from capillary finger to stable flow. The relative permeability curve was calculated using Brooks-Corey model, while the results showed the relative permeability of CO2 slightly decreases with the increase of capillary number.