Simultaneous Injection Of CO2 Research Articles

Developing a numerical model for microbial methanation in a depleted hydrocarbon reservoir

Biological methanation is a promising option for CO2 utilization and energy storage. While the underground condition is not appropriate for a methanation reaction, microorganisms act as a catalyst and make the reaction possible. This study investigates the performance of biological methanation in depleted gas reservoirs using numerical simulation. To do this, a one-dimensional synthetic homogeneous depleted gas reservoir is modeled with the two-phase flow comprising components H2, CO2, CH4, and H2O. Then, the simultaneous injection of CO2 and H2 into the reservoir is numerically simulated to evaluate the methane production rate in MATLAB Reservoir Simulation Toolbox (MRST) open-source software. Long-term results show propagating composition waves and pressure profiles. Sensitivity analysis reveals that methane production is positively correlated with the initial reservoir pressure and the number of methanogenic microorganisms, but negatively correlated with the temperature and the bacterial decay rate. The bacterial growth rate has an insignificant effect on methane production in this model. The bacterial population is the most critical parameter, as 1e7 methanogenic microorganisms per cubic meter of aqueous phase can produce 96% pure methane after 12 years. Overall, the work demonstrates harnessing in-situ bio-reactions to utilize CO2 and recover depleted gas reservoirs.

Economic analysis of CCUS: Accelerated development for CO2 EOR and storage in residual oil zones under the context of 45Q tax credit

Residual oil zones (ROZ) undergoing CO2 Enhanced Oil Recovery (CO2-EOR) may benefit from specific strategies to maximize their value. We evaluated several strategies for producing from a Permian Basin, West Texas, USA field’s ROZ. This ROZ lies below the main pay zone (MPZ) of the field. Such brownfield ROZs occur in the Permian Basin and elsewhere. Since brownfield ROZs are hydraulically connected to the MPZs, development sequences and schemes influence oil production, CO2 storage, and net present value (NPV). We conducted economic assessments of various CO2 injection/production schemes in the stacked ROZ-MPZ reservoir based on flow simulations of a high-resolution geocellular model built from wireline logs and core data and calibrated through production history matching. Flow simulations of water alternating gas (WAG) injection, such as switching injection from the MPZ to the ROZ and commingled production, were studied. Simulation results showed that simultaneous CO2 injection into the MPZ and ROZ lead to the largest oil production and, generally, the largest NPV. If instead, CO2 was simultaneously injected into the MPZ and ROZ, then into the ROZ alone, this maximized CO2 storage. CO2 storage can be used as a tax credit under the Internal Revenue Code, Section 45Q. Storage performance depends on the development approach and WAG ratio. Developing the ROZ increased storage compared to only producing from the MPZ. The WAG ratio to maximize oil production did not always yield the largest NPV. These findings are potentially applied to other Brownfield ROZs, which are common below San Andres reservoirs in the Permian Basin and other basins. ROZ development can increase oilfields’ NPV and carbon storage potential. Our study can serve as an analog for similar reservoirs. This work provides valuable insights into the further optimization of brownfield ROZ development and information for operators to plan to develop stacked ROZ-MPZ reservoirs.

Molecular Investigation on the Displacement Characteristics of CH4 by CO2, N2 and Their Mixture in a Composite Shale Model

The rapid growth in energy consumption and environmental pollution have greatly stimulated the exploration and utilization of shale gas. The injection of gases such as CO2, N2, and their mixture is currently regarded as one of the most effective ways to enhance gas recovery from shale reservoirs. In this study, molecular simulations were conducted on a kaolinite–kerogen IID composite shale matrix to explore the displacement characteristics of CH4 using different injection gases, including CO2, N2, and their mixture. The results show that when the injection pressure was lower than 10 MPa, increasing the injection pressure improved the displacement capacity of CH4 by CO2. Correspondingly, an increase of formation temperature also increased the displacement efficiency of CH4, but an increase of pore size slightly increased this displacement efficiency. Moreover, it was found that when the proportion of CO2 and N2 was 1:1, the displacement efficiency of CH4 was the highest, which proved that the simultaneous injection of CO2 and N2 had a synergistic effect on shale gas production. The results of this paper will provide guidance and reference for the displacement exploitation of shale gas by injection gases.

Experimental investigation of foam assisted water alternate gas injection in relation to enhanced oil recovery applications

In this work, the efficiency of CO2-foam injection for enhanced oil recovery (EOR) is investigated. Six floods were performed on sand pack columns. Pure water injection, WAG injection and simultaneous injection of CO2 and surfactant solution with various concentrations were conducted. Notable difference was observed between oil production in secondary surfactant assisted WAG and other injection scenarios. The experimental work in this research shows that increase in concentration of surfactant in the injection process results in mobilization of more oil that may not have been achievable by using water flooding and WAG flooding methods individually.

Influence of CO2–Brine Co-injection on CO2 Storage Capacity Enhancement in Deep Saline Aquifers: An Experimental Study on Hawkesbury Sandstone Formation

This study was conducted to identify a potential CO2-storage-capacity-enhancement technique: enhancement of CO2 storage through co-injection or the simultaneous injection of CO2 and brine into saline aquifers. A series of triaxial permeability tests on brine-saturated sandstone samples for a range of injection pressures (4–10 MPa) under different confining pressures (20–35 MPa) was performed at 35 °C constant temperature. To clearly identify the sequestration-enhancement capability of the proposed novel method, conventional CO2 injection (injection of only CO2 into brine-saturated rock) was also carried out under the same test conditions. Both tests were subjected to comprehensive chemical analyses to evaluate the alteration of CO2 solubility in brine caused by the proposed method. CO2 flow behavior under conventional CO2 injection may convert from two- to single-phase flow over time around the injection point, as a result of forced brine migration. This may create a suddenly increased advective flux some...

Numerical modeling of CO2 injection scenarios in petroleum reservoirs: Application to CO2 sequestration and EOR

CO2 injection is a most promising method for enhancing oil recovery from petroleum reservoirs especially from depleted one. CO2 injection can be employed as secondary and tertiary enhanced oil recovery (EOR) methods. The most prominent advantage of CO2 injection is reducing greenhouse gases in the atmosphere and consequently reducing environmental problems. Different approaches have been employed to study the performance of CO2 in increasing oil production including miscible/immiscible injection, carbonated water injection (CWI) and CO2 injection into aquifer. In these methods different parameters can effect such as minimum miscible pressure (MMP), injection rate and so forth. Therefore, the main goal of this paper is to study of different CO2 injection methods and the effect of operational factors on the performance of each method by a numerical simulation model. In this study, a synthetic reservoir is considered for numerical simulation of CO2 injection process. To assess this goal, three different CO2 injection strategies including CO2 injection into the bottom aquifer, CO2 injection into oil column (pay-zone) and simultaneous CO2 injection into aquifer and pay-zone are defined. Based on the results obtained from three aforementioned injection scenarios, simultaneous CO2 injection into aquifer and pay-zone leads to higher oil recovery factor in comparison with other scenarios. Critical injection rate for each scenario was determined and employed in the case of simultaneous CO2 injection into aquifer and pay-zone. Moreover, at the same CO2 injection rate, injection into aquifer leads to produce more oil compared to CO2 injection into the pay-zone.

A geological storage option for CO2 in the Bohaiwan Basin, East China?

Geological assessment of the Bohaiwan Basin in eastern China for the COACH (Cooperation Action within CCS China-EU) project indicated that storing carbon dioxide (CO2) in this region will be technically challenging and require a flexible storage solution. It is suggested that a pilot scheme within the Dagang oil field complex could prove the concept of Carbon Capture and Storage (CCS) and CO2-Enhanced Oil Recovery (CO2-EOR) in the challenging conditions of oil fields in this region of China. This could be followed by simultaneous injection of CO2 into a nearby larger oil field and adjacent aquifers that would offer a potential storage option by combining the larger storage space anticipated for aquifers with the possible future financial incentives of CO2-EOR.

Carbon Dioxide Flooding As An Enhanced Oil Recovery Process

Synopsis In earlier work(1–5), the fundamental and the field applications of carbon dioxide flooding were described. The presentation(5) at the Western Regional Meeting of SPE in 1991 focussed on a comparison of CO2 flooding for light and heavy oils, with examples from the field showing that CO2 flooding has recovered significant amounts of incremental oil under miscible as well as immiscible conditions. Carbon dioxide flooding for the enhanced recovery of heavy oils is important for Canada since it provides an alternative to thermal recovery. In this article the author will attempt to illustrate the state-of-the-art on CO2 flooding in general and how CO2 flooding relates to the recovery of heavy oils in particular. Introduction There is a great deal of industry interest in CO2 flooding as evidenced by the large number of field applications which have been initiated in the past decade(6). Additional field tests are certain to be carried out when CO2 supplies of acceptable purity and volumes are found. All major petroleum research centres, institutes, universities and government research institutions have projects relating to CO2 flooding. With two exceptions, the process normally involves the injection of CO2 initially, followed by a period in which CO2 is alternated, as small slugs, with another fluid, and terminates, with the injection of the principal driving or chase fluid which would be either water or gas. The two exceptions are the carbon dioxide stimulation process which is carried out in producing wells and is a stimulation technique very similar to a ""huff-and-puff' scheme. The other exception occurs in reservoirs which have such low pressure that they must initially be pressurized prior to the injection of CO2. Normally, such pressurization is by injection of water. Carbon dioxide flooding may be carried out either as a miscible or as an immiscible oil recovery process and has been studied in the laboratory or practiced in the field in the following modes:carbon dioxide stimulation;continuous CO2 injection;simultaneous injection of CO2 and water;alternating slugs of CO2 and water;injection of CO2 with H2S;injection of CH4 and CO2;CO2 and N2 mixtures;the CO2, SO2, combination;CO2 and LPG mixtures; andLPG followed by CO2. The most common way that CO2 flooding is being applied in approximately 60 depleted light oil reservoirs in the United States has been to initially repressurize the reservoir to the minimum miscibility pressure by injecting water. In a few cases, repressurization was accomplished by injecting CO2 from the start. Of course, this can be costly. For a reservoir depth of, say. 2500 m, one can expect the minimum miscibility pressure to be about 16 MPa and the reservoir temperature to be 90 °C. At these conditions, 350 m3 of CO2 would approximately equal 1 m3 in reservoir volume. Depending on the size of the reservoir and the cumulative past production the CO2 requirements can prove to be prohibitive.

Effects of C02 Addition to Steam on Recovery of West Sak Crude Oil

Summary A high-pressure ID laboratory displacement study evaluated the effects of adding CO2 to steam on the recovery of West Sak crude oil. Results of the laboratory experiments indicate that the simultaneous injection of CO2 and steam increases recovery, reduces injection temperatures, and reduces the heat input required.

Prediction of CO2 Flood Performance: Interaction of Phase Behavior With Microscopic Pore Structure Heterogeneity

Summary This paper describes simulations of the effects of microscopic heterogeneity present in rock pore structures or resulting from high water saturations on the performance of one-dimensional (1D) CO2 floods. In the simulations, microscopic heterogeneity was represented by dividing the nonaqueous portion of the pore space into flowing, dendritic, and trapped fractions. A 1D simulator, previously shown to model quantitatively the effects of phase behavior in slim-tube displacements, was modified to include effects of the isolated or trapped fraction unavailable for mixing with injected fluids and the dendritic fraction, which exchanges material with the flowing fraction by mass transfer. Model formulation, numerical solution, and validation tests are described. Results of simulations with no water present indicate that performance of a 1D CO2 flood is sensitive to deviations from complete local mixing. Calculated oil recovery decreases as the flowing fraction, Peclet number, and Damkohler number decrease. Comparisons of calculated and measured residual oil saturations (ROS's) in CO2 corefloods support this observation. Simulations of secondary and tertiary displacements by continuous CO2 injection and alternate and simultaneous injection of CO2 and water are compared. Performance of secondary displacements is not strongly affected by incomplete local mixing. In tertiary displacements, however, total oil recovery and the rate of recovery are reduced if effects of trapped and dendritic saturations are included.

Numerical Evaluation of the Effect of Simultaneous Steam and Carbon Dioxide Injection on the Recovery of Heavy Oil

Summary The immiscible displacement mechanism of CO2 in a simultaneous injection of CO2 and steam in a heavy-oil reservoir is evaluated with a numerical simulation model. In a steam stimulation process, the viscosity reduction effect of CO2 on heavy oil is the major contributor to increased recovery in a high-compressibility reservoir. In a normal-compressibility reservoir, the major benefit is derived from the solution gas effect of the injected CO2. Ignoring the solubility of CO2 in water can introduce an optimistic incremental recovery over steam-only injection. In a steamdrive process, the addition of CO2 to be injected steam improves the final recovery by only a small amount. However, the oil production rate before steam breakthrough appears to be production rate before steam breakthrough appears to be accelerated by the solution of CO2 in the heavy oil. The swelling effect of CO2 does not appear to play an important role in the incremental recovery, because the swelling effect of CO2 at high temperature is small when compared with the thermal expansion of the crude oil. Introduction The growing interest in the application of CO2 injection in EOR schemes has been concentrated so far on the miscible aspect of CO2. The CO2 miscible flood process generally is limited to the recovery of light-gravity process generally is limited to the recovery of light-gravity oil. Application of CO2 miscible flood to heavy-gravity oil has been hampered by the complex phase behavior, including the possible deposition of asphaltene, a solid phase, which could be detrimental to the permeability of phase, which could be detrimental to the permeability of the reservoir. In the immiscible aspect of CO2 injection, the viscosity reduction effect of CO2, generally unimportant in light-oil reservoirs, could play a significant role in the recovery of heavy oil. For all heavy-oil reservoirs, the major mechanism of enhanced recovery methods, which include steam injection and in-situ combustion process, is the reduction of reservoir oil viscosity to allow oil mobilization and to improve the mobility ratio between the reservoir oil and the displacement fluid. A study of the significant viscosity reduction effect of CO2 on high-viscosity crude oil was published as early as 1963. Welker and Dunlop showed that the viscosity reduction could be up to 98 % for a 4,800-cp (4.8-Pas) heavy crude oil at 80 deg. F (27 deg. C) and 800-psi (5515-kPa) carbonation pressure. A proposed field application of CO2 injection was reported to take advantage of this significant viscosity reduction aspect. It was also reported that supercritical CO2 was used to achieve solvent-reduced oil viscosity in some U.S. reservoirs in 1977. A study on the effect of normal reservoir parameters on a CO2 huff ‘n’ puff process was reported parameters on a CO2 huff ‘n’ puff process was reported in 1979. However, no field data have been published. In 1981, the first CO2 cyclic stimulation was conducted in Canada with interesting results. The experiment of solvent addition to steam process has been carried out in the field since probably as early as steam was applied successfully in oil recovery. No systematic evaluation was presented or published. Laboratory physical models were used to evaluate the benefit of solvent addition to steam and the results were reported by Redford. JPT P. 1591