Dual Benefit of CO2 Sequestration: Storage and Enhanced Oil Recovery

Introduction

CO2 is usually injected into formations at high pressure and high temperature in which the CO2 is in its supercritical condition. Storing CO2 in a supercritical condition will allow the storage to store more CO2 because of the less volume occupied by CO2 at this state [1]. While CO2 is injected into the formation, the major mechanisms that ensue CO2 sequestration are: (i) Physical/Structural trapping, due to the low permeability of the cap or sealing rock that will prevent CO2 from migration or leak to the surface or other resources in the underground [1, 2], (ii) Solubility trapping, in which the injected CO2 will dissolve in water to its solubility limit that based on the water composition, (iii) Mineral trapping – the dissolved CO2 in water will produce carbonic acid that will react with the rock and precipitate calcite mineral, and (iv) Residual or Capillary trapping which occurs after CO2 injection stops and water begins to imbibe into the aquifer displacing the CO2 already in the aquifer. Not all the CO2 is displaced but some are left behind as residual CO2 (residual trapping). Zhang and Agarwal carried out numerical simulation and optimization for CO2 storage in saline aquifers [3]. They used Genetic Algorithms (GA) to optimize parameter such as; CO2 injection rate, CO2 injection pressure, injection depth, well schemes (vertical/horizontal). Their optimizer can be used to optimize the sequestration capacity of CO2 in saline aquifers. They developed a code that can be used to study the leakage of CO2 during storage in abandoned wells. Also it can be used to the enhancement in methane gas recovery from depleted gas reservoirs. The developed optimizer can be used to investigate the CO2 storage in heterogeneous geological formations. Zhang and Agarwal optimizer code matched the simulation results obtained by other codes and they utilized their code to optimize the process of CO2 sequestration in different scenarios and different well patterns [3]. Zhang and Agarwal carried out numerical simulation to study the CO2 sequestration efficiency, safety, and its economic feasibility before sequestration in field scale saline aquifers [4]. They carried out the simulation study on three large identified saline aquifers and their simulation results were in agreement with that obtained from seismic data in CO2 monitoring during sequestration. Seo and Mamora performed experimental and simulation studies to assess the possibility of sequestering supercritical CO2 in depleted gas reservoirs [5]. They obtained the relative permeability curves by simulating the experimental results, and they use the relative permeability in the simulation of field cases. They constructed 3D simulation model to investigate he injection of supercritical CO2 in depleted gas reservoirs. The simulation results showed that the amount of CO2 stored in depleted gas reservoirs is related to the depletion and the reservoir capacity. The higher the depletion and the larger the reservoir the higher was the sequestered CO2. The simulation results showed that 4.8 million tons can be stored and 56 years in depleted gas reservoirs compared to 1.2 million tons in 29 years. They showed that the injection rate of the supercritical CO2 did not affect the storing capacity of the reservoirs and also in addition to CO2 storage, 1.3 BSCF natural gas was produced during the 29 years sequestration period and 4.9 BSCF was produced in the case of 56 years sequestration. This actually shows the mutual benefits of the sequestration of CO2 in depleted gas reservoirs, more gas will be produced due to the high reservoir pressure obtained by CO2 injection and in the same time CO2 is stored in these reservoirs. Nogueria and Mamora investigated the CO2 sequestration in depleted gas reservoirs in addition to impurities from the flue gas from the surface separators such as nitrogen [6]. One of the proposed objectives of CO2 sequestration is to maintain the pressure of gas reservoirs. In addition to that CO2 can be stored in these reservoirs because they have large storage capacity compared to oil reservoirs having the same pore volume. They proposed the injection of CO2 with a mixture of nitrogen gas and other flue gas impurities to enhance the combustion of the produced gas. They found out that injecting CO2 with impurities did not affect the CO2 storage volume in depleted gas reservoirs. They concluded that to maximize the CO2 sequestration volume, impurities should be injected with CO2, and also this will reduce the compression requirements and improve the sweep efficiency and in turn enhance the gas recovery. Adebayo proposed a technique to monitor the CO2 sequestration in the down hole using combined resistivity and temperature logging [7]. The proposed technique can be used to monitor the dissolution/precipitation cause by CO2/Brine/Rock/Interactions (CBRI) with the carbonate formations in saline aquifers. Also, the proposed technique can be used to assess and evaluate the effectiveness of scale inhibitors injected to prevent the scale caused by CO2 interaction with the carbonate reservoirs (calcium carbonate or calcium sulfate scale). They have done resistivity and temperature logging on carbonates for three months continuously during the CO2 injection and the dissolution/precipitation observed clearly from the recorded logs. CBRI produced carbonic acid which reacted with the carbonate at low pH, once the pH increased this will cause carbonate precipitation. The proposed technique was able to capture the dissolution and the precipitation of carbonates inside the core during CO2 injection. Olabode and Radonjic studied the interaction between the stored CO2 and the cap rock (shale) in the underground storage [8]. They carried out experimental work for longer time periods at high temperatures. They found out that the CO2 affected the shale cap rock integrity and the surface area of the rock exposed to the reaction increased and this also will impact the pore geometry and pores connectivity due to the interaction. They concluded that the contact time has strong impact on the shale integrity due to the reactivity of the carbonic acid generated from the reaction of CO2 and brines. Mohamed investigated the effect of CO2 sequestration on the permeability of vuggy carbonate aquifers [9]. They carried out several core flooding experiments with continuous CO2 injection to study the effect of CO2 interaction won the rock permeability. They found out that the CO2 injection may increase the rock permeability due to dissolution or damage the rock permeability due to the precipitation of calcium carbonate and the reaction depends on reservoir conditions of permeability, pressure, temperature and porosity. The experimental results showed that two sources of damage were identified; the first one was due to calcium carbonate precipitation and the second one due to fines migration of the clay minerals that exist in the core. Shtepani studies CO2 sequestration in gas condensate reservoirs [10]. He integrated the laboratory results with modeling study that was done before compositional simulation and field pilot test for CO2 injection. He showed that the phase behavior of CO2 and gas condensate will affect the storage volume of CO2 in depleted gas condensate reservoirs. The PVT study should be carried out to study the phase behavior because this will be important in building the equation of state model (EOS). He shows that the coreflood experiments should be performed in addition to the PVT experiment to determine the CO2 breakthrough and the results from the flooding experiment can be used to study the sensitivity using commercial simulators to study the feasibility of CO2 sequestration in depleted gas condensate reservoirs. Barrufet investigated the CO2 storage capacity in different geologic formations, for different levels of CO2 purity and different injection schemes [11]. They studied the storage of CO2 in depleted gas condensate reservoirs and into saline aquifer using compositional reservoir simulation model. They found out that the presence of impurities such as nitrogen and methane in CO2 decreased the storage capacity of the reservoir. They concluded that an optimization study should be carried out based on the economic optimum between the cost of the impurities separation such as nitrogen and methane from the CO2, compression, and the CO2 injection rate. The simulation results showed that, the mass of CO2 sequestrated per pore volume in the aquifer is 13 times smaller than that of the depleted gas condensate reservoir model. The saline aquifer of the same volume as a depleted gas reservoir has lower storage capacity because of its low overall compressibility. However, aquifers tend to have a far larger extent, which often compensates somewhat for this lower ratio and therefore provides storage for significant volumes of CO2. Pilisi and Ceyhan carried out a feasibility study of CO2 sequestration in deep water formations in the Gulf of Mexico [12]. They performed complete description of the whole process of the CO2 capture and sequestration including the technical limitations from the surface to the underground storage. In deep offshore reservoirs the liquid CO2 has higher density and that may cause hydrates that will fill the pore space and act as trapping mechanism. They concluded that, deep water sub-seabed sequestration provides an enormous storage capacity to counteract increasing world consumption of fossil fuels. Pilisi and Ceyhan concluded that, large scale simulations are needed to investigate the impact of geochemical reactions on the deep water sea bed region and also the impact of the liquid CO2 injection on the water chemistry in the deep water [12]. Daneshfar carried out a feasibility study for CO2 sequestration in the Arbuckle formation in Oklahoma [13]. They performed a general review for CO2 storage in saline aquifers using the existing wells, they found out that the criteria that control the sequestration process are; geology of the aquifer, lithology of the storage reservoir, cost of the operations, CO2 sequestration impact on the reservoir rock properties, and depth of the completed intervals. The residual oil in the Arbuckle formation will affect the reaction chemistry that will impact CO2 sequestration. The numerical simulation results of CO2 sequestration in disposal well in the Arbuckle formation showed that the dissolution/precipitation of the minerals took place in the near-wellbore. Residual oil retarded the dissolution of the mineral and delayed the reaction in the near-wellbore area.

CO2 flooding is used to enhance the oil recovery from carbonate and sandstone reservoirs. CO2-EOR has many problems such as viscous fingering and gravity override. Hoffman and Shoaib developed a numerical model for CO2 enhanced oil recovery [14]. Their model showed that the CO2 injection in low permeability shale recovered more oil. They showed that CO2 injection will enhance the sweep efficiency and support the reservoir pressure. CO2 can be injected into the reservoir either by using vertical or horizontal injectors but the horizontal injector capacity was higher compared to the vertical one. The objective of this paper is to investigate the dual benefit of CO2 sequestration in saline aquifers underlying oil reservoirs using numerical simulation software. The specific objectives are as follows: 1) investigate the CO2 sequestration in saline aquifers, 2) investigate the effect of the slow release of the sequestered CO2 to the oil reservoir on the oil recovery due to the viscosity reduction, and 3) studying the effect of different well schemes on the oil recovery by the slow released CO2 from the storage aquifer.

Simulation Model

Simulation data initialization was done using drainage area with length of 8000 ft and width of 6000 ft. The thickness of oil bearing zone was 145 ft and for aquifer 70 ft was used. Grid blocks in X = 50 with a length of each grid block equals to 160 ft. Grid Blocks in Y = 40 with a length of each grid block equals to 150 ft. This thickness was divided in to five layers with Average porosities of 0.18, 0.17, 0.1, 0.18 and 0.15 respectively for first and second layer of reservoir, low permeability layer and two layers for the aquifer. Average permeability of 100 md, 80 md, 0.01 md 75 md, and 90 md respectively were set for the five layers. The middle layer permeability was set to be low to slow down the release CO2 during the sequestration process. The length of the horizontal well was 2500 ft (for both injector and producer). The first three layers (from the top) are oil zones while the last two layers are aquifer. The grid block permeability in x, y, and z directions is perm x = perm y = 10 * perm z. The reservoir pressure was set to be 4000 psi, the minimum miscibility pressure (MMP) = 1600 psi, Pb (bubble point pressure) = 1400 psi, gas/oil contact (GOC) = 9000 ft. Figure 1 shows the initial model as described. The following well properties were considered; maximum injection pressure = 5500 psi, for injectors, operating bottom hole pressure (BHP) = 1800 psi for producers, and gas/oil ratio (GOR) = 8000 scf/stb, well radius= 0.625 ft, and Skin damage = 1.5.

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Conclusion

In this study, the mutual benefits of CO2 sequestration in aquifers was investigated, where the stored CO2 will migrate to the oil zone and swell the oil and enhance the oil recovery. The following are the conclusions that can be drawn from this study: 1. Simulation results showed that the sequestered CO2 in the aquifer migrated to the oil zone and reduced the oil viscosity more than 6 folds. The reduction in the oil viscosity will enhance the oil recovery by the natural reservoir energy.

2. CO2 sequestration in aquifers increased the oil recovery from the overlying oil zone by two mechanisms; the first one is the increase in oil mobility and the second one due to the increase the oil zone pressure due to the CO2 sequestration in the aquifer.

3. Different well schemes affected the oil recovery from the oil zone. The well scheme that provided the maximum storage capacity was horizontal well located at the bottom of the aquifer zone.