Carbon Dioxide Storage in Natural Gas Reservoir

This project is one of the first successful field tests and commercial implementation of enhanced gas recovery (EGR) for a depleted gas reservoir by injecting a natural high-carbon dioxide (CO2) gas stream in the Gulf of Thailand. It has demonstrated that injection of CO2-containing gas stream into a natural gas reservoir is a promising win-win technology for ultimate recovery improvement of natural gas in depleted reservoirs and CO2 sequestration. To evaluate the effectiveness of EGR, the test was conducted in depletion-drive sandstone gas reservoirs. EGR was initiated when the primary gas recovery was mostly realized. Injection of natural gas with around 60% CO2 from deeper formations in the same area yielded an incremental gas recovery of 8% to 10% of original gas in-place in one successful candidate, demonstrating the recovery enhancement potential in such reservoirs. Increasing ultimate recovery of a depleted gas reservoir and enhancing hydrocarbon recovery helps supply extra energy to the Kingdom of Thailand and power more electricity generation. The additional production has generated multi-million USD in revenue not only for the country mainly in form of royalty and petroleum income tax, but also for the company. Another obvious benefit of this project is a positive environmental impact. Its outcome helps reduce the emissions of greenhouse gas in the atmosphere by sequestering large amounts of CO2 in a depleted gas reservoir. This underground storage option is considered economical and have a low environmental impact. Therefore, the project delivers positive environmental change.Besides the fact that we are implementing this pilot, we believe this project can also be adopted by operators in other fields on a very broad sense and scale. With favorable size of opportunities, it can be economic to inject high CO2 gas from surface compressors. This will enable the operator more flexibility in term of source of high CO2 gas and injection rate. Along with all those mentioned above, the project contributes to sustainability and innovation for the exploration and production industry in Thailand.

Summary In this study, we investigate the complexities of carbon dioxide (CO2) injection/storage associated with dispersion in depleted natural gas reservoirs, examining the role of reservoir heterogeneity, permeability distributions, autocorrelation lengths, and variations in residual and mobile water saturations. These reservoir conditions are crucial for understanding the dispersive characteristics and their impact on the efficiency of CO2 storage in natural gas reservoirs. We used 2D and 3D stochastic numerical models to capture various reservoir heterogeneity configurations by investigating the impact of Dykstra-Parsons heterogeneity coefficients and vertical-to-horizontal permeability ratios. The impacts of residual water (Swr) and mobile water saturations (Sw), with and without the effect of CO2 and methane (CH4) solubility, were also studied. Approximate Péclet numbers were calculated to quantify the interplay between diffusive and advective transport while exploring gravity-dominated and channeling flow that ultimately influences CO2 transport and produced gas composition. All analyses are performed with a compositional reservoir simulation with the capability to account for the impacts of molecular diffusion and mechanical dispersion. Our findings reveal that higher Dykstra-Parsons coefficients (i.e., greater permeability heterogeneity) resulted in larger mixing zones (more dispersion), signifying the prevalence of advection in these cases. The analysis further indicates that in models with large vertical-to-horizontal permeability ratios, the advection-dominated flow regime is especially sensitive to variations in permeability distribution, with reservoirs displaying greater heterogeneity and exhibiting more channeling and convective spreading. In addition to this, large residual water saturation has no impact on dispersion unless CO2 and CH4 solubilities in the formation brine are significant. Variations in mobile water saturation (Sw) similarly alter CO2 flow behavior, with solubility effects found to generally reduce the size of the CO2-CH4 mixing zone because of solubilization of the downstream CO2, thereby affecting the spreading of the injected CO2. The insights gained from this work highlight the importance of understanding reservoir heterogeneity to optimize CO2 injection and storage in depleted gas reservoirs. By recognizing and quantifying the impact of these heterogeneities on gas flow and mixing, this research offers a way to enhance CO2 sequestration efficiency, aiding in the successful execution of CO2 storage initiatives in line with global energy transition goals.

The material balance techniques have been used in the oil and gas industry for estimating hydrocarbon reserves for a long time. The objective of this paper is to introduce a fairly simple and fast material balance technique that can provide a fairly good estimate of CO2 storage capacity in depleted gas reservoirs. Sequestration of CO2 in geological formations is a strategy currently being considered for decreasing CO2 emissions to the atmosphere. These geological formations can be either depleted oil and gas reservoirs or saline reservoirs. A depleted gas reservoir can store significantly more gas than a depleted oil reservoir due to the fact that gas is more compressible than oil and the ultimate recovery in gas reservoirs is higher than that in oil reservoirs. Many researchers have published reservoir simulation studies of CO2 sequestration in depleted gas fields, however, a reservoir simulation study, depending on its complexity, can take several months to perform. In this paper, a fairly simple and fast material balance technique, combined with nodal analysis, is presented that can provide a fairly good estimate of CO2 storage capacity in depleted gas reservoirs. A depleted gas reservoir, for which the production and pressure history data were available, was selected as a candidate to perform this material balance study. First the material balance calculations were performed to estimate the size of the gas reservoir, aquifer and reservoir pressure. The formation parting pressure was estimated based on basic rock mechanics principles as a function of reservoir pressure. The bottom hole injection pressure was maintained below the formation parting pressure, until the surface facilities limitations were reached. As a result of this study, the amount of CO2 that can be stored in this depleted gas reservoir was estimated within a few weeks.

Summary Methane (CH4) dissolved in an aquifer within a gas reservoir can be replaced by carbon dioxide (CO2) injection, which presents a promising route for carbon utilization and sequestration. However, the processes and mechanisms of CO2-CH4 codissolution and mass transfer remain unclear in multicomponent systems containing brine, CO2, CH4, and nitrogen (N2). In this work, water samples and simulated gases are prepared with respect to Zone IIIU of the S gas field with potential water-soluble gas. First, dissolving equilibrium experiments are performed to investigate the solubility of different injected gases in brine. The dynamic process of CO2-CH4 mass transfer in water after CO2 injection is further analyzed by competitive replacement experiments. The alterations of dissolved and undissolved gases and brine are observed using ion chromatography. Results indicate the following gas solubility ranking: CO2 > impure CO2 > CH4 > hydrocarbon gas > N2. The dynamic variations between hydrocarbon gas entry into the aquifer during water-soluble gas accumulation and CH4 release from the aqueous system during primary depletion production are elucidated. Since the original vapor/liquid phase equilibrium of water-soluble gas is broken by CO2 injection, a new aqueous system is rebuilt after CO2-CH4-brine interaction. The dissolution and modification of impure CO2 demonstrate potential for enhanced gas recovery (EGR) and geological carbon storage (GCS) in gas reservoirs with aquifers. The results of this study are important not only for EGR in water-soluble gas production from an aquifer but also for all GCS reservoir types, especially depleted gas reservoirs. Furthermore, the findings provide essential solubility parameters for thermodynamic calculation and numerical simulation of multicomponent phase equilibrium.

The emission of carbon dioxide into the atmosphere, which is one of the causes of the greenhouse effect, could be reduced by the removal of carbon dioxide from stack gases of power plants and subsequent injection of the removed carbon dioxide in depleted gas reservoirs. In The Netherlands there are some 220 gas reservoirs of which 90 are in production. The largest field, Groningen, with initial gas reserves of some 2,500 mrd m3 has a potential for carbon dioxide storage of 8 × 109 ton. The field cannot play an immediate role in the combat against the greenhouse effect, since its presently estimated depletion date is around the middle of the next century. Other Dutch onshore fields have a storage potential of 1.3 × 109 ton of carbon dioxide divided over about 100 reservoirs. These fields will gradually become available starting from about 2000 onwards. The cost of transport and injection of carbon dioxide in onshore reservoirs is estimated at Dfl 7,50/ton of carbon dioxide.

Hydrogen storage in depleted gas reservoirs: A comprehensive review

<p>Volatile organic sulfur compounds (VOSC) are known to occur in natural gas and petroleum reservoirs. These compounds are typically accompanied by H<sub>2</sub>S which together, degrade the quality of the petroleum, complicate production due to corrosion of piping, and pose a health risk to workers and local communities. The origins of both H<sub>2</sub>S and VOSC in natural gas are only partially understood with the latter being analyzed in only a few cases and its formation processes virtually unknown. Nevertheless, several studies have linked VOSC to H<sub>2</sub>S in processes such as thermochemical sulfate reduction (TSR) and kerogen cracking. Hence, VOSC have the potential to act as a proxy for the natural gas and H<sub>2</sub>S origins, in-situ TSR and fluid migration pathways.</p><p>To better understand the pathways of VOSC formation in natural gas reservoirs, we analyzed natural gas samples (Permian reservoirs, Sichuan Basin, China) and performed a series of pyrolysis experiments. The results of the experiments between methane (CH<sub>4</sub>) and H<sub>2</sub>S at 360°C for 4-96 hours revealed the only VOSC formed is methanethiol (MeSH) which was identified at ppm concentrations in all experiments. The δ<sup>34</sup>S values of the MeSH were 2 to 3‰ heavier than the initial H<sub>2</sub>S. For comparison, Meshoulam et al., (2021) reported that the reaction between H<sub>2</sub>S and pentane (i.e. “wet gas”) that yielded a variety of VOSCs from thiols to methyl-thiophenes in the gas phase and up to methyl-benzothiophenes in the liquid phase. The analysis of natural gases showed that the samples contain a large variety of thiols and sulfides. The diversity of VOSC identified carries some resemblance to that observed by Meshoulam et al., (2021) and may suggest these VOSC are the result of in-reservoir reaction of C<sub>2</sub>+ hydrocarbons with H<sub>2</sub>S. The analysis of δ<sup>34</sup>S values of the VOSCs showed they cover a range between +10 to +30‰ while most samples had their VOSC in a narrower range of approximately 8‰. Generally, samples show a positive correlation between H<sub>2</sub>S content and VOSCs concentration- thereby implying VOSCs formation in the gas-phase. The δ<sup>34</sup>S of thiols in five of the samples covered a narrower isotopic range of about 2‰ while the sulfides in the samples spread over a large isotopic range of up to 10‰. This observation suggests the thiols are in isotopic equilibrium with their associated H<sub>2</sub>S while the sulfides are not. The reason for this difference is unclear. Further analysis will shed more light on isotopic fractionations between VOSC and H<sub>2</sub>S and will thus allow identification of H<sub>2</sub>S origins in the studied area.</p><p>[1] Meshoulam, A., Said-Ahmad, W., Turich, C., Luu, N., Jacksier, T., Shurki, A., Amrani, A., 2021. Experimental and theoretical study on the formation of volatile sulfur compounds under gas reservoir conditions. <em>Organic Geochemistry</em>, 152, 104175</p>

Carbon Capture and Storage (CCS) is certainly the most important energy transition technology for the petroleum industry. The main objective of this process is to sequester carbon dioxide (CO2) in underground reservoirs/structures safely for many years with aim of reducing the greenhouse gas emissions and mitigating the global climate change impacts. Generally, there are four target areas for underground carbon storage. These consist of depleted oil or gas reservoirs, saline aquifers, coal beds and conventional oil reservoirs with a potential for enhance oil recovery (CO2-EOR). The current trend in the industry is mainly focused on the first two categories above. Large solubilization capacity of brine with multiple trapping mechanisms made the saline aquifer an interesting target while the existing knowledge, infrastructure in place and good injectivity are the most important factors for depleted hydrocarbon reservoirs. There are many published case studies in the literature focusing on CO2 storage in depleted gas reservoirs, however the majority of them apply to conventional dynamic flow, some with an added caprock integrity study. During producing life and CO2 injection phase in a depleted hydrocarbon reservoir, pores pressure and fluid saturation in the pore space changes affecting the fluid flow, geochemical equilibrium, and geomechanics properties of the reservoir. It is essential to establish an integrated coupled model to capture the inter-related effects of dynamic fluid flow, geochemistry and geomechanics on the storage capacity and integrity of the reservoir. During CO2 injection into depleted gas reservoirs, it is anticipated that there will be mineral dissolution or precipitation effects due to geochemical reactions that alter the rock porosity and permeability. This in turn will result in changes of the rock strength. Basically, these dynamic fluid flow, geochemical, and geomechanical changes are inter-related. Hence it is important to use an integrated coupled model that captures all these effects caused by CO2 injection to evaluate suitability of the reservoir for long-term CO2 storage. In this study, CMG's compositional simulator GEM is used to couple the dynamic fluid flow, the geochemistry, and the geomechanics to study the effects of all three changes. This provides a more accurate CO2 storage capacity estimation approach along with valuation of geomechanics such as subsidence at top of the reservoir and surface which determine the integrity of storage. For this paper a sector model extracted from a full field depleted gas reservoir with a single producer well which later converted to CO2 injector. The results of the coupled model show approximately 1% of injected CO2 in mole are mineralized in 3000 years considering geochemistry impact in the model. This translates to an equivalent increasing of storage capacity of 5-10% compared to conventional dynamic model. The results of the geochemical reactions show that initially there is some dissolution during the CO2 injection, after that within couple of hundred years there are precipitation and finally there is CO2 mineralization after 3000 years. This is mainly due to the expansion of the CO2 plume from the gas zone to the water zone. It is observed that during the production there is a subsidence of about 22 cm at the top of the reservoir and there is pore collapse due to pressure depletion in the reservoir rock. At the end of injection, subscience recovered by average of 20% of its maximum during the production. The injection can be continued until the initial reservoir pressure is reached without breaching caprock however due to rate constraint and risk of induced fracture, the injection rate is kept constant at 0.5 MMSCF/day.

Carbon dioxide capture from large stationary sources and storage in geological media is a technologically-feasible mitigation measure for the reduction of anthropogenic emissions of CO2 to the atmosphere in response to climate change. Carbon dioxide (CO2) can be sequestered underground in oil and gas reservoirs, in deep saline aquifers, in uneconomic coal beds and in salt caverns. The Alberta Basin provides a very large capacity for CO2 storage in oil and gas reservoirs, along with significant capacity in deep saline formations and possible unmineable coal beds. Regional assessments of potential geological CO2 storage capacity have largely focused so far on estimating the total capacity that might be available within each type of reservoir. While deep saline formations are effectively able to accept CO2 immediately, the storage potential of other classes of candidate storage reservoirs, primarily oil and gas fields, is not fully available at present time. Capacity estimates to date have largely overlooked rates of depletion in these types of storage reservoirs and typically report the total estimated storage capacity that will be available upon depletion. However, CO2 storage will not (and cannot economically) begin until the recoverable oil and gas have been produced via traditional means. This report describes a reevaluation of the CO2 storage capacity and an assessment of the timing of availability of the oil and gas pools in the Alberta Basin with very large storage capacity (>5 MtCO2 each) that are being looked at as likely targets for early implementation of CO2 storage in the region. Over 36,000 non-commingled (i.e., single) oil and gas pools were examined with effective CO2 storage capacities being individually estimated. For each pool, the life expectancy was estimated based on a combination of production decline analysis constrained by the remaining recoverable reserves and an assessment of economic viability, yielding an estimated depletion date, or year that it will be available for CO2 storage. The modeling framework and assumptions used to assess the impact of the timing of CO2 storage resource availability on the region’s deployment of CCS technologies is also described. The purpose of this report is to describe the data and methodology for examining the carbon dioxide (CO2) storage capacity resource of a major hydrocarbon province incorporating estimated depletion dates for its oil and gas fields with the largest CO2 storage capacity. This allows the development of a projected timeline for CO2 storage availability across the basin and enables a more realistic examination of potential oil and gas field CO2 storage utilization by the region’s large CO2 point sources. The Alberta Basin of western Canada was selected for this initial examination as a representative mature basin, and the development of capacity and depletion date estimates for the 227 largest oil and gas pools (with a total storage capacity of 4.7 GtCO2) is described, along with the impact on source-reservoir pairing and resulting CO2 transport and storage economics. The analysis indicates that timing of storage resource availability has a significant impact on the mix of storage reservoirs selected for utilization at a given time, and further confirms the value that all available reservoir types offer, providing important insights regarding CO2 storage implementation to this and other major oil and gas basins throughout North America and the rest of the world. For CCS technologies to deploy successfully and offer a meaningful contribution to climate change mitigation, CO2 storage reservoirs must be available not only where needed (preferably co-located with or near large concentrations of CO2 sources or emissions centers) but also when needed. The timing of CO2 storage resource availability is therefore an important factor to consider when assessing the real opportunities for CCS deployment in a given region.

Literature shows that there is a significant amount of natural gas available for enhanced recovery in the depleted reservoirs; at the same time, the depleted gas reservoirs are a proven storage facility for Carbon Dioxide (CO2) storage in terms of reservoir integrity. Conceptually, injecting CO2 into a depleted gas reservoir will not only potentially rejuvenalize the gas production, but will also store the greenhouse gas in a proven subsurface formation. Study on CO2 phase behavior in subsurface conditions shows that CO2 most likely will be in super-critical state which exhibits liquid-like density and gas-like viscosity. These properties are favorable in displacing natural gas reservoirs in volumetric and pore scale sweep efficiency. Using numerical reservoir simulation on a synthetic case with multiple scenarios, this paper identifies the most amenable characteristics of a reservoir for enhancing gas production by injecting CO2 and analyzes the parameters influencing this secondary recovery process. In the paper, reservoir depth, depletion pressure ratio, aquifer activity, inclination angle, reservoir heterogeneity with various permeability arrangement, injection rate, and producer bottomhole pressure will be studied on the synthetic model. Furthermore, this paper will quantify the amount of natural gas which can be produced and CO2 that can be stored in an ideal case using economic matrix. From this study, the ideal candidates for enhanced gas recovery by CO2 injection will be proposed based on simulation results, thus one can screen the available gas reservoirs for CO2 storage purpose and can quickly quantify the additional gas production from the secondary recovery.

ABSTRACT: This study explores the potential of repurposing depleted natural gas reservoirs for green hydrogen storage, utilizing the material balance equation (MBE) framework. The presence of an aquifer, a common feature in many depleted reservoirs, is considered, and the Carter and Tracy aquifer model is applied alongside the Peng-Robinson equation of state for hydrogen. A case study is conducted using a reference reservoir geometry with varying hydraulic properties (porosity and permeability) and a range of natural gas production rates. Results indicate that natural gas production rate, formation permeability, and porosity are critical factors not only for gas extraction but also for determining the feasibility of hydrogen storage. The study finds that typical sandstone reservoirs are most suitable for hydrogen storage, while formations with very high or low permeability present challenges. The findings highlight that with appropriate reservoir management, depleted gas reservoirs could serve as an effective hydrogen storage solution, contributing to a more flexible and resilient energy system. Future research should focus on understanding biochemical reactions in these reservoirs when exposed to hydrogen, which remains a relatively unexplored area. 1. INTRODUCTION The management of energy, a critical component in the transition from conventional energy resources to renewables, requires bridging the gap between demand and supply, often through the use of energy storage. One form of storage is hydrogen gas which is an energy carrier that can be used to store, transport, and deliver energy produced from other sources. In this energy transition, green hydrogen which is produced via electrolysis using renewable energy sources could play a vital role (Kourougianni et al., 2024). Although the production of green hydrogen is largely secured from a technological standpoint, the limited storage capacity remains a significant barrier to further development. Current storage technologies can accommodate limited volumes. To store large quantities of hydrogen, subsurface formations like aquifers, caverns, and depleted oil and gas reservoirs are promising candidates. Depleted oil and gas reservoirs are porous media which host fluids within their pore network, which once accommodated hydrocarbons. Together with aquifers, they can store large volumes accommodating variations on a weekly basis with TWh in terms of energy storage capacity (Edlmann et al., 2021).

This study investigates the complexities of CO2 injection/storage associated with dispersion in depleted natural gas reservoirs, examining the role of reservoir heterogeneity, permeability distributions, autocorrelation lengths, and variations in residual and mobile water saturations. These reservoir conditions are crucial for understanding the dispersive characteristics and their impact on the efficiency of CO2 storage in natural gas reservoirs. We used 2D and 3D stochastic numerical models to capture various reservoir heterogeneity configurations by investigating the impact of Dykstra-Parsons heterogeneity coefficients and vertical-to-horizontal permeability ratios. The impacts of residual water and mobile water saturations, with and without the effect of CO2 and CH4 solubility, were also studied. Approximate Peclet numbers were calculated to quantify the interplay between diffusive and advective transport while exploring gravity-dominated and channeling flow that ultimately influences CO2 transport and produced gas composition. All analysis is performed with a compositional reservoir simulation with the capability to account for the impacts of molecular diffusion and mechanical dispersion. Our findings reveal that higher Dykstra-Parsons coefficients (i.e. greater permeability heterogeneity) resulted in larger mixing zones (more dispersion), signifying the prevalence of advection in these cases. The analysis further indicates that in models with large vertical-to-horizontal permeability ratios, the advection-dominated flow regime is especially sensitive to variations in permeability distribution, with reservoirs displaying greater heterogeneity and exhibiting more channeling and convective spreading. In addition to this, large residual water saturation has no impact on dispersion unless CO2 and methane solubilities in the formation brine are significant. Variations in mobile water saturation similarly alter CO2 flow behavior, with solubility effects found to generally reduce the size of the CO2-CH4 mixing zone because of solubilization of the downstream CO2, thereby affecting the spreading of the injected CO2. The insights gained from this work highlight the importance of understanding reservoir heterogeneity to optimize CO2 injection and storage in depleted gas reservoirs. By recognizing and quantifying the impact of heterogeneities on gas flow and mixing, this research offers a way to enhance CO2 sequestration efficiency, aiding in the successful execution of CO2 storage initiatives in line with global energy transition goals.

Sequestration of carbon dioxide (CO2) in depleted or partially depleted oil reservoirs is an immediate, cost-effective option to reduce CO2 emissions into the atmosphere. Carbon dioxide has been injected into oil reservoirs for the purpose of enhancing oil recovery (EOR). With EOR, the goal is to maximize the oil production by minimizing the use of CO2 while with sequestration, the goal is to maximize the storage of the CO2. During EOR, a significant amount of CO2 may be sequestered in the reservoir. If CO2 emissions are regulated, the EOR process may therefore be able to earn sequestration credits in addition to oil revenues. We develop a theoretical framework that analyzes the co-optimization of oil extraction and CO2 sequestration. The economic analysis takes into account factors such as capture, transportation and recycling costs. This paper discusses the effects of several injection strategies and injection timing on optimization of oil recovery - CO2 storage capacity for a synthetic, three dimensional, heterogeneous reservoir model. A simulation study is completed using a 3-D compositional simulator " ECLIPSE 300?? and an optimization algorithm in order to optimize the net present value of oil recovery and CO2 storage. A number of simulations are studied to achieve comprehensive understanding of the financial performance of coupled CO2 sequestration and EOR projects. The simulations have showed that the projects would be unprofitable for immiscible cases when using costs typical of current CO2 capture from power plants unless there is some form of credit for storage. In contrast, in miscible cases, the projects may be profitable even without considering any CO2 credits and their profitability is further enhanced with possible carbon credits. The results show that innovative reservoir engineering techniques are required for co-optimizing CO2 storage and oil recovery. 1. Introduction CO2 concentration in the atmosphere has drastically increased over the past 250 years from 280 to 380 ppm (Bryant 1997). The major cause of increasing CO2 emissions into the air has been recognized as the dramatic increase in the fossil fuel consumption for energy production. Increasing concentrations of CO2 leads to climate change via enhancing the natural greenhouse effect. Several measures have been suggested to control the problem of increasing CO2 emissions in the air. One of such measures is to decrease carbon intensity of energy production, which means less CO2 per specified amount of produced energy (Forooghi, Hamouda and Eilertsen 2009). CO2 emissions can also be reduced by increasing the share of renewable energies in the energy consumption portfolio. The most promising, immediate option for reducing a large amount of CO2 is, however, the long-term sequestration of CO2 in geological formations. Depleted or mature oil and gas reservoirs, deep saline formations, and unminable coalbeds are usually considered as the most applicable CO2 sequestration formations (Bachu 2003). Geological CO2 storage as the effective option to mitigate atmospheric CO2 emissions has been considered since the 1990's and has been implemented at a large scale for the first time in Norway (Moritis 2002). Oil and gas reservoirs are good candidates for sequestration because industrial experiences already exist for CO2 injection. Regarding economic aspects of the sequestration process, coupled enhanced oil recovery (EOR) and sequestration processes have advantages since the increased oil recovery will offset some of the costs of CO2 sequestration process. The Weyburn CO2 sequestration and EOR project is an example of commercial coupled CO2 EOR and sequestration process, which has shown a great success in terms of both objectives of the project (Malik and Islam 2000). In this project, carbon dioxide is transported from the North Dakota coalgasification plant through pipelines and is injected into the Weyburn oil field.

The purpose of this paper is to investigate the effects of phase behavior on the sequestration CO2 of in depleted gas reservoirs (dry gas, wet gas and retrograde gas). Carbon dioxide sequestration in depleted and abandoned gas reservoirs can accomplish two important objectives. Firstly, it could be important part of present climate control initiative to reduce the concentration of carbon dioxide in the atmosphere. Secondly, it could be instrumental to enhance gas and condensate recovery. Using the pressure-temperature diagrams and two phase flash calculations, the phase behavior of natural gas-carbon dioxide mixtures were analyzed to provide enlightenment on the sequestration process. From analysis of simulated results, it was found that carbon dioxide exhibited a drying effect on wet and retrograde gas mixtures and a wetting effect on dry gas. The results for retrograde gas condensate depended on the composition of reservoir fluids at abandonment conditions. The main difference being the liquid volume present with increasing pressure and carbon dioxide concentration. This influenced the volume of condensate vaporized with addition of carbon dioxide. It was also determined that carbon dioxide lowers the compressibility factor of all gas types. These results are favorable for carbon dioxide sequestration because decreasing compressibility factors represents increasing storage capacity.

In the framework of selecting potential targets for CO2 geological storage, depleted gas reservoirs are well positioned because they offer directly reusable platform facilities, proven cap rock, and seal integrity; because these reservoirs contained a highly mobile gas phase for thousands to millions of years; and a very detailed reservoir characterization developed for gas production purposes. Furthermore, coupled with enhanced gas recovery, CO2 sequestration in gas reservoirs is also a means to reduce costs for CO2 injection by producing the remaining gas. This chapter presents a numerical simulation study of CO2 injection into the nearly depleted gas reservoir at the K12-B field, North Sea, selected as a demonstration site for the Offshore Reinjection of CO2 project. Simulations have been conducted using two different codes: TOUGHREACT, for characterizing the geochemical fluid-rock interactions that may occur during the injection period, and TOUGH2/EOS7C, for simulating the CO2 sequestration coupled with enhanced methane production. Simulation results show that considering the injection of about 3 million tons of CO2 for 10 yr, (1) a very low geochemical impact is expected to occur, which is favorable in terms of cap rock and reservoir integrity, and (2) the enhanced gas recovery efficiency remains limited when considering the full-scale CO2 injection rate.