Utilization of CO2 Injection to Improve Oil Recovery of the Handsworth Bakken Formation

The Bakken formation has become a prominent oil resource for south-east Saskatchewan, especially with the advent of horizontal well technology and new hydraulic fracturing methods. As more wells are drilled, there is a desire to determine whether there is potential for improved oil recovery and to evaluate the economic feasibility. This paper evaluates the benefit of implementing waterflooding, CO2 injection or WAG （water-alternating-gas） recovery methods for improved oil recovery of the Bakken formation. A simulation model resembling the study area was built using CMG-GEM （computer modeling group-generalized equation of state model） reservoir simulation package and a history match of the primary recovery data available was performed. Based on the simulation results, it was concluded that waterflooding had a significant influence on the oil recovery factor, although COz provided the highest increase in crude oil recovery, The capital expenditure for surface facilities and cost of injected fluid was the most economically viable for implementation of waterflooding. The WAG injection simulation results were similar to CO2 injection, except that reservoir pressure was able to be better maintained. Given that high-quality source water is available, waterflooding is the most economically feasible choice according to the simulation results obtained from this study.

Sorption of methane and CO_2 for enhanced coalbed methane recovery and carbon dioxide sequestration

Sequestration of CO2 in deep and unmineable coal seams is one of the attractive alternatives to reduce its atmospheric concentration. Injection of CO2 in coal seams may help in enhancing the recovery of coalbed methane. An experimental study has been carried out using coal samples from three different coal seams, to evaluate the enhanced gas recovery and sequestration potential of these coals. The coals were first saturated with methane and then by depressurization some of the adsorbed methane was desorbed. After partial desorption, CO2 was injected into the coals and subsequently they were depressurized again. Desorption of methane after the injections was studied, to investigate the ability of CO2 to displace and enhance the recovery of methane from the coals. The coals exhibited varying behavior of adsorption of CO2 and release of methane. For one coal, the release of methane was enhanced by injection of CO2, suggesting preferential adsorption of CO2 and desorption of methane. For the other two coals, CO2 injection did not produce incremental methane initially, as there was initial resistance to methane release. However with continued CO2 injection, most of the remaining methane was produced. The study suggested that preferential sorption behavior of coal and enhanced gas recovery pattern could not be generalized for all coals.

Mechanism of CO_2 enhanced CBM recovery in China: a review

Permeability of coal reservoirs in China is in general low. Injection of CO2 into coal seams is one of the potential ap-proaches for enhancing coalbed methane (CBM) production. The feasibility of this technology has been investigated in China since the 1990s. Advances in mechanism of CO2 enhanced CBM recovery (CO2-ECBM) in China are reviewed in light of certain aspects, such as the competitive multi-component gas adsorption, sorption-induced coal swelling/shrinkage and its potential effect on CBM production and numerical simulation for CO2-ECBM recovery. Newer investigations for improving the technology are discussed. It is suggested that a comprehensive feasibility demonstration in terms of geology, technology, economics and environment-carrying capacity is necessary for a successful application of the technology for CBM recovery in China. The demonstration should be car-ried out after more investigations into such facets as the control of coal components and structure to a competitive multi-component-gas adsorption, the behavior and essence of super-critical adsorption by coal of gas, environmental and safe feasi-bility of coal mining after CO2 injection and more extensive pilot tests for CO2-ECBM recovery.

Modelling of microbial enhanced oil recovery application using anaerobic gas-producing bacteria

Microbial enhanced oil recovery （MEOR） methods apply injection of bacteria to depleted oil reservoirs to produce oil, which had remained unrecovered after the conventional methods of production. The ability ofthermophilic anaerobic bacteria to produce gas as the main mechanism in potential MEOR in high salinities of 70-100 g/L was investigated in this study. Maximum gas production of up to 350 mL per 700 mL of salty solution was produced at a salinity of 90 g/L stably during 2-4 days of experiment. The experimental results were upscaled to the Snorre Oilfield, Norway, and simulated using ECLIPSE software for 27 months. The best scenarios showed that the increase in oil recovery on average was at 21% and 17.8% respectively. This study demonstrated that anaerobic bacteria used in biogas plants could be an attractive candidate for MEOR implementation due to their ability to withstand high temperature and salinity, and produce gas in large volumes.

A review of chemical-assisted minimum miscibility pressure reduction in CO_(2) injection for enhanced oil recovery

Miscible CO_(2)injection appears to be an important enhanced oil recovery technique for improving sweep efficiency and eliminating CO_(2)-oil interfacial tension resulting in up to 10%higher oil recovery compared to immiscible flooding,in addition to the environmental benefits of reducing greenhouse gas emissions through carbon capturing utilising and storage(CCUS).Moreover,this technique could be similarly applicable to natural gas and nitrogen projects to increase oil recovery and to reduce the associated gas flaring.However,miscible displacement may not be achievable for all reservoirs,in particular,reservoirs with high temperature where high injection pressure would be needed to reach miscibility which likely exceeds the formation fracture pressure.Therefore,to further achieve reservoirs’potential,there is a pressing need to explore a viable means to decrease the miscibility pressure,and thus expand the application envelop of miscible gas injection in reservoirs with high temperatures.In this work,we aim to provide insights into minimum miscibility pressure(MMP)reduction by adding chemicals into CO_(2)phase during injection.We achieved this objective by performing a comprehensive review on chemical-assisted MMP reduction using different chemical additives(e.g.,alcohols,fatty acids,surfactants)and different experimental methodologies.Previous experimental studies have shown that a fraction of chemical additives can yield up to 22%of MMP reduction in CO_(2)-oil system.Based on results analysis,surfactant based chemicals were found to be more efficient compared to alcohol based chemicals in reducing the interfacial tension in the CO_(2)-oil system.Based on the current experimental results,adding chemicals to improve the miscibility and reduce the MMP in the CO_(2)-oil system appears to be a promising technique to increase oil recovery while reducing operating cost.Selection of the effective chemical additives may help to expand the application of miscible gas injection to shallow and high temperature reservoirs.Furthermore,our review provides an overall framework to screen potential chemical additives and an injection strategy to be used for miscible displacement in CO_(2)and/or gas systems.

A fully coupled finite element framework for thermal fracturing simulation in subsurface cold CO2 injection

Thermal fracturing could occur during cold CO2 injection into subsurface warm rock formations.It can be seen in a variety of fields such as carbon geo-sequestration,unconventional gas development,enhanced oil recovery,geothermal energy extraction,and energy geological storage systems.In CO2 geosequestion,limited degree of thermal fracturing due to the cooling effects of cold CO2 injection will enhance well injectivity,especially for those storage formations of low permeability.Thermal fracturing can therefore potentially enhance the injection efficiency and make positive impact on commercialization of CO2 geological storage.However,excessively developed fractures could break down the caprock and cause potential CO2 leakage into overlying rock formations.Risk analysis has to be done based on thermal fracturing simulation in order to maintain caprock integrity.Simulation of thermal fracturing during cold CO2 injection involves the coupled processes of heat transfer,mass transport,rock deforming as well as fracture propagation.To model such a complex coupled system,a fully coupled finite element framework for thermal fracturing simulation is presented.This framework is based on the theory of non-isothermal multiphase flow in fracturing porous media.It takes advantage of recent advances in stabilized finite element and extended finite element methods.The stabilized finite element method overcomes the numerical instability encountered when the traditional finite element method is used to solve the convection dominated heat transfer equation,while the extended finite element method overcomes the limitation with traditional finite element method that a model has to be remeshed when a fracture is initiated or propagating and fracturing paths have to be aligned with element boundaries.

A simulation study of water injection and gas injectivity scenarios in a fractured carbonate reservoir:A comparative study

Regarding the enormous demands of numerous industries to fossil fuels,it is essential to select the proper enhanced oil recovery approaches for vertical and horizontal wells to supply the demands with the optimum expenditure.Water and gas injectivity as the secondary enhanced oil recovery techniques would be preferentially considered regarding their low costs of performances rather than chemical recovery and thermal techniques.Injected gas tends to push oil through pores or cracks in the matrix block and lead them to the production well.Therefore,injection of gas may significantly increase the recovery factor in these reservoirs.In this research,different injection scenarios in a fractured carbonate reservoir in the west of Iran are being simulated by the PVT modules of Eclipse software.The purpose of this research is to analyze the possibility of gradually increasing the extent of recovery by injecting carbon dioxide,methane,and water,and different injectivity patterns are considered in this research.The selection of injectivity patterns is severely based on the highest recycling rate of gas injection on different injection scenarios,and the injectivity scenarios were being compared with the natural depletion scenario.Consequently,Co2 injection(about 60%)had the highest oil recovery factor and CH4 and TB(about 54%and 53%)injectivity scenarios had the second and third highest rate of the oil recovery factor.

Experimental research of condensate blockage and mitigating effect of gas injection

The condensate blockage causes a substantial decrease in well productivity for gas condensate reservoirs.Based on the previous studies,a novel experimental method was designed to evaluate condensate blockage and the mitigating effect of gas injection.The method considers the stacking effect in the near wellbore region and the gas flow in the far wellbore region.There is an intermediate vessel containing condensate gas at the entrance of core holder in the experimental apparatus.In the process of pressure depletion experiment in a long core model,the vessel is connected to the core and the pressure of the vessel remains above the dew point pressure.The seriousness of condensate blockage is investigated by this research.When pressure drops to maximum retrograde condensation pressure,the gas permeability decreases by 80%compared with the initial gas permeability.Contrastive experiments were conducted to study the removal effect of different injection fluids and different injection volumes.The results show that CO2 injection is more effective than methanol in mitigating condensate blockage and the optimal CO2 injection volume is around 0.15 HCPV。