Enhanced Coalbed Methane Recovery Using Microorganisms

As traditional petroleum supplies dwindled and prices soared over the past few years, oil companies have shifted their attention to oil sands, a mix of sand, water, and a heavy, viscous hydrocarbon called bitumen that can be converted to oil. With the plunge in oil prices in fall 2008, many producers began canceling or postponing plans to expand oil sands development projects, but this turn of events could yet reverse, as Canada’s vast oil sands deposits are lauded as a secure source of imported oil for the United States. At the same time, however, oil sands present troubling questions in terms of the environmental health effects associated with their development.

The production of natural gas from coal seam reservoirs follows a succession of stages that are well established and understood. Salient components are the execution of hydraulic fractures, dewatering of both native and introduced water, and the subsequent production of what it is almost entirely methane. Most coal seams are of relatively small net pay thickness and in many cases also of low permeability, i.e. 2 md or less. Produced gas comes from a combination of both free gas in the coal porosity and, especially, desorbing gas. Because of large heterogeneities and major differences among coal seam reservoirs, the hydraulic fracturing is rarely uneventful with a large number of issues to be resolved, such as fluid selection or the mass of proppant. Most of these decisions are local and often conclusion cannot be drawn from elsewhere. Frequently, a well is subjected to multiple stages of hydraulic fracture treatments. Production performance characteristics also vary considerably. The interaction between permeability, natural cleat networks and natural and artificial fractures is often complicated and difficult to predict. This results in different periods of post-treatment de-watering, the volume of water that is produced and the onset of predominant natural gas production. We have constructed a realistic physical and economic model where the NPV criterion is used to identify successful or potentially uneconomic candidates. We forecast fractured well performance using the Unified Fracture Design (UFD) approach and we account for time of de-watering and the cost of water management. Charged against the net present value of the revenue are the costs of fracturing and well completion. Five wells with different Langmuir isotherm parameters were considered for the NPV parametric studies. The parametric studies include a range of reservoir permeabilities, porosities, proppant masses, and fracture heights. The results show the window of attractive prospects and delineate the unattractive prospects which can be considerable.

Gas injection is a proven EOR method in the oil industry with many well-documented successful field applications spanning a period of more than five decades. The injected gas composition varies between projects, but is typically hydrocarbon gas, sometimes enriched with intermediate components to ensure miscibility, or carbon dioxide in regions such as the Permian Basin, where supply is available at an attractive price. Miscible nitrogen injection into oil reservoirs, on the other hand, is a relatively uncommon EOR technique because nitrogen often requires a prohibitively high pressure to reach miscibility. Unlike other injection gases, the minimum miscibility pressure for nitrogen decreases with increasing temperature. In fact, in deep, hot reservoirs containing volatile oil, nitrogen may develop miscibility at a pressure similar to the MMP for hydrocarbon gas or carbon dioxide. The phase behavior is more complicated than what can be captured by correlations and hence requires equation-of-state calculations. Results from a recent EOR screening study in ADNOC indicate that a couple of high-temperature oil reservoirs in Abu Dhabi may be potential targets for miscible nitrogen injection. This paper discusses key aspects of the EOS modeling. Advanced gas injection PVT data are available to enable a fair comparison between nitrogen, carbon dioxide and lean hydrocarbon gas. In this work, we have modelled and analyzed the phase behavior of two volatile oil systems with respect to nitrogen, hydrocarbon gas, and carbon dioxide injection, as part of a reservoir simulation study, which will be covered in a subsequent publication; see Mogensen and Xu (2019). Nitrogen behaves differently from hydrogen carbon gas, despite the fact that the two gases lead to similar minimum miscibility pressures. At the prevailing reservoir pressure, the swelling factor with hydrocarbon gas is four times higher than for nitrogen. Furthermore, the reservoir fluid density increases during swelling with nitrogen, whereas it decreases as a result of hydrocarbon gas swelling. The same trend is observed for viscosity. Injection gas blends with various proportions of nitrogen and carbon injection shows that the MMP is constant when more than 35-40% nitrogen is present in the blend.

Storing carbon dioxide (CO2) resulting from the burning of fossil fuels in geological formations could be an environmentally appealing approach to mitigate the volume of greenhouse gas emissions. Among the geological choices available, storing CO2 in coal deposits offers numerous benefits. For instance, injecting CO2 can boost methane production from coal reserves, coal has the capacity to securely retain CO2 for extended durations, and there are promising coal basins near various CO2-emitting sources that contain suitable formations for sequestration. Practical trials involving the storage of CO2 in coal seam reservoirs have encountered significant challenges, primarily the decline in injectivity resulting from coal swelling and extensive loss due to the concentration of the reservoir's cleat system. CO2 sequestration in coal reservoirs carries several potential risks, including leakage CO2 if not properly contained, which can migrate through the geological formations. Additionally, it can induce seismicity—the injection of CO2 may increase pore pressure in the coal reservoir, potentially triggering seismic activity, especially if the pressure buildup leads to fault. There are also concerns about reservoir integrity, as the injection of CO2 can alter the structural and mechanical properties of the coal reservoir, leading to coal swelling, and environmental impacts. In this research, our objective is to review and reassess research related to the storage of CO2 in coal reservoirs. This study concentrates on the alterations in characteristics and responses of coal formations resulting from CO2 exposure in the context of CO2 sequestration. We emphasize the key discoveries from existing research up to this point and suggest areas with significant potential.

Coal seam as the gas productive reservoir and gas-bearing reservoir, it is different from the conventional sandstone reservoir. On the one hand, coal cleat is well-developed in coal seam reservoir. Its characteristics are low porosity, small permeability, large specific surface area, low mechanical strength, strong heterogeneity, low reservoir pressure and so forth. These characteristics determine that drilling has more influence on coal seam reservoir than on conventional sandstone reservoir. In the process of drilling, therefore, in order to reduce or avoid the pollution to coal seam, usually adopt underbalanced drilling way to keep negative differential pressure and to reduce the damage of fluid in borehole flowing into the reservoir. At the same time, when underbalanced drilling, formation fluid flows into the borehole, leading to the formation pressure near the borehole to change. On the other hand, due to coal seam with low mechanical strength, great brittleness, and well-developed coal cleat, in the process of drilling especially underbalanced drilling, borehole wall is prone to collapse. Coal cleat exists in the coal seam and affects its mechanical property. When studying coal seam borehole wall stability, coal cleat must be considered. Considering time effect, the paper established the borehole wall stability model of coal seam with coal cleat when underbalanced drilling, obtained the collapse pressure distribution, and analyzed influence factors of coal seam borehole wall stability, providing theoretical guidance to prevent borehole wall instability. Key words : Coal seam; Underbalanced drilling; Negative differential pressure; Borehole wall stability; Coal cleat

CO 2 coal seam storage is a significant component of carbon capture and storage technology, which serves as a pivotal technical instrument for the reduction of greenhouse gas emissions. The Ordos Basin develops a considerable number of unminable coal seams, which present an optimal place for CO 2 coal seam storage. This paper presents an investigation into the geological characteristics of the No.4 coal seam reservoir in the Shanxi Formation of Permian age and the No.8 coal seam reservoir in the Benxi Formation of Carboniferous age. To explore the adsorption capacity of coal rock and the sealing performance of caprock, relevant experiments were conducted. The results of the experiments demonstrate that the adsorption capacity of CO 2 on the coal samples is 1.11–3.73 times that of CH 4 . The results of the breakthrough pressure test demonstrate that the mudstone sealing performance is the most effective, followed by dense limestone and sandy mudstone. Combined with the geological data of the study area, the analytic hierarchy process method was used to evaluate the CO 2 storage potential of coal seams. The areas suitable for geological storage of CO 2 in the study area are located in the central part and the south‐central part.

The recovery of coal bed methane can be enhanced by injecting carbon dioxide (CO2) in the coal seam at supercritical conditions. Through an in situ adsorption/desorption process the displaced methane (CH4) is produced and the adsorbed CO2 is permanently stored. This process is called Enhanced Coal Bed Methane recovery (ECBM) and it is a technique under investigation as a possible approach to the geological storage of CO2 in a carbon dioxide capture and storage (CCS) system. ECBM recovery is not yet a mature technology, in spite of the growing number of pilot and field tests worldwide that have shown its potential and highlighted its difficulties. The problems encountered are largely due to the heterogeneous nature of coal and its complex interaction with gases. These issues, which represent the motivation of this research work, need to be addressed both at laboratory and field test scales. The aim of this thesis is therefore to develop experimental and modeling tools that are able to provide a comprehensive characterization of coal required first to understand the mechanisms acting during the process of injection and storage and secondly to assess its potential for an ECBM operation. In particular, sorption data of CO2, CH4 and N2 on several coals from different coal mines worldwide have been measured at conditions typically encountered in coal seams. CO2 maximum sorption capacity per unit mass of dry coal has been found to range between 5% and 14% weight and to depend on coal rank in a non-monotonic way. Moreover, for a specific coal, competitive sorption isotherms of the binary and ternary mixtures of these gases have been obtained, showing that CO2 adsorbs always more than CH4, and CH4 more than N2. This property is of key importance for ECBM application. In order to investigate the coal volumetric behavior upon exposure to an adsorbing gas, two approaches have been followed. In the first, the utilization of a visualization technique allowed to measure the unconstrained expansion of a coal disc, confirming that indeed coal swells when exposed to a gas that is able to adsorb on its surface and penetrate into its structure, whereas exposure

Coal seam gas is an unconventional resource for natural gas that is becoming popular due to its environmental benefit and abundance. This paper reviews recent developments on the pore-scale characterisation of coal from coal seam gas reserviors. The development of micro-computed tomography (micro-CT) imaging has enabled for the 3D characterization of the fracture system in coals. This provides detailed insights into understanding flow in these unconventional reservoirs. A novel image calibration method in which the skeleton of the fracture system is obtained from micro-CT imaging while the fracture apertures are measured from scanning electron microscopy (SEM) is described. We also show the application of micro-CT imaging for studying diffusion processes in ultralow permeability matrices and discuss the incorporation of the data into calculations of gas production from unconventional reservoirs. The extraction of statistical information from micro-CT images to reconstruct coal cleat system are also demonstrated. This technique allows for preserving the key attributes of the cleat system while the generated fracture network is not limited in terms of size nor resolution. The developments of microfluidic methods for understanding the complex displacement mechanisms in coal seams are also described. These low-cost experimental methods can provide unique information about the displacement mechanisms occurring during gas production from coal seam reservoirs. Variation of coal contact angle with pressure is analysed and results demonstrate important wettability processes that occur in coal seams. We describe numerical methods for prediction of petrophysical properties from micro-CT images of coal and discuss the associated limitations when dealing with coal samples. The paper concludes by addressing the challenges faced when characterising coal at the micro-scale and approaches for population of coal data into reservoir simulators for relaible prediction of reservoir behaviour during gas production as well as CO2 sequestration in coalbeds.

Early Permian Cattle Creek Coals in Fairview Field in Queensland Australia is an insitu multicomponent Coal Seam Gas Reservoir. The Early Permian East coals or Springwater play typically occur at depths between 1,100 m to 1,800 m. These medium volatile bituminous coals are characterized as having lower permeability (<5 mD), a high gas content (10 – 15 m3/t daf), an elevated concentration of ethane and heavier hydrocarbon components (2 – 14% C2+), and higher inerts concentration (0.2 – 12% CO2, < 3% N2) than found in many CSG fields. . An analysis and history match of the production data from existing appraisal wells with a particular emphasis on the produced gas composition and its variation with depletion was performed using both an in-house compositional simulator which used the extended Langmuir Isotherm as the basis for the equilibrium relationship between the free and the sorbed gas phase and a commercial compositional simulator. Methane, Carbon Dioxide, Ethane, Propane and Nitrogen were simulated during this study. The results showed potential differences between the produced gas composition obtained during well production (considering the adsorption/desorption behavior of a multicomponent gas in a coal seam reservoir) and the in-situ gas composition determined from gas sampling during desorption tests. Heating value profiles were generated and compared illustrating the potential impact of the reservoir dynamic behaviour. The results also showed how the produced concentration of N2 (free gas phase) can be 4 to 7 times higher than its insitu concentration and that a variation of up to 75% of the initial concentration in free gas phase of CO2 and C2H6 concentration is possible due to the variability of the isotherms indicated from core.

Significant amounts () of water are currently being extracted from coalbed methane (CBM) wells in Permian–Carboniferous coal in the Liulin area of the eastern Ordos basin, China. Waters coproduced with CBM have common chemical characteristics that can be an important exploration tool because they relate to the coal depositional environment and hydrodynamic maturation of groundwater and can be used to guide CBM development strategies. The CBM production targets of the No. 3 and 4 coal seams from sandstone in the Shanxi Formation and No. 8, 9, and 10 coal seams in the karst of the Taiyuan Formation were deposited in fluvial-deltaic and epicontinental-sea environments, respectively. This paper combines CBM geology, hydrogeology, CBM recovery, and laboratory data to define mechanisms of CBM preservation including the important influence of groundwater. Relevant indices include fluid inclusions as an indicator of the hydraulic connection between the coal seam reservoir and the overlaying strata and the ensemble characteristics of total dissolved solids (TDS) contents of water, water production rates, and reservoir temperatures as an indication of the current hydraulic connection. The TDS contents of waters from the No. 3 and 4 and No. 9 and 10 coal seams are double those from the subjacent karst No. 8 coal seam, indicating the important control of fast flow in karst. Low-salinity fluid inclusions from the roof of the subjacent-karst No. 8 coal seam also indicate an enduring hydraulic connection with overlaying strata during its burial history. Relatively low current temperatures in the No. 8 (subjacent-karst) coal seam also infer a strong hydraulic connection and active flow regime. Deuterium concentrations are elevated in the mudstone-bounded No. 9 and 10 coal seams, further confirming low rates of fluid transmission. The gas contents of coal seams from the Taiyuan Formation are higher than those from the sandstone-bounded coal seams in Shanxi Formation, also correlating with low rates of water transmission and low permeability. Conceptual models for these fluvial-deltaic and epicontinental-sea environments that are consistent with geology, gas content, and gas and water production rate histories are of gas-pressure sealing for the Shanxi Formation and hydrostatic-pressure sealing for the Taiyuan Formation. These results confirm the important controls of hydrogeological conditions on the preservation of CBM and the utility of hydrogeological indicators in prospecting for CBM.

Application of coalbed methane hydraulic jet-increasing permeability-nitrogen injection to increase production in Shanxi mining area

This paper presents a scoping study to investigate the economic viability of nitrogen injection to improve the recovery of coalbed gas. The sensitivity of the analysis to key reservoir parameters is also presented. The results of the study suggest that nitrogen injection may be more attractive than conventional pressure depletion for lower permeability formations where the loss in permeability with pressure decline is significant. Nitrogen injection economics are shown to be very sensitive to the costs associated with injection and separation and are adversely affected by reservoir heterogeneity.

Complex thermal coal-gas interactions in heat injection enhanced CBM recovery

Enhanced Oil Recovery techniques are one of the top priorities of technology development in petroleum industries nowadays due to the increase in demand for oil and gas which cannot be equalized by the primary production or secondary production methods. The main function of EOR process is to displace oil to the production wells by the injection of different fluids to supplement the natural energy present in the reservoir. Moreover, these injecting fluids can also help in the alterations of the properties of the reservoir like lowering the IFTs, wettability alteration, a change in pH value, emulsion formation, clay migration and oil viscosity reduction. The objective of this experiment is to investigate the residual oil recovery by combining the effects of gas injection followed by low salinity water injection for low permeability reservoirs. This is done by a series of flooding tests on selected tight carbonate core samples taken from Zakuum oil field in Abu Dhabi by using firstly low salinity water as the base case and nitrogen & CO2 injection followed by low salinity water flooding at reservoir conditions of pressure and temperature. The experimental results revealed that a significant improvement of the oil recovery is achieved by the nitrogen injection followed by the low salinity water flooding with a recovery factor of approximately 24% of the residual oil.

Enhanced Oil Recovery techniques are one of the top priorities of technology development in petroleum industries nowadays due to the increase in demand for oil and gas which cannot be equalized by the primary production or secondary production methods. The main function of EOR process is to displace oil to the production wells by the injection of different fluids to supplement the natural energy present in the reservoir. Moreover, these injecting fluids can also help in the alterations of the properties of the reservoir like lowering the IFTs, wettability alteration, a change in pH value, emulsion formation, clay migration and oil viscosity reduction. The objective of this experiment is to investigate the residual oil recovery by combining the effects of gas injection followed by low salinity water injection for low permeability reservoirs. This is done by a series of flooding tests on selected tight carbonate core samples taken from Zakuum oil field in Abu Dhabi by using firstly low salinity water as the base case and nitrogen & CO2injection followed by low salinity water flooding at reservoir conditions of pressure and temperature. The experimental results revealed that a significant improvement of the oil recovery is achieved by the nitrogen injection followed by the low salinity water flooding with a recovery factor of approximately 24% of the residual oil.