Unconventional Gas Recovery Research Articles

Evaluation of CO2-enhanced gas recovery and storage through coupled non-isothermal compositional two-phase flow and geomechanics modelling

CO2 injection into unconventional gas reservoir has been recognized as a promising approach to enhance unconventional gas recovery (CO2-EUGR) and sequester CO2 geologically. The CO2-EUGR is a complex multi-physics coupling process. To accurately assess the effectiveness of different injection strategies, this paper firstly presents a non-isothermal compositional two-phase flow model coupling with geomechanics, in which a multicomponent adsorption kinetics is incorporated to separate free phase and adsorbed phase. A hybrid numerical approach combining EbFVM and GFEM is used for numerical solutions. The performance of different injection strategies for CO2-EUGR is evaluated. The results indicate that CO2 injection is able to improve CH4 recovery significantly, over 90 % of injected CO2 can be adsorbed in reservoirs, The performance of CO2-EUGR is permeability dependent, the displacement effect occurs earlier when reservoir permeability is higher; Increase in temperature of injected gas and mixed CO2/N2 injection can further improve CH4 recovery, especially for low permeability gas reservoirs; Mixed gas injection also enables displacement effect to occur earlier; Cyclic injection can hardly lead to increase in CH4 production, especially when reservoir permeability is higher, while it can cause an increase in amount of adsorbed CO2 during injection period. Based on these findings, a geothermal-assisted CO2-EUGR method is proposed.

An adsorption micro mechanism theoretical study of CO2-rich industrial waste gas for enhanced unconventional natural gas recovery: Comparison of coalbed methane, shale gas, and tight gas

Direct injection of CO2-rich industrial waste gas to displace unconventional natural gas is proposed as an energy-saving and green development method. In this work, the Giant canonical Monte Carlo and molecular dynamics methods were employed to compare the adsorption mechanisms of this method in three typical unconventional gas reservoirs, which are coal seam, shale and tight sandstone. It is found in the adsorption configurations that the proportion of gas molecules in the free state is higher in tight sandstone than in shale and coal seam. The adsorption energy of CH4/waste gas components on all reservoirs is in the order of CH4/SO2 > CH4/CO2 > CH4/NO > CH4/N2, among which the absolute value of the CH4/SO2 adsorption energy on the coal seam reaches the highest 64.220 kJ/mol. The adsorption selectivity of SO2, CO2 and NO over CH4 is greater than 1.0 in all reservoirs at depths of 0.5–4.0 km, and the competitive adsorption phenomenon in the deep reservoirs has a severe negative effect on it. Gas adsorption mode in the tight sandstone is dominated by filling pore structures, while gas adsorption in the coal seam is highly correlated with adsorption sites. This study is instructive for enhanced unconventional natural gas recovery by CO2-rich industrial waste gas injection from the perspective of gas adsorption.

A hybrid numerical model for coupled hydro-mechanical analysis during CO2 injection into heterogeneous unconventional reservoirs

This paper presents a hybrid numerical model for simulating compressible multiphase multicomponent transport in deformable, heterogeneous unconventional reservoirs. A fully implicit theoretical framework for coupled hydromechanical behaviour is established, in which the flash calculation is avoided. To preserve the local mass conversation, an element based finite volume method is used to spatially discretize mass conversation equations. Linear momentum equilibrium equation is discretized with finite element method. Two numerical approaches are coupled through sharing the same shape functions. An implicit mid-interval backwards difference algorithm is used to handle the temporal derivative. Reliability and efficiency of the developed model have been examined by verification tests against available analytical or numerical solutions. The coupled hydromechanical processes in heterogeneous reservoirs were simulated. The results of numerical experiments show that oscillatory problem for saturation in heterogeneous media can be eliminated, demonstrating better performance of developed model for heterogeneous reservoir simulations. Reservoir performance is significantly shaped by its heterogeneity through controlling fluid flow and time for CO2–CH4 displacement. Simulation results show that the time required for completion of CO2–CH4 displacement increases by about 250 days when considering heterogeneity effect. In conclusion, this study offers a valuable tool for facilitating the development of CO2-enhanced unconventional gas recovery.

Reservoir Porosity Improvement Device based on Underwater Pulse Arc Fracturing and Frequency Resonance Technology

SummaryThe low porosity of the reservoir has a significant impact on the production of unconventional oil and gas, hence a device to increase reservoir porosity and enhance unconventional oil and gas recovery was developed. The device can be lowered to 3000 m and operate continuously for more than 30 minutes under a discharge voltage of 11 kV in the frequency range of 0–60 Hz to improve reservoir porosity by causing reservoir resonance. The equipment structure includes an energy storage circuit, trigger switch, and energy transducer. The theoretical model of the energy storage circuit was established by the state space averaging method to obtain the time constant which was verified by a simulation experiment. The gas spark switch with an adjustable gap was used, the frequency control of the discharge pulse was achieved by rectifier voltage regulation, and the underwater pulse arc fracturing experiment was performed to confirm the accuracy and stability of the frequency control. Additionally, the effect of frequency resonance on reservoir porosity improvement was examined through comparative experiments, and the images of the distribution of pore texture in shale obtained by the X-ray computed tomography (CT) system demonstrate that resonance excitation can significantly promote the development of fractures and the improvement of shale samples’ porosity. The stimulation operation field experiment was carried out on coalbed methane wells in Shanxi Province, and the multipole array acoustic logging image verified that the equipment has a good reservoir porosity improvement effect. Experimental results indicate that this study has a potential application value in the field of unconventional reservoir stimulation.

Plasma based fracking in unconventional shale – A review

Shale gas and other unconventional resources such as coal bed methane, gas hydrates, tight oil etc. have gained significant worldwide interest because of their potential to increase the energy supply. Hydro fracking is the common technique to exploit the shale reservoir. However, there are some technical and environmental challenges linked to hydro fracking, which must be addressed in order to optimize resource recovery. Plasma fracturing has emerged as a technological breakthrough that may improve unconventional shale gas recovery which is a sustainable technique preventing the depletion of water resource and also reduces cost, energy use and environmental impacts. This technique utilizes the electrical energy to generate the plasma pulses thus minimizes the formation damage near the wellbore. The present paper reviews research progress on plasma fracturing mechanism and its advantages and associated challenges.

Feasibility investigation of enhanced coalbed methane recovery by steam injection

Heat injection is an effective technique to enhance unconventional oil and gas recovery. As an excellent heat transfer medium, steam has a great potential for coalbed methane (CBM) recovery enhancement. To investigate the feasibility of enhanced CBM recovery by steam injection, infrared thermal imaging (ITI) and thermocouples were employed to study the heating efficiency of steam on three ranks of coal, and nuclear magnetic resonance (NMR) was applied to analyze water transport within the coal after steam treatment. The results showed that the internal temperature of the coal samples reached about 80 °C in 17 min of steam treatment and thermal cracking of coal were induced, hence steam injection could facilitate gas desorption and provide more channels for gas migration. NMR test results indicated that steam preferentially condensed in coal micropores due to the capillary condensation effect, hence steam might have the potential to displace methane. The T2 spectra of the coals after steam treatment exhibited only the first two peaks without the third peak, indicating that steam injection might not cause the water blocking effect. The outcomes of this study are expected to provide valuable insights into the field application of steam injection to enhance CBM production.

Numerical investigation of the fracture network morphology in multi-cluster hydraulic fracturing of horizontal wells: A DDM-FVM study

Hydraulic fracturing is the most effective method to enhance the recovery of unconventional oil and gas via the formation of complex connected fracture networks. In this study, a pseudo three-dimensional fully fluid-solid coupled model is established to investigate the interaction between hydraulic fractures (HFs) and natural fractures (NFs), and the fracture network propagation process. The displacement discontinuity method (DDM) and finite volume method (FVM) are applied to simulate the rock deformation of the reservoir and fracturing fluid flow into the fracture networks, respectively. The influence of the stress shadow, flow rate distribution, comprehensive fluid loss, and complex extension behavior are considered in this model. A modified analytical crossing criterion is used to predict the interaction between the HF and NF. To improve the accuracy of the pressure calculation, the width of the fracture vertical cross-section is replaced by an equivalent width. The coupled equations are solved by Newton–Raphson iteration method. The numerical results of the proposed model agreed well with published analytical and experimental results. Based on the model, detailed sensitivity analyses are conducted to investigate the interaction between HFs and NFs, and the geometries of the fracture networks. The simulation results show that the fracture network morphology is significantly affected by NFs in naturally fractured reservoirs. The stress interference between HFs can weaken the effect of the horizontal stress difference; thus, NFs can be activated effectively. In addition, the complexity of the fracture network is proportional to the activation rate of the NFs. A more complex fracture network can be formed under the following conditions: a small horizontal stress difference, large NF length, low injection rate and low viscosity. It is noteworthy that a smaller value is not always better for cluster spacing. An optimal cluster spacing exist to obtain good results for reservoir stimulation.

Technology Focus: Natural Gas Processing and Handling (April 2022)

Natural gas has two faces. On one side, it is an important part of the energy-transformation toolkit. On the other side, it is a potent greenhouse gas. Technology can bring the two sides together. The three papers selected for this Tech Focus feature describe technologies that can make natural gas safer to move and store. The first paper, OTC 30655, describes an effort to eliminate flaring during offloading from a floating liquefied natural gas facility (FLNG) and an LNG carrier. Managing the balance of fuel gas and boiled-off gas between the FLNG and the carrier is vital to maintaining equilibrium and eliminating flaring. The paper looks at carriers with spherical tanks and presents a process study to identify potential causes of flaring during offtake and corrections that could eliminate it without capital modifications. The second paper, OTC 30871, considers the benefits of barges over ship-type LNG carriers. Ship-type LNG carriers are designed to operate offshore over fields, which does not necessarily provide optimal opportunity for monetization. The paper argues that near-shore barges holding liquefaction facilities linked to the rest of the system elsewhere could be a more-viable gas-monetization concept. The third paper, SPE 204787, describes a characterization and monitoring approach for underground gas storage. The approach involves close integration of subsurface understanding with the optimization of surface facilities. It also addresses sustainable operations through an asset-integrity-management plan. To learn more about the advancement of technology in the natural gas space, check out the suggested additional reading and visit the OnePetro online library. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 19783 - Hybrid System—An Emerging Solution to Sour Gas Treatment by Siddharth Parekh, Schlumberger SPE 202984 - Sour Gas Has a Sweeter Future—Bulk H2S Removal Using Polymeric Cellulose Triacetate-Based Membranes by Pinkesh Sanghani, Schlumberger, et al. SPE 208134 - Inventory Verification in Underground Gas Storage Rebuilt From Depleted Gas Reservoir: A Case Study From China by Lina Song, PetroChina, et al. SPE 207956 - Unconventional Waste and Flare Gas Recovery System in New Circular Economy by Mohamed Ahmed Soliman, Saudi Aramco, et al.

Flow regime evolution and stress-dependent permeability in nanoporous rocks

Researchers have studied microstructural controls on permeability of tight-matrix rocks, like coal and shale, in the recent years with growing interest in recovery of unconventional gas from deep rocks. Rock matrix in these reservoirs has significant proportion of microporoisty and, hence, the effective permeability is typically very low. Flow in tight-rock matrix is usually dependent on a complex and dynamic combination of pressure-governed Darcy flow regime in the fractures and macropores and concentration gradient-governed diffusive/non-Darcy flow regime in the meso- and micro- pores. Hence, multiple flow-regimes co-exist at any given pressure in these rocks. In this study, we present the experimental and modeling work carried out on tight coal from the San Juan basin and Marcellus shale. A methodology that uses pore size distribution to estimate the proportion of these dynamically changing and co-existing flow regimes in these rocks is presented. The appropriate proportions of Darcy and non-Darcy flow regime estimated using the methodology is then used in a flow model developed to assess the effective permeability variation of these rocks with depletion, that is, pressure decline. Finally, the stress path sensitivity is included in the model to estimate stress-dependent permeability variation in rocks. The developed model is validated against both coal and shale permeability data. The study establishes that effective permeability is dependent on pore size distribution and stress conditions since both dynamically affect the proportion of multiple co-existing flow regimes in these tight reservoirs.

In-situ 4D visualization and analysis of temperature-driven creep in an oil shale propped fracture

The proppant embedment due to creep in shales is a known issue affecting the useable lifetime of wells in unconventional oil and gas recovery. One of the factors influencing creep is the presence of organics, whose properties can be very sensitive to temperature. In this work we investigated for the first time the role of temperature-induced creep increase in proppant embedment in an organics-rich Green River oil shale sample via in-situ synchrotron X-ray micro-computed tomography. We observed that temperatures as low as 75 °C already induce fast creep, with a fracture aperture closing rate of 13 μm/h and a loss of fracture conductivity rate of 8.7%/h, due only to proppant embedment, in the measured interval at the first heating stage. Local displacement data analysis provided evidence for markedly plastic deformation around the proppant-shale contacts, in contrast with the brittle proppant embedment observed on more cemented and less organics-rich shales at room temperature. The results highlight how the problem of temperature-dependent mechanical behavior might be more important than previously thought, in shales with a high content in organics, and that in-situ micro-imaging techniques can play a key role in understanding the underlying mechanisms, contributing to solve creep-related problems associated with hydraulic fracturing in complex scenarios.

Fracture Reactivation Modeling in a Depleted Reservoir

Injection-induced fracture reactivation during hydraulic fracturing processes in shale gas development as well as coal bed methane (CBM) and other unconventional oil and gas recovery is widely investigated because of potential permeability enhancement impacts. Less attention is paid to induced fracture reactivation during oil and gas production and its impacts on reservoir permeability, despite its relatively common occurrence. During production, a reservoir tends to shrink as effective stresses increase, and the deviatoric effective stresses also increase. These changes in the principal effective stresses may cause Coulomb fracture slip in existing natural fractures, depending on their strength, orientation, and initial stress conditions. In this work, an extended finite element model with contact constraints is used to investigate different fracture slip scenarios induced by general reservoir pressure depletion. The numerical experiments assess the effect of Young’s modulus, the crack orientation, and the frictional coefficient of the crack surface on the distribution of stress and displacement after some reservoir depletion. Results show that the crack orientation significantly affects the state of stress and displacement, particularly in the vicinity of the crack. Slip can only occur in permitted directions, as determined by the magnitudes of the principal stresses and the frictional coefficient. Lastly, a larger frictional coefficient (i.e., a rougher natural fracture surface) makes the crack less prone to shear slip.

Reduced methane recovery at high pressure due to methane trapping in shale nanopores

By 2050, shale gas production is expected to exceed three-quarters of total US natural gas production. However, current unconventional hydrocarbon gas recovery rates are only around 20%. Maximizing production of this natural resource thus necessitates improved understanding of the fundamental mechanisms underlying hydrocarbon retention within the nanoporous shale matrix. In this study, we integrated molecular simulation with high-pressure small-angle neutron scattering (SANS), an experimental technique uniquely capable of characterizing methane behavior in situ within shale nanopores at elevated pressures. Samples were created using Marcellus shale, a gas-generative formation comprising the largest natural gas field in the United States. Our results demonstrate that, contrary to the conventional wisdom that elevated drawdown pressure increases methane recovery, a higher peak pressure led to the trapping of dense, liquid-like methane in sub-2 nm radius nanopores, which comprise more than 90% of the measured nanopore volume, due to irreversible deformation of the kerogen matrix. These findings have critical implications for pressure management strategies to maximize hydrocarbon recovery, as well as broad implications for fluid behavior under confinement.

Regeneration of unconventional natural gas by methanogens co-existing with sulfate-reducing prokaryotes in deep shale wells in China

Biogenic methane in shallow shale reservoirs has been proven to contribute to economic recovery of unconventional natural gas. However, whether the microbes inhabiting the deeper shale reservoirs at an average depth of 4.1 km and even co-occurring with sulfate-reducing prokaryote (SRP) have the potential to produce biomethane is still unclear. Stable isotopic technique with culture-dependent and independent approaches were employed to investigate the microbial and functional diversity related to methanogenic pathways and explore the relationship between SRP and methanogens in the shales in the Sichuan Basin, China. Although stable isotopic ratios of the gas implied a thermogenic origin for methane, the decreased trend of stable carbon and hydrogen isotope value provided clues for increasing microbial activities along with sustained gas production in these wells. These deep shale-gas wells harbored high abundance of methanogens (17.2%) with ability of utilizing various substrates for methanogenesis, which co-existed with SRP (6.7%). All genes required for performing methylotrophic, hydrogenotrophic and acetoclastic methanogenesis were present. Methane production experiments of produced water, with and without additional available substrates for methanogens, further confirmed biomethane production via all three methanogenic pathways. Statistical analysis and incubation tests revealed the partnership between SRP and methanogens under in situ sulfate concentration (~ 9 mg/L). These results suggest that biomethane could be produced with more flexible stimulation strategies for unconventional natural gas recovery even at the higher depths and at the presence of SRP.

Permeability-enhanced rate model for coal permeability evolution and its application under various triaxial stress conditions

Knowledge on permeability enhancement is of great significance for the exploitation of coalbed methane, shale gas, and tight gas. In this study, the volumetric strain of rocks is considered to be one of the most important permeability change factors. A new model based on the concept of the permeability-enhanced rate (PER), which is referred to as the permeability ratio variation of per volumetric strain, is derived based on Darcy’s law, the tablet flow model, and the theories of flow through porous media and capillary flow. To validate the PER model using coal samples under triaxial stress conditions, loading tests at different gas pressures and loading-unloading tests at different loading-unloading rates are conducted. In the loading tests, the PER evolution is quite different for the different gas pressures. The PER value at a gas pressure of 1 MPa reached 108.40, which was 1.69, 1.41, and 1.57 times as high as the PER value at 0.5 MPa, 3 MPa, and 5 MPa, respectively. In the loading-unloading tests, the PER value was calculated based on the initial porosity and the relative increment in the volumetric strain during the whole loading-unloading process. A lower loading-unloading rate implied a more connected failure surface, and the PER value was greatly enhanced in the post-peak phase. The results show that a good relation between the deformation and seepage characteristics is developed in the PER model. The PER can not only capture the failure process and describe the pore-fracture connectivity improvement induced under loading conditions but can also quantitatively evaluate the permeability evolution, which provides an easy and fundamental method to describe the relative degree of permeability change in the recovery of unconventional gas.

A method for simultaneously determining axial permeability and transverse permeability of tight reservoir cores by canister degassing test

AbstractPermeability anisotropy of shale and tight gas reservoirs is critical for applications in unconventional gas recovery, but laboratory measurements are still limited. This paper presents an experimental method for determining permeability anisotropy of shale and tight reservoirs. The method uses gas production data from a canister and an analytical solution of continuity equation in anisotropic core sample. Axial permeability and transverse permeability of the core are estimated by matching experimental data with analytical solution. The proposed method is verified by comparing with true values and calculated values through numerical simulations that cover variations in rock permeability. The method is applied to real data measured in canister degassing tests (CDT) involving two different directional shale core samples. Then, the experimental results are compared with the results from pulse pressure decay (PPD) method. Both the verification from numerically calculated results and the comparison between PPD results and CDT results exhibit the practicality of the proposed method. At last, the effects of permeability anisotropy, porosity, initial gas pressure, rock dimensions, and adsorption on the profiles of gas production are investigated.

210Po in the environment: insight into the naturally occurring polonium isotope

Polonium is rapidly emerging as an international environmental health concern primarily because of the recent rise in hydraulic fracturing (fracking). Recovery of unconventional oil and gas generates produced water containing natural radioactivity, which is increasing the radiological impact of 210Po. In this context, accurate measurements of 210Po in environmental samples is crucial because 210Po is the main contributor to the natural radiation dose received by all living organisms. However, the analytical chemistry of polonium is complicated, primarily due to its volatility. This review highlights recent analytical progress and challenges in determination of 210Po in the environmental and biological samples.

Fracturing with Carbon Dioxide: From Microscopic Mechanism to Reservoir Application

Summary Water fracturing is widely employed as a reservoir-stimulating technology for the recovery of unconventional oil and gas. However, the process suffers from massive water consumption and environmental concerns. Therefore, alternative fracturing fluids are desired. In recent years, fracturing with CO2 was proposed to embrace multiple benefits, including carbon storage, enhanced recovery, etc. Herein, based on specially designed facilities and new analytical methodologies, we present multiscale and quantitative investigations on the fracturing mechanism and behavior of CO2 and water. It was demonstrated that because of the high leak-off of CO2, shear fractures can be readily induced, which facilitated the formation of tensile and mixed fractures, leading to effective fracturing, complex networks, and greater stimulated reservoir volume. Finally, a 4- to 20- fold increase in tight oil production could be achieved by CO2 fracturing in field tests with five wells.

Modeling and simulation on heat-injection enhanced coal seam gas recovery with experimentally validated non-Darcy gas flow

Abstract Heat-injection into coal seam has gained great attention as a supplementary method for the improvement of unconventional gas recovery from deep reservoirs in recent years. However, it involves a lot of ambiguous interactions among the deformation of formation, the transport of gas and the diffusion of heat in the porous coal media, especially the property of gas. In this paper, the seepage behavior of coal seam gas (CSG) that obeys non-Darcy flow law was directly observed in a conducted laboratory experiments. Then, a general Forchheimer equation was confirmed and strictly validated by the experimental data to characterize the non-Darcy seepage phenomenon. Subsequently, a fully coupled thermo-hydro-mechanical model was mathematically established. Based on the finite element approach, a numerical simulation for heat-injection enhanced coal seam gas recovery was then implemented. The susceptibilities of coal permeability and gas production to the gas sorption, heat-mass transfer, and the porosity-seepage characteristics of coal were quantified by a series of numerical scenarios. Final modeling and simulation results reveal that: (1) coal seam gas flow obeys non-Darcy law when the gradient of gas pressure is higher, but trends to be laminar flow that obeys Darcy law when the gradient is lower, and (2) heat-injection to stimulate coal seam could improve the production efficiency, increasing the Langmuir volume sorption parameter, the temperature correction coefficient and the initial values of permeability can improve coal permeability and enhance gas production.

East coast gas: resource potential at different gas price scenarios (Part 1: quantification of unconventional gas resource potential)

A qualitative ranking of the remaining gas potential of Australian east coast basins was undertaken using a spatial analysis methodology of play fairway sweet-spot mapping. Play components considered important for the presence and recovery of unconventional gas were mapped across the plays of interest in Australian east coast basins. Modelled horizontal well type curves and development plans from North American analogues for unconventional gas production were used to quantify the sweet-spot mapping using a methodology we developed called common recovery segment mapping. A range of potential resource numbers were calculated for each play, leading to a quantification of the potential resource across the entire area of interest. Part 2 of this paper will show how these undeveloped unconventional gas resources may ultimately contribute to the east coast Australia energy mix.

On factors affecting coalbed gas content measurement

Coalbed gas content measurement is important for both unconventional gas recovery and mining safety. This study experimentally discussed factors affecting coalbed gas content measurement. It is found that small coal particles demonstrated high desorption rate at the early stage of desorption tests. However, the difference in methane desorption rate reduces when the coal particle size is more than 1.0 mm, indicating that a threshold of coal particle size exists in methane desorption in coal. Also, the particle size distribution tends to be stable when coal sample mass is over 15 g, stabilizing at around 1.75 mm. Therefore, the coal sample over 15 g is recommended to use in desorption tests of coalbed gas content measurement. The temperature and gas pressure can enhance the desorption rate, especially at the early stage of desorption. This temperature effect, however, mainly occurred in the first 15 min of desorption test. After 30 min, the desorption rate tends to be stable, slightly changing from around 0.35 mol/kg/min to 0.75 mol/kg/min. Due to endothermic process, absolute isothermal condition does not exist in desorption test, but this temperature variation mainly occurred in the first 15 min. The results also show incorporating the desorption data from the time of exposure to 13 min of desorption tests is essential to typically reflect methane desorption kinetics in coal. The study also shows that the measurement difference in gas content between the case with sample being air-puffed and -flushed and the case with sample exposed to the air is small. Therefore, the air-puffing and flushing during the sample collection has an insignificant effect the gas contact measurement result. This study can help to advance the understanding of impact factors on coalbed gas content measurement method.