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Collaborating Authors
You, Zhenjiang
Implications of Recent Research into the Application of Graded Particles or Micro-Proppants for Coal Seam Gas and Shale Hydraulic Fracturing
Johnson, Raymond Leslie (The University of Queensland, Centre for Natural Gas) | Ramanandraibe, Honja Miharisoa (The University of Queensland, School of Chemical Engineering) | Di Vaira, Nathan (The University of Queensland, School of Mechanical and Mining Engineering) | Leonardi, Chris (The University of Queensland, School of Mechanical and Mining Engineering) | You, Zhenjiang (The University of Queensland, Centre for Natural Gas) | Santiago, Vanessa (The University of Queensland, School of Chemical Engineering) | Ribeiro, Ayrton (The University of Queensland, Centre for Natural Gas) | Badalyan, Alexander (The University of Adelaide, Australian School of Petroleum and Energy Resources) | Bedrikovetsky, Pavel (The University of Adelaide, Australian School of Petroleum and Energy Resources) | Zeinijahromi, Abbas (The University of Adelaide, Australian School of Petroleum and Energy Resources) | Carageorgos, Themis (The University of Adelaide, Australian School of Petroleum and Energy Resources) | Sanchez-Barra, Angel (The University of Alberta, Reservoir Geomechanics Research Group) | Chalaturnyk, Rick (The University of Alberta, Reservoir Geomechanics Research Group) | Deisman, Nathan (The University of Alberta, Reservoir Geomechanics Research Group)
Abstract Low permeability, naturally fractured reservoirs such as coal seam gas (CSG, coalbed methane or CBM) and shale gas reservoirs generally require well stimulation to achieve economic production rates. Coupling hydraulic fracturing and micro-proppant or graded particle injections (GPI) can be a means to maximise hydrocarbon recovery from these tight, naturally fractured reservoirs, by maintaining or improving cleat or natural fracture conductivity. This paper presents a summary of the National Energy Resources Australia (NERA) project "Converting tight contingent CSG resources: Application of graded particle injection in CSG stimulation" - which assessed the application of micro-proppants, providing guidance on key considerations for GPI application to CSG reservoirs. Over the last decade, laboratory research and modelling have shown the benefits of the application of GPI to keep pre-existing natural fractures and induced fractures open during production of coal reservoirs with pressure dependent permeability (PDP). Laboratory studies, within this study, provide further insight on potential mechanisms and key factors, including proppant size and optimum concentration, which contribute to the success of a micro-proppant placement. Accompanying numerical modelling studies will be presented that describe the likely fluidized behaviour of micro-proppants (e.g., straining models, electrostatic effects, and ‘screen out’ prediction). This paper outlines the necessary reservoir characterization, treatment considerations, and key numerical modelling inputs necessary for the design, execution, and evaluation of GPI treatments, whether performed standalone or in conjunction with hydraulic fracturing treatments. It also provides insight on the practical application of GPI efficiently into fracturing operations, minimizing natural and hydraulic fracturing damage effects, thereby maximizing potential production enhancement for coals, shales and other tight, naturally fractured reservoirs exhibiting pressure-dependent permeability effects.
- North America > United States (1.00)
- Europe (1.00)
- Oceania > Australia > Queensland (0.94)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.93)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.80)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- North America > United States > New Mexico > San Juan Basin (0.99)
- (5 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Modeling and Economic Analyses of Graded Particle Injections in Conjunction with Hydraulic Fracturing of Coal Seam Gas Reservoirs
Santiago, Vanessa (The University of Queensland (Corresponding author)) | Ribeiro, Ayrton (The University of Queensland) | Johnson, Raymond (The University of Queensland) | Hurter, Suzanne (The University of Queensland) | You, Zhenjiang (The University of Queensland and Edith Cowan University (Corresponding author))
Summary Hydraulic fractures can enhance well productivity from stress-sensitive naturally fractured reservoirs, such as coalbed methane or coal seam gas (CSG) reservoirs. Graded proppant injection (GPI) has been proposed to enhance long-term, far-field interconnectivity between the created hydraulic and short-term, enhanced natural fracture permeability, resulting from fracture fluid leakoff and lowered net effective stress. This novel study shows how applying GPI with hydraulic fracturing treatments resulting in an increased stimulated reservoir volume (SRV) can enhance well productivity and improve CSG well economics. A commercially available reservoir model and history-matched hydraulically fractured coal seam case are used to evaluate well performance differences between a hydraulic fractured reservoir and one including GPI application. A dual-porosity system and the Palmer and Mansoori model are used to simulate initial and long-term permeability accounting for reservoir depletion (i.e., increased net effective stress and matrix shrinkage). A previously validated case study is used to describe the post-embedment benefits of GPI based on the porosity model and history-matched reservoir properties. A net present value (NPV) can then be calculated for each scenario, based on the production differences and typical Australian CSG costs. Our results show that permeability enhancement is achieved beyond the hydraulically fractured region for all post-GPI stimulation cases. An optimal SRV can be found relative to permeability that maximizes the incremental NPV from GPI application. The next most significant parameters after permeability that influence the economic outcomes are fracture porosity and coal compressibility. A larger SRV yields higher cumulative gas production over 30 years with up to 7.2 times increase over gas production without GPI. This study substantially increases our understanding of how to model and understand the benefits of GPI application along with hydraulic fracturing to increase the SRV in CSG wells.
- North America > United States (0.93)
- Oceania > Australia > Queensland (0.48)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.94)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Modelling and Economic Analyses of Graded Particle Injections in Conjunction with Hydraulically Fracturing of Coal Seam Gas Reservoirs
Santiago, Vanessa (The University of Queensland, Australia) | Ribeiro, Ayrton (The University of Queensland, Australia) | Johnson, Raymond (The University of Queensland, Australia) | Hurter, Suzanne (The University of Queensland, Australia) | You, Zhenjiang (Edith Cowan University, Australia)
Abstract Hydraulic fractures can enhance well productivity from stress sensitive naturally fractured reservoirs such as coalbed methane or coal seam gas (CSG) reservoirs. Graded proppant injection (GPI) has been proposed to enhance long-term, far-field interconnectivity between the created hydraulic and short-term, enhanced natural fracture permeability, resulting from fracture fluid leakoff and lowered net effective stress. This novel study shows how applying GPI with hydraulic fracturing treatments resulting in an increased stimulated reservoir volume (SRV) can enhance well productivity and improve CSG well economics. A commercially available reservoir model and history-matched hydraulically fractured coal seam case is used to evaluate well performance differences between a hydraulic fractured reservoir and one including GPI application. A dual-porosity system and Palmer and Mansoori model are used to simulate initial and long-term permeability accounting for reservoir depletion (i.e., increased net effective stress, matrix shrinkage). A previously validated case study is used to describe the post-embedment benefits of GPI based on the porosity model and history-matched reservoir properties. A net present value (NPV) can then be calculated for each scenario, based on the production differences and typical Australian CSG costs. Our results show that permeability enhancement is achieved beyond the hydraulically fractured region for all post-GPI stimulation cases. An optimal SRV can be found relative to permeability that maximises the incremental NPV from GPI application. The next most significant parameters after permeability that influence the economic outcomes are fracture porosity and coal compressibility. A larger SRV yields higher cumulative gas production over 30 years with up to 7.2 times increase over gas production without GPI. This study substantially increases our understanding on how to model and understand the benefit of GPI application along with hydraulic fracturing to increase the SRV in CSG wells.
- North America (0.68)
- Oceania > Australia > Queensland (0.47)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.94)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Case Study and Sensitivity Analysis of Borehole Breakout in the Cooper Basin, Australia
Zhong, Ruizhi (The University of Queensland) | Azman, Aideel (The University of Queensland) | Johnson, Ray (The University of Queensland) | You, Zhenjiang (Edith Cowan University The University of Queensland) | Nguyen, Lan (Pure Hydrogen Corporation Limited)
Abstract The Cooper Basin of Australia is challenged by high deviatory stress conditions in the strike-slip to reverse stress regimes, which increase borehole breakout during drilling. This paper studies the applicability of failure criteria such as Mohr-Coulomb, Mogi-Coulomb, and Drucker-Prager for wellbore collapse in a low permeability sandstone well in the Cooper Basin, Australia. The influences of well conditions and rock mechanical properties on the wellbore collapse modeling are also investigated. The 1D mechanical earth model (MEM) from well Tamarama-1 is compiled and extracted to provide four sections of data with borehole breakouts. First, the stresses around the borehole are calculated using the Kirsch equations. Then, different failure criteria (i.e., Mohr-Coulomb, Mogi-Coulomb, and Drucker-Prager) are used to evaluate the areas of borehole breakout. Finally, a parametric analysis is presented to show the influences of well conditions and rock mechanical properties on the prediction of borehole breakouts. The results show that the Mogi-Coulomb criterion and Drucker-Prager criterion have a good match with borehole breakouts from field observations. The Mohr-Coulomb criterion overestimates the wellbore collapse pressure and breakout areas because it ignores the strengthening effect of the intermediate principal stress. The parametric study shows that the maximum horizontal stress, azimuth, inclination, and friction angle can affect borehole breakouts in terms of magnitude and orientation. Rock mechanical properties such as Young's Modulus do not affect the borehole breakout, and Poisson's ratio has a minor effect on the borehole breakout. A better understanding of borehole stability is crucial and beneficial to drilling and completions of oil and gas wells. This paper provides an integrated workflow to determine which failure criterion is most applicable for given conditions and provides a framework for a more detailed sensitivity analysis on borehole breakout. It has applicability for the numerous strike-slip regimes being appraised with deviated and horizontal wellbores in the Eastern Hemisphere.
- Oceania > Australia > Queensland (0.92)
- Oceania > Australia > South Australia (0.82)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
Integrating Reservoir Characterisation, Diagnostic Fracture Injection Testing, Hydraulic Fracturing and Post-Frac Well Production Data to Define Pressure Dependent Permeability Behavior in Coal
Johnson, Raymond L. (University of Queensland) | You, Zhenjiang (University of Queensland) | Ribeiro, Ayrton (University of Queensland) | Mukherjee, Saswata (University of Queensland) | Salomao de Santiago, Vanessa (University of Queensland) | Leonardi, Christopher (University of Queensland)
Abstract Defining pressure dependent permeability (PDP) behaviour in coalbed methane (CBM) or coal seam gas (CSG) reservoirs using reservoir simulation is non-unique based on the uncertainty in coal properties and input parameters. A diagnostic fracture injection test (DFIT) can be used to investigate bulk permeability at a reservoir level and at lowered net effective stress conditions. As coal has minimal matrix porosity and under DFIT conditions cleat porosity is fluid saturated with reasonably definable total compressibility values, the DFIT data can provide insight into PDP parameters. At pressures above the fissure opening pressure, pressure dependent leak off (PDL) behaviour increases exponentially with increasing pressure. Many authors have noted that with decreasing pressure PDP declines exponentially with increasing net effective stress. Thus, PDP behaviour can be defined by PDL. In this paper, we show how combined analyses, using typically collected field data, can be used to better define and constrain the modelling of PDP. We illustrate this process based on a well case study that includes the following data: fracture fabric and porosity reasonably defined from image log and areal core studies; DFIT data acquired under initial saturation conditions; hydraulic fracturing data; and longer term production data. These analyses will be integrated and used to constrain the parameters required to obtain a rate and pressure history-match from the post-frac well production data. This workflow has application in other coal seam gas cases by identifying key variables where hydraulic fracturing performance has been unable to overcome limitations based on pressure or stress dependent behaviours and often accompanied by low reservoir permeability values. While this is purposely targeting areas where only typically collected field data is available, this workflow can include coal testing data for matrix swelling/shrinkage properties or other production data analysis techniques.
- North America > United States > Texas (0.93)
- Europe (0.93)
- Oceania > Australia > Queensland (0.70)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.46)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- (27 more...)
Evaluating Performance of Graded Proppant Injection into CSG Reservoir: A Reservoir Simulation Study
Ribeiro, Ayrton (The University of Queensland Centre for Natural Gas Energi Simulation Research Fellow, The University of Queensland) | Santiago, Vanessa (School of Chemical Engineering, The University of Queensland) | You, Zhenjiang (School of Chemical Engineering, The University of Queensland) | Johnson Jr, Raymond (School of Chemical Engineering, The University of Queensland The University of Queensland Centre for Natural Gas) | Hurter, Suzanne (The University of Queensland Centre for Natural Gas)
Abstract Stress-dependent permeability in coal seam gas (CSG) reservoirs can challenge the development of coal fields with lower initial permeabilities. Thus, advanced well stimulation techniques become essential. This work evaluates the performance of novel graded proppant injection (GPI) technique for CSG reservoir stimulation using reservoir simulation models. A simplified model for steady-state incompressible fluid flow during the early dewatering stage of production is validated by the analytical model results. A general model is then developed for GPI process during unsteady-state compressible two-phase flow in coal, accounting for gas desorption, matrix shrinkage, heterogeneous permeability distribution, and cross-flow. Fractured porous medium is modelled by a dual-porosity radial model. Stress-dependent permeability and matrix shrinkage effects are modelled using the Palmer-Mansoori equation. Under the incompressible fluid flow condition, the productivity index after well stimulation using GPI technique increases by 1.3~2.3 times. Moreover, simulation of compressible gas-water flow coupled with gas desorption from matrix yields 4~13% increment on recovery factor (RF) during production for 30 years. Stimulation accounting for matrix shrinkage enhances RF by 9~13%. For heterogeneous permeability distribution, more permeable layers exhibit deeper penetration of particles. The enhanced permeability owing to GPI yields higher production of both gas and water. Cross-flow between the coal layers influence the effectiveness of the depressurisation process and hence gas desorption post-stimulation. It allows dewatering of deeper layers and additional desorption of gas.
- North America > United States (1.00)
- Oceania > Australia > Queensland (0.47)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.67)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
Development of Predictive Models in Support of Micro-Particle Injection in Naturally Fractured Reservoirs
You, Zhenjiang (School of Chemical Engineering, The University of Queensland) | Wang, Duo (School of Mechanical and Mining Engineering, The University of Queensland) | Di Vaira, Nathan (School of Mechanical and Mining Engineering, The University of Queensland) | Johnson, Raymond (School of Chemical Engineering, The University of Queensland The University of Queensland Centre for Natural Gas) | Bedrikovetsky, Pavel (Australian School of Petroleum, The University of Adelaide) | Leonardi, Christopher (School of Mechanical and Mining Engineering, The University of Queensland The University of Queensland Centre for Natural Gas)
Abstract New models for particle embedment during micro-particle injection into naturally fractured reservoirs are developed. The proposed models aim to predict production benefit from the application of micro-particle injection during coal seam gas (CSG) stimulation with broader applications to other naturally fractured reservoirs. The elastoplastic finite element modelling is applied to coal sample from Surat basin (Australia), to predict micro-particle embedment and fracture deformation under various packing densities and closure stresses. The coupled lattice Boltzmann-discrete element model (LBM-DEM) is then used for permeability prediction. These results are combined in a radial Darcy flow analytical solution to predict the productivity index of CSG wells. Modelling results indicate that considering elastoplastic fracture surface deformation leads to smaller permeability increase and less production enhancement, if compared with the linear elastic deformation of fracture implemented in traditional models. Although focused on Australian coals, the developed workflow is more broadly applicable in other unconventional resources. Modelling of particle transport and leak-off in coal fracture intersected with a cleat using LBM-DEM approach demonstrates the effects of particle and cleat sizes, particle concentration and sedimentation on the leak-off process. The leak-off is significantly affected if the particle-cleat size ratio is higher than 0.5. Particle sedimentation increases leak-off into vertical cleat substantially, but has no effect on horizontal cleat. Suspensions of higher concentration result in higher leak-off for cleats with different apertures.
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.68)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- Information Technology > Modeling & Simulation (0.83)
- Information Technology > Data Science > Data Mining (0.40)
Abstract Compressibility needs to be accounted for when estimating productivity decline in closed gas and oil reservoirs, and in closed aquifers. Previous works derived an analytical model and well index for inflow performance accompanied by fines migration and consequent permeability damage for incompressible flow towards well. In the present work, we account for fluid and rock compressibility. The problem with given and constant well production rate is investigated. Mathematical model is developed, which provides well productivity index decline with time. Under this model, the solution of damage-free compressible flow in a closed reservoir is matched with the impedance growth formulae for incompressible flow in the well vicinity. The well production data have been successfully matched by the model; the tuning parameters have the common values. It allows indicating the fines mobilization, migration and straining as possible well impairment mechanism in wells under investigation.
- North America > United States (0.68)
- Africa (0.46)
Lost-Circulation Control for Formation-Damage Prevention in Naturally Fractured Reservoir: Mathematical Model and Experimental Study
Xu, Chengyuan (Southwest Petroleum University) | Kang, Yili (Southwest Petroleum University) | You, Lijun (Southwest Petroleum University) | You, Zhenjiang (University of Adelaide)
Summary Drill-in fluid loss is the most important cause of formation damage during the drill-in process in fractured tight reservoirs. The addition of lost-circulation material (LCM) into drill-in fluid is the most popular technique for loss control. However, traditional LCM selection is mainly performed by use of the trial-and-error method because of the lack of mathematical models. The present work aims at filling this gap by developing a new mathematical model to characterize the performance of drill-in fluid-loss control by use of LCM during the drill-in process of fractured tight reservoirs. Plugging-zone strength and fracture-propagation pressure are the two main factors affecting drill-in fluid-loss control. The developed mathematical model consists of two submodels: the plugging-zone-strength model and the fracture-propagation-pressure model. Explicit formulae are obtained for LCM selection dependent on the proposed model to control drill-in fluid loss and prevent formation damage. Effects of LCM mechanical and geometrical properties on loss-control performance are analyzed for optimal fracture plugging and propagation control. Laboratory tests on loss-control effect by use of different types and concentrations of LCMs are performed. Different combinations of acid-soluble rigid particles, fibers, and elastic particles are tested to generate a synergy effect for drill-in fluid-loss control. The derived model is validated by laboratory data and successfully applied to the field case study in Sichuan Basin, China.
- Research Report > Experimental Study (0.64)
- Research Report > New Finding (0.50)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
Prevention of Water-Blocking Formation Damage in Gas Reservoirs Wettability Alteration, Analytical Modelling
Naik, Saurabh (Australian School of Petroleum, The University of Adelaide) | You, Zhenjiang (Australian School of Petroleum, The University of Adelaide) | Bedrikovetsky, Pavel (Australian School of Petroleum, The University of Adelaide)
Abstract Water blocking is a widespread formation damage mechanism in oil and gas reservoirs. The end effect on the well sand-face or fracture results in the creation of a water film which significantly reduces gas permeability. The removal of the water film by changing wettability near to the wellbore or hydraulic fracture is the traditional method of well stimulation. We describe inflow performance by two-phase steady-state flow towards well. The wettability affects the relative permeability and the capillary pressure. Treatment of the well neighbourhood by nanoparticles or surfactants results in a reservoir with non-uniform wettability. We present a steady-state solution for inflow performance and show how the alteration of the contact angle and the treatment depth affects the well productivity index. The model is verified by comparison with coreflood data. The developed analytical model can be used for the prediction of gas well productivity, and for the planning and design of wettability-alteration well-stimulation. The main result of the paper is the existence of the optimal contact angle.