Effect of matrix shrinkage on wellbore stresses in coal seam gas: An example from Bowen Basin, east Australia

Reisabadi, Mohammadreza Zare; Haghighi, Manouchehr; Sayyafzadeh, Mohammad; Khaksar, Abbas

doi:10.1016/j.jngse.2020.103280

Cited by 14 publications

(5 citation statements)

References 28 publications

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“…Functional form of permeability change versus reservoir pressure depends on many factors including cleat compressibility, coal geomechanical properties and matrix shrinkage [7,45,146,149,151,155,163,164]. Coal failure and fine production, when occurs, can result in decrease in permeability and subsequently affect the shape of permeability change curve [165][166][167][168][169][170][171][172][173]. The impact of coal failure on permeability change in Australian CSG basins is less investigated and requires further research.…”

Section: Author/s Study Area Methodsmentioning

confidence: 99%

History, Geology, In Situ Stress Pattern, Gas Content and Permeability of Coal Seam Gas Basins in Australia: A Review

et al. 2021

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Coal seam gas (CSG), also known as coalbed methane (CBM), is an important source of gas supply to the liquefied natural gas (LNG) exporting facilities in eastern Australia and to the Australian domestic market. In late 2018, Australia became the largest exporter of LNG in the world. 29% of the country’s LNG nameplate capacity is in three east coast facilities that are supplied primarily by coal seam gas. Six geological basins including Bowen, Sydney, Gunnedah, Surat, Cooper and Gloucester host the majority of CSG resources in Australia. The Bowen and Surat basins contain an estimated 40Tcf of CSG whereas other basins contain relatively minor accumulations. In the Cooper Basin of South Australia, thick and laterally extensive Permian deep coal seams (>2 km) are currently underdeveloped resources. Since 2013, gas production exclusively from deep coal seams has been tested as a single add-on fracture stimulation in vertical well completions across the Cooper Basin. The rates and reserves achieved since 2013 demonstrate a robust statistical distribution (>130 hydraulic fracture stages), the mean of which, is economically viable. The geological characteristics including coal rank, thickness and hydrogeology as well as the present-day stress pattern create favourable conditions for CSG production. Detailed analyses of high-resolution borehole image log data reveal that there are major perturbations in maximum horizontal stress (SHmax) orientation, both spatially and with depth in Australian CSG basins, which is critical in hydraulic fracture stimulation and geomechanical modelling. Within a basin, significant variability in gas content and permeability may be observed with depth. The major reasons for such variabilities are coal rank, sealing capacity of overlying formations, measurement methods, thermal effects of magmatic intrusions, geological structures and stress regime. Field studies in Australia show permeability may enhance throughout depletion in CSG fields and the functional form of permeability versus reservoir pressure is exponential, consistent with observations in North American CSG fields.

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Section: Author/s Study Area Methodsmentioning

confidence: 99%

History, Geology, In Situ Stress Pattern, Gas Content and Permeability of Coal Seam Gas Basins in Australia: A Review

et al. 2021

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“…By taking the derivative of time of Eq. 9, the Norton power law criterion related to the creep time can be obtained (Reisabadi et al, 2020;Science-Natural Gas Science and Engineering, 2020;Xinxin et al, 2022):…”

Section: Creep Modelmentioning

confidence: 99%

The shrinkage behavior of boreholes drilled through deepwater creeping salt formations in West Africa

Wang,

Deng,

et al. 2024

Front. Energy Res.

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Introduction: Salt formations are complex and pose significant risks during oil and gas drilling. Creep behavior in salt formations under geostress can jeopardize drilling safety.Methods: This study analyzes the shrinkage behavior of boreholes drilled through salt formations in West Africa’s Block B, with emphasis on the differential creep rates in two horizontal principal stress directions and the evolution of wellbore shape over time. The impact of drilling fluid density on shrinkage rates is also investigated.Results: After drilling through salt formations, the creep rates differ between the two horizontal principal stress directions. Shrinkage is faster in the direction of minimum horizontal principal stress and slower in the direction of maximum horizontal principal stress. Over time, shrinkage rates converge, resulting in a transition from elliptical to circular wellbore shape. Higher drilling fluid density leads to reduced shrinkage rates.Discussion: These findings contribute to the theoretical guidance for drilling fluid density selection in salt formations.

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“…Subsequent studies have built upon this foundation. For instance, Reisabadi et al [12] introduced an analytical model that considers the effects of depletion, matrix shrinkage, and wellbore trajectory when estimating the stress distribution around the wellbore. Li et al [13] developed a heat-fluid-solid coupling numerical model for horizontal wells in NGH reservoirs, taking into account hydrate decomposition.…”

Section: Introductionmentioning

confidence: 99%

Research on Fluid–Solid Coupling Mechanism around Openhole Wellbore under Transient Seepage Conditions

Liu,

Zhou,

et al. 2024

Processes

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Hydraulic fracturing is one of the most important enhanced oil recovery technologies currently used to develop unconventional oil and gas reservoirs. During hydraulic fracture initiation, fluid seeps into the reservoir rocks surrounding the wellbore, inducing rock deformation and changes in the stress field. Analyzing the fluid–solid coupling mechanism around the wellbore is crucial to the construction design of fracturing technologies such as pulse fracturing and supercritical carbon dioxide fracturing. In this study, a new transient fluid–solid coupling model, capable of simulating the pore pressure field and effective stress field around the wellbore, was established based on the Biot consolidation theory combined with the finite difference method. The numerical results are in excellent agreement with the analytical solutions, indicating the reliability of the model and the stability of the computational approach. Using this model, the influence of seepage parameters and reservoir properties on the fluid–solid coupling around the open-hole wellbore was investigated. The simulation results demonstrate that, during wellbore pressurization, significant changes occur in the pore pressure field and effective stress field near the wellbore. The fluid–solid coupling effect around the wellbore returns to its initial state when the distance exceeds four times the radius away from the wellbore. As the fluid viscosity and wellbore pressurization rate decrease, the pore pressure field and effective circumferential stress (ECS) field around the wellbore become stronger. Adjusting the fluid viscosity and wellbore pressurization rate can control the effect of seepage forces on the rock skeleton during wellbore fluid injection. For the same injection conditions, rocks with q higher Young’s modulus and Poisson’s ratio exhibit stronger pore pressure fields and ECS fields near the wellbore. This model furnishes a dependable numerical framework for examining the fluid–solid coupling mechanism surrounding the open-hole wellbore in the initiation phase of hydraulic fractures.

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Effect of matrix shrinkage on wellbore stresses in coal seam gas: An example from Bowen Basin, east Australia

Cited by 14 publications

References 28 publications

History, Geology, In Situ Stress Pattern, Gas Content and Permeability of Coal Seam Gas Basins in Australia: A Review

History, Geology, In Situ Stress Pattern, Gas Content and Permeability of Coal Seam Gas Basins in Australia: A Review

The shrinkage behavior of boreholes drilled through deepwater creeping salt formations in West Africa

Research on Fluid–Solid Coupling Mechanism around Openhole Wellbore under Transient Seepage Conditions

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