Results
Liquid Nitrogen Fracturing in Boreholes under True Triaxial Stresses: Laboratory Investigation on Fractures Initiation and Morphology
Yang, Ruiyue (China University of Petroleum) | Hong, Chunyang (China University of Petroleum) | Huang, Zhongwei (China University of Petroleum) | Wen, Haitao (China University of Petroleum) | Li, Xiaojiang (Sinopec Research Institute of Petroleum Engineering) | Huang, Pengpeng (China University of Petroleum) | Liu, Wei (China University of Petroleum) | Chen, Jianxiang (China University of Petroleum)
Summary Multistage hydraulic fracturing is widely used in developing tight reservoirs. However, the economic and environmental burden of freshwater souring, transportation, treatment, and disposal in hydraulic fracturing operations has been a topic of great importance to the energy industry and public alike. Waterless fracturing is one possible method of solving these waterโrelated issues. Liquid nitrogen (LN2) is considered a promising alternate fracturing fluid that can create fractures by coupled hydraulic/thermal loadings and, more importantly, pose no threats to the environment. However, there are few laboratory experiments that use LN2 directly as a fracturing fluid. In this work, we examine the performance of LN2 fracturing based on a newly developed cryogenicโfracturing system under trueโtriaxial loadings. The breakdown pressure and fracture morphologies are compared with water fracturing. Moreover, fractureโinitiation behavior under cryogenic inโsitu conditions revealed by cryoโscanning electron microscopy (cryoโSEM) is presented, and the role of thermal stress is quantified by a coupled thermoporoelasticโdamage numerical simulation. Finally, the potential application considerations of LN2 fracturing in the field site are discussed. The results demonstrate that LN2 fracturing can lower fracture initiation and propagation pressure and generate higher conductive fractures with numerous thermally induced cracks in the vicinity of the wellbore. Thermal gradient could generate enormously highโtensile hoop stress and bring about extensive rock damage. Fractureโpropagation direction is inclined to be influenced by the thermal stress. Furthermore, phase transition during the fracturing process and low fluid viscosity of LN2 can also facilitate the fracture propagation and network generation. The key findings obtained in this work are expected to provide a viable alternative for the sustainable development of tightโreservoir resources in an efficient and environmentally acceptable way.
- North America > United States > Texas (1.00)
- Europe (0.67)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.98)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.98)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.98)
- (6 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- (9 more...)
Abstract We present the DigiCoal toolbox that is an integrated set of numerical functions written in Matlab, dedicated to analyse 3D computed tomography (CT) images of coal and reconstructing representative digital models. The design is based on a comprehensive framework: CT image pre-processing, statistics extraction, digital coal modelling and structural analysis. This paper offers an overview of the structure and techniques used in the creation of the toolbox, together with code snippets and examples.
- North America > United States (0.68)
- Oceania > Australia (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.94)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.47)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.99)
- Europe > Germany > Ruhr Basin (0.99)
- Asia > China > Shanxi > Ordos Basin (0.99)
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- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
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Abstract Low permeability formations (aquitards) and geological faults play a key role in determining the degree of isolation of groundwater resources (aquifers) from hydrocarbon reservoirs. Reliable assessment of the potential risks associated with groundwater extraction and depressurisation for coal seam gas (CSG) development necessitates accurate characterisation of aquitards and faults and incorporation in regional-scale groundwater flow models. We provide an overview of a range of approaches by which aquitards and faults may be represented in such models. A range of approaches that may be used to upscale and spatially interpolate aquitard hydraulic properties for inclusion in regional-scale groundwater flow models was examined. These methods vary in complexity and in the level of data support required. They range from simple analytical averaging approaches and flux-based methods to complex approaches based on geostatistical characterisation and facies reconstruction. Representations of geological faults and associated fracture systems in groundwater flow models include the common use of transmissibility multipliers to represent faults. For the simulation of groundwater flow in fractured porous media, three categories of methods are available, ranging in complexity from equivalent porous media approaches to discrete fracture network models. A review of regional-scale groundwater flow models developed for Australian CSG impact assessments identified that aquitard heterogeneity and geological faults are typically omitted or highly simplified. For aquitards, simplifications typically involve neglecting the spatial heterogeneity of hydraulic properties through the adoption of spatially uniform values. For geological faults and fault networks, a paucity of data currently exists with regards to both fault architecture (e.g. orientation, location, size and frequency) and flow properties of faults.
- Oceania > Australia > Queensland (0.46)
- North America > United States > California (0.46)
- Oceania > Australia > Western Australia (0.28)
- Geology > Structural Geology > Fault (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.95)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.71)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.66)
- Oceania > Australia > Queensland > Surat Basin (0.94)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.94)
- Oceania > Australia > New South Wales > Surat Basin (0.94)
- Oceania > Australia > New South Wales > Gunnedah Basin (0.94)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (3 more...)
Abstract This paper presents the results of a laboratory study on the effect of different fracture fluid systems on permeability impairment of a typical coalbed methane (CBM) reservoir. These fluid systems include conventional gel fluids (linear and cross-linked gel), gel fluid with surfactant and a viscoelastic fluid system. A series of flow tests on coal plugs were conducted under simulated reservoir conditions to assess permeability reduction due to matrix swelling and cleat plugging by gel fluids. Tests included surface behavior of different fracture fluids and surfactants on coal surface, degrees of matrix swelling and plugging of fractures and cleat systems by fracture fluids. The results of these tests have shown that permeability impairment induced by matrix swelling is highly irreversible. This irreversible damage can be prevented to a certain extent by conventional practices of adding certain types of salt (such as KCl) into fracture fluids. Both linear gel and cross-linked gel fluids cause a significant reduction (around 70%) in permeability of CBM reservoirs. Addition of KCl along with certain types of surfactants to gel fluid can marginally improve gel clean up. However, the permeability impairment could be as high as 60%. With the use of viscoelastic fluid system, on the other hand, permeability impairment can be as little as 20 to 30%. This means the viscoelastic fluid system has a great potential in reducing permeability impairment which in turn can help rapid dewatering from CBM reservoirs and increase production. Introduction To improve productivity, CBM reservoirs are routinely stimulated by hydraulic fracturing using proppant-laden gelled fluids, which usually contain polymers, surfactants, friction reducers and other chemicals. Fracturing with gelled fluids has the potential to damage reservoir (permeability reduction) by filtrate invasion (Olsen, et al., 2003). There exist, among others, two main mechanisms of formation damage due to hydraulic fracturing treatment in CBM reservoirs: permeability damage due to matrix swelling and cleat plugging. Coal formations normally contain a certain amount of clay components, such as smectite, illite, kaolinite, calcite, chlorite, etc., which can be affected by an invading incompatible filtrate of water-based fracturing fluids and may lead to coal matrix swelling, and consequently to a relatively large reduction in permeability. This type of sorption/swelling induced permeability damage is highly irreversible (Puri, et al., 1991). Coal is a dual porosity reservoir rock which has a micro porous matrix and a network of natural fractures known as cleats. Although cleats have very low porosity, they are solely responsible for the permeability of a coal seam. Therefore, coal permeability can be easily damaged due to plugging of cleats by gelled fluids. To minimize coal permeability damage due to matrix swelling, it is a general practice to add clay stabilizer which is commonly known as surfactants and salts to the base fracture fluid. KCl is a commonly used salt by the industry. The concentration of KCl, however, is formation dependent. In this study, a series of water sensitivity tests were conducted on coal samples to evaluate quantitatively how coal permeability decreases with base fracture fluid and determine optimum KCl concentration for the coal seams. To minimize coal permeability damage due to plugging of cleats by gelled fluids during hydraulic fracturing, it is possible that by adding certain surfactant to fracture fluids, the recovery of gelled fluids can be improved, therefore, dewatering and gas production can be enhanced. It is well known that surface tension and contact angle have strong effects on capillary pressure generated by fluids in porous media. In CBM reservoirs, the invaded fracture fluids offer great resistance to flow and are difficult to recover during dewatering or production. Surfactants are generally added to improve the surface properties of rocks and lower the surface tension of the fracture fluids and enhance fluid recovery in low-pressure reservoirs. In this study, a number of surfactants were investigated by evaluating their surface chemistry properties and conducting flow test on coal samples.
- Europe > Norway > Norwegian Sea (0.34)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Well Drilling > Formation Damage (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
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