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Marc R Bustin - One of the best experts on this subject based on the ideXlab platform.
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geological evaluation of halfway doig montney hybrid Gas shale tight Gas reservoir northeastern british columbia
Marine and Petroleum Geology, 2012Co-Authors: Gareth R L Chalmers, Marc R BustinAbstract:Abstract Evaluation of the reservoir quality of the Triassic Halfway–Montney–Doig hybrid Gas shale/tight Gas reservoir in the Groundbirch field in northeastern British Colombia requires an integration of unconventional and conventional methodologies. Reservoir evaluation includes reservoir thickness and structure, total porosity, TOC content, organic maturity, pore size distribution (micro- to macro-pore size fractions), surface area, mineralogy and pulse-decay permeability. Quartz (10–74%), carbonate (13–73%) and feldspar (0–42%) dominate the mineralogy of all formations with illite (0–32%) being locally important. The T max values range between 443 and 478 °C placing the reservoirs beyond the oil window. Pore size distribution by low-pressure Gas adsorption analysis identifies a large variation between the contributions from the micro-, meso- and macro-pore size fractions. Matrix permeabilities range between 1.0E-3 and 6.5E-7 mD at an effective stress between 2400 and 3300 PSI (16.5–22.8 MPa). Changes in depositional environments and diagenetic processes manifest as differences in lithology and mineralogy within the Montney and Doig reservoirs which subsequently affect the fabric, texture and pore size distribution. Fabric, texture and pore size distribution contribute to the variation in the permeability and the proportions of free to sorbed Gas within the reservoir. Quartz-rich, coarser-grained intervals (upper portions of Doig C, B and Halfway Formation) have lower surface area, greater porosities and a higher volume of macropores compared to the carbonate- and clay-rich finer-grained intervals (Doig A). Permeabilities do not vary according to lithology with higher permeabilities found within both fine-grained (Doig A) and coarser-grained (Halfway Formation) units. Permeability is controlled by pore size distribution. Higher permeability samples contain a balanced ratio between micro-, meso- and macro-porosity. The finer-grained intervals have higher sorbed Gas Capacity due to higher surface areas because of the higher volumes of finer mesopores and micropores than the coarser-grained units. However, porosity and permeability are low in some parts of the Doig A and fracture stimulation is necessary to achieve economic flow rates.
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lower cretaceous Gas shales in northeastern british columbia part ii evaluation of regional potential Gas resources
Bulletin of Canadian Petroleum Geology, 2008Co-Authors: Gareth R L Chalmers, Marc R BustinAbstract:Abstract The Lower Cretaceous Buckinghorse Formation and equivalent strata in northeastern British Columbia are investigated for potential as Gas shale reservoirs. A total of 215 cored samples were analyzed for methane sorption Capacity, moisture content and total porosity. Organic geochemistry was determined by Rock-Eval 6® analyses and a suite of samples with a variation in TOC content, mineralogy and porosity were analyzed for permeability. Total organic carbon (TOC) contents vary between 0.2 and 16.99 wt%, with an average of 2.52 wt%. Organic matter is a mixture of Type I, II and III kerogens. Moisture contents vary between 1.5 and 11 wt%, with an average of 4.6 wt%. Methane sorption capacities range between 0.03 and 1.86 cm3/g, with an average of 0.53 cm3/g at hydrostatic pressure. Porosity of the shale is between 0.7 and 16% and averages 6.5%. The total Gas Capacity is between 1.49 and 14.5 cm3/g with an average of 5.7 cm3/g at hydrostatic pressure. The highest level of thermal maturity, as defined by Rock-Eval Tmax, occurs along the deformation front where depths of burial were the greatest. Tmax values ranged between 416°C (immature) and 476°C (overmature). TOC content and reservoir pressure are the primary controls on the methane sorption Capacity of the strata. The highest methane sorption Capacity is in NTS map section 94-P of the study area near the British Columbia, Alberta and Northwest Territory borders, where TOC contents are the highest and the kerogen is dominated by types I and II. Areas with greater depths of burial (adjacent to the deformation front) have higher reservoir pressures and this increases the ability to store significant amounts of sorbed Gas even though TOC is lower than the shallower sediments. The TOC is lowest along the deformation front likely because of higher sedimentation rates and higher thermal maturities compared to the distal parts of the basin.
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characterizing the shale Gas resource potential of devonian mississippian strata in the western canada sedimentary basin application of an integrated formation evaluation
AAPG Bulletin, 2008Co-Authors: Daniel J K Ross, Marc R BustinAbstract:Devonian–Mississippian strata in the northwestern region of the Western Canada sedimentary basin (WCSB) were investigated for shale Gas potential. In the subsurface, thermally mature strata of the Besa River, Horn River, Muskwa, and Fort Simpson formations attain thicknesses of more than 1 km (0.6 mi), encompassing an area of approximately 125,000 km2 (48,300 mi2) and represent an enormous potential Gas resource. Total Gas Capacity estimates range between 60 and 600 bcf/section. Of particular exploration interest are shales and mudrocks of the Horn River Formation (including the laterally equivalent lower Besa River mudrocks), Muskwa Formation, and upper Besa River Formation, which yield total organic carbon (TOC) contents of up to 5.7 wt.%. Fort Simpson shales seldom have TOC contents above 1 wt.%. Horn River and Muskwa formations have excellent shale Gas potential in a region between longitudes 122W and 123W and latitudes 59N and 60N (National Topographic System [NTS] 94O08 to 94O15). In this area, which covers an areal extent of 6250 km2 (2404 mi2), average TOC contents are higher (3 wt.% as determined by wire-line-log calibrations), and have a stratal thickness of more than 200 m (656 ft). Gas capacities are estimated to be between 100 and 240 bcf/section and possibly greater than 400 tcf Gas in place. A substantial percentage of the Gas Capacity is free Gas caused by high reservoir temperatures and pressures. Muskwa shales have adsorbed Gas capacities ranging between 0.3 and 0.5 cm3/g (9.6–16 scf/t) at reservoir temperatures of 60–80C (140–176F), whereas Besa River mudrocks and shales have low adsorbed Gas capacities of less than 0.01 cm3/g (0.32 scf/t; Liard Basin region) because reservoir temperatures exceed 130C (266F). Potential free Gas capacities range from 1.2 to 9.5 cm3/g (38.4 to 304 scf/t) when total pore volumes (0.4–6.9%) are saturated with Gas. The mineralogy has a major influence on total Gas Capacity. Carbonate-rich samples, indicative of adjacent carbonate platform and embayment successions, commonly have lower organic carbon content and porosity and corresponding lower Gas Capacity (1% TOC and 1% porosity). Seaward of the carbonate Slave Point edge, Muskwa and lower Besa River mudrocks can be both silica and TOC rich (up to 92% quartz and 5 wt.% TOC) and most favorable for shale Gas reservoir exploration because of possible fracture enhancement of the brittle organic- and siliceous-rich facies. However, an inverse relation between silica and porosity in some regions implies that zones with the best propensity for fracture completion may not provide optimal Gas Capacity, and a balance between favorable reservoir characteristics needs to be sought.
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the organic matter distribution and methane Capacity of the lower cretaceous strata of northeastern british columbia canada
International Journal of Coal Geology, 2007Co-Authors: Gareth R L Chalmers, Marc R BustinAbstract:Abstract The methane sorption Capacity of a succession of sandstone, siltstone, shale and coal from the Lower Cretaceous Fort St John Group of Northeastern British Columbia was investigated. Average organic matter (OM) content for all formations is 2.3 wt.% with a minimum of 0.6 wt.% and maximum of 10.1 wt.%. The methane sorption Capacity ranges between 0.19 and 2.74 cm3/g at 6 MPa and at 30 °C. Total Gas Capacity (free and sorbed Gas) ranges between 2.2 and 16.6 cm3/g at 6 MPa. Micropore volumes range between 0.43 and 1.69 cm3/100 g. A positive correlation exists between the OM content, micropore volume and the methane Capacity of shales. Shales with high methane capacities have either high contents of inertodetrinite or vitrinite. Moisture content shows a positive relationship with OM content, micropore volume and methane Capacity. The negative relationship between moisture and surface area derived from N2 adsorption suggests the moisture is located within the microporosity of the OM, and also explains the positive relationship between methane Capacity and moisture. The high inertodetrinite and vitrinite contents correlate with sea-level regressions that delivered terrestrial OM from coastal plains located south of the study area into the basin.
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shale Gas potential of the lower jurassic gordondale member northeastern british columbia canada
Bulletin of Canadian Petroleum Geology, 2007Co-Authors: Daniel J K Ross, Marc R BustinAbstract:Abstract The Lower Jurassic Gordondale Member is an organic-rich mudrock and is widely considered to have potential as a shale Gas reservoir. Influences of Gordondale mudrock composition on total Gas capacities (sorbed and free Gas) have been determined to assess the shale Gas resource potential of strata in the Peace River district, northeastern British Columbia. Sorbed Gas capacities of moisture-equilibrated samples increase over a range of 0.5 to 12 weight percent total organic carbon content (TOC). Methane adsorption capacities range from 0.05 cc/g to over 2 cc/g in organic-rich zones (at 6 MPa and 30°C). Sorption capacities of mudrocks under dry conditions are greater than moisture equilibrated conditions due to water occupation of potential sorption sites. However, there is no consistent decrease of sorption Capacity with increasing moisture as the relationship is masked by both the amount of organic matter and thermal maturation level. Clays also affect total Gas capacities in as much as clay-rich mudrocks have high porosity which may be available for free Gas. Gordondale samples enriched with carbonate (calcite and dolomite) typically have lower total porosities than carbonate-poor rocks and hence have lower potential free Gas contents. On a regional reservoir scale, a large proportion of the Gordondale total Gas Capacity is free Gas storage (intergranular porosity), ranging from 0.1-22 Bcf/section (0.003-0.66 m3/section). Total Gas-in-place Capacity ranges from 1-31.4 Bcf/section (0.03-0.94 m3/section). The greatest potential for Gas production is in the south of the study area (93-P) due to higher thermal maturity, TOC enrichment, higher reservoir pressure, greater unit thickness and improved fracture-potential.
J J K Daemen - One of the best experts on this subject based on the ideXlab platform.
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Minimum operating pressure for a Gas storage salt cavern under an emergency: a case study of Jintan, China
Oil & Gas Science and Technology - Revue d'IFP Energies nouvelles, 2020Co-Authors: Tongtao Wang, Jianchao Jia, Wenquan Wang, J J K DaemenAbstract:Decreasing the Gas pressure is one of the most effective methods to increase the working Gas Capacity of salt cavern Underground Gas Storages (UGS). In this paper, KING-1 and -2 caverns of Jintan salt cavern UGS, Jiangsu province, China, are studied as an example to investigate their responses under extremely low Gas pressure. A 3D geomechanical model of the two caverns is built based on the geological features and rock properties of the host rock salt formation. Different operating conditions are simulated. Safety evaluation criteria for completion casing and caverns are proposed. Thresholds of the indicators consisting of the criteria are given to find the potential minimum Gas pressure and the safe working duration of the two caverns. Calculation results indicate that axial strain (along the vertical direction) can perfectly reflect the effects of low Gas pressure on the safety of completion casing. The indicators calculated based on the stresses have advantages compared to those based on deformation in assessing the safety of the salt cavern under such low Gas pressure and short operating time conditions. The minimum Gas pressure gradient of KING-1 and -2 caverns at the casing shoe can decrease from about 7 kPa/m to 5 kPa/m, viz., the minimum Gas pressure can decrease from 7 MPa to 5 MPa. The maximum duration for 5 MPa is no more than 118 days. Taking KING-1 cavern as an example, the working Gas volume can increase about 17.3%. Research results can provide references for Jintan salt cavern UGS coping with Gas shortages.
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determination of the maximum allowable Gas pressure for an underground Gas storage salt cavern a case study of jintan china
Journal of rock mechanics and geotechnical engineering, 2019Co-Authors: Tongtao Wang, Chunhe Yang, Jianjun Li, Gang Jing, Qingqing Zhang, J J K DaemenAbstract:Abstract Increasing the allowable Gas pressure of underground Gas storage (UGS) is one of the most effective methods to increase its working Gas Capacity. In this context, hydraulic fracturing tests are implemented on the target formation for the UGS construction of Jintan salt caverns, China, in order to obtain the minimum principal in situ stress and the fracture breakdown pressure. Based on the test results, the maximum allowable Gas pressure of the Jintan UGS salt cavern is calibrated. To determine the maximum allowable Gas pressure, KING-1 and KING-2 caverns are used as examples. A three-dimensional (3D) geomechanical model is established based on the sonar data of the two caverns with respect to the features of the target formation. New criteria for evaluating Gas penetration failure and Gas seepage are proposed. Results show that the maximum allowable Gas pressure of the Jintan UGS salt cavern can be increased from 17 MPa to 18 MPa (i.e. a gradient of about 18 kPa/m at the casing shoe depth). Based on numerical results, a field test with increasing maximum Gas pressure to 18 MPa has been carried out in KING-1 cavern. Microseismic monitoring has been conducted during the test to evaluate the safety of the rock mass around the cavern. Field monitoring data show that KING-1 cavern is safe globally when the maximum Gas pressure is increased from 17 MPa to 18 MPa. This shows that the geomechanical model and criteria proposed in this context for evaluating the maximum allowable Gas pressure are reliable.
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Determination of the maximum allowable Gas pressure for an underground Gas storage salt cavern – A case study of Jintan, China
Elsevier, 2019Co-Authors: Tongtao Wang, Chunhe Yang, Gang Jing, Qingqing Zhang, J J K DaemenAbstract:Increasing the allowable Gas pressure of underground Gas storage (UGS) is one of the most effective methods to increase its working Gas Capacity. In this context, hydraulic fracturing tests are implemented on the target formation for the UGS construction of Jintan salt caverns, China, in order to obtain the minimum principal in situ stress and the fracture breakdown pressure. Based on the test results, the maximum allowable Gas pressure of the Jintan UGS salt cavern is calibrated. To determine the maximum allowable Gas pressure, KING-1 and KING-2 caverns are used as examples. A three-dimensional (3D) geomechanical model is established based on the sonar data of the two caverns with respect to the features of the target formation. New criteria for evaluating Gas penetration failure and Gas seepage are proposed. Results show that the maximum allowable Gas pressure of the Jintan UGS salt cavern can be increased from 17 MPa to 18 MPa (i.e. a gradient of about 18 kPa/m at the casing shoe depth). Based on numerical results, a field test with increasing maximum Gas pressure to 18 MPa has been carried out in KING-1 cavern. Microseismic monitoring has been conducted during the test to evaluate the safety of the rock mass around the cavern. Field monitoring data show that KING-1 cavern is safe globally when the maximum Gas pressure is increased from 17 MPa to 18 MPa. This shows that the geomechanical model and criteria proposed in this context for evaluating the maximum allowable Gas pressure are reliable. Keywords: Underground Gas storage (UGS) salt cavern, In situ stress testing, Maximum Gas pressure, Gas penetration failure, Microseismic monitorin
Gareth R L Chalmers - One of the best experts on this subject based on the ideXlab platform.
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geological evaluation of halfway doig montney hybrid Gas shale tight Gas reservoir northeastern british columbia
Marine and Petroleum Geology, 2012Co-Authors: Gareth R L Chalmers, Marc R BustinAbstract:Abstract Evaluation of the reservoir quality of the Triassic Halfway–Montney–Doig hybrid Gas shale/tight Gas reservoir in the Groundbirch field in northeastern British Colombia requires an integration of unconventional and conventional methodologies. Reservoir evaluation includes reservoir thickness and structure, total porosity, TOC content, organic maturity, pore size distribution (micro- to macro-pore size fractions), surface area, mineralogy and pulse-decay permeability. Quartz (10–74%), carbonate (13–73%) and feldspar (0–42%) dominate the mineralogy of all formations with illite (0–32%) being locally important. The T max values range between 443 and 478 °C placing the reservoirs beyond the oil window. Pore size distribution by low-pressure Gas adsorption analysis identifies a large variation between the contributions from the micro-, meso- and macro-pore size fractions. Matrix permeabilities range between 1.0E-3 and 6.5E-7 mD at an effective stress between 2400 and 3300 PSI (16.5–22.8 MPa). Changes in depositional environments and diagenetic processes manifest as differences in lithology and mineralogy within the Montney and Doig reservoirs which subsequently affect the fabric, texture and pore size distribution. Fabric, texture and pore size distribution contribute to the variation in the permeability and the proportions of free to sorbed Gas within the reservoir. Quartz-rich, coarser-grained intervals (upper portions of Doig C, B and Halfway Formation) have lower surface area, greater porosities and a higher volume of macropores compared to the carbonate- and clay-rich finer-grained intervals (Doig A). Permeabilities do not vary according to lithology with higher permeabilities found within both fine-grained (Doig A) and coarser-grained (Halfway Formation) units. Permeability is controlled by pore size distribution. Higher permeability samples contain a balanced ratio between micro-, meso- and macro-porosity. The finer-grained intervals have higher sorbed Gas Capacity due to higher surface areas because of the higher volumes of finer mesopores and micropores than the coarser-grained units. However, porosity and permeability are low in some parts of the Doig A and fracture stimulation is necessary to achieve economic flow rates.
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lower cretaceous Gas shales in northeastern british columbia part ii evaluation of regional potential Gas resources
Bulletin of Canadian Petroleum Geology, 2008Co-Authors: Gareth R L Chalmers, Marc R BustinAbstract:Abstract The Lower Cretaceous Buckinghorse Formation and equivalent strata in northeastern British Columbia are investigated for potential as Gas shale reservoirs. A total of 215 cored samples were analyzed for methane sorption Capacity, moisture content and total porosity. Organic geochemistry was determined by Rock-Eval 6® analyses and a suite of samples with a variation in TOC content, mineralogy and porosity were analyzed for permeability. Total organic carbon (TOC) contents vary between 0.2 and 16.99 wt%, with an average of 2.52 wt%. Organic matter is a mixture of Type I, II and III kerogens. Moisture contents vary between 1.5 and 11 wt%, with an average of 4.6 wt%. Methane sorption capacities range between 0.03 and 1.86 cm3/g, with an average of 0.53 cm3/g at hydrostatic pressure. Porosity of the shale is between 0.7 and 16% and averages 6.5%. The total Gas Capacity is between 1.49 and 14.5 cm3/g with an average of 5.7 cm3/g at hydrostatic pressure. The highest level of thermal maturity, as defined by Rock-Eval Tmax, occurs along the deformation front where depths of burial were the greatest. Tmax values ranged between 416°C (immature) and 476°C (overmature). TOC content and reservoir pressure are the primary controls on the methane sorption Capacity of the strata. The highest methane sorption Capacity is in NTS map section 94-P of the study area near the British Columbia, Alberta and Northwest Territory borders, where TOC contents are the highest and the kerogen is dominated by types I and II. Areas with greater depths of burial (adjacent to the deformation front) have higher reservoir pressures and this increases the ability to store significant amounts of sorbed Gas even though TOC is lower than the shallower sediments. The TOC is lowest along the deformation front likely because of higher sedimentation rates and higher thermal maturities compared to the distal parts of the basin.
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the organic matter distribution and methane Capacity of the lower cretaceous strata of northeastern british columbia canada
International Journal of Coal Geology, 2007Co-Authors: Gareth R L Chalmers, Marc R BustinAbstract:Abstract The methane sorption Capacity of a succession of sandstone, siltstone, shale and coal from the Lower Cretaceous Fort St John Group of Northeastern British Columbia was investigated. Average organic matter (OM) content for all formations is 2.3 wt.% with a minimum of 0.6 wt.% and maximum of 10.1 wt.%. The methane sorption Capacity ranges between 0.19 and 2.74 cm3/g at 6 MPa and at 30 °C. Total Gas Capacity (free and sorbed Gas) ranges between 2.2 and 16.6 cm3/g at 6 MPa. Micropore volumes range between 0.43 and 1.69 cm3/100 g. A positive correlation exists between the OM content, micropore volume and the methane Capacity of shales. Shales with high methane capacities have either high contents of inertodetrinite or vitrinite. Moisture content shows a positive relationship with OM content, micropore volume and methane Capacity. The negative relationship between moisture and surface area derived from N2 adsorption suggests the moisture is located within the microporosity of the OM, and also explains the positive relationship between methane Capacity and moisture. The high inertodetrinite and vitrinite contents correlate with sea-level regressions that delivered terrestrial OM from coastal plains located south of the study area into the basin.
Tongtao Wang - One of the best experts on this subject based on the ideXlab platform.
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Minimum operating pressure for a Gas storage salt cavern under an emergency: a case study of Jintan, China
Oil & Gas Science and Technology - Revue d'IFP Energies nouvelles, 2020Co-Authors: Tongtao Wang, Jianchao Jia, Wenquan Wang, J J K DaemenAbstract:Decreasing the Gas pressure is one of the most effective methods to increase the working Gas Capacity of salt cavern Underground Gas Storages (UGS). In this paper, KING-1 and -2 caverns of Jintan salt cavern UGS, Jiangsu province, China, are studied as an example to investigate their responses under extremely low Gas pressure. A 3D geomechanical model of the two caverns is built based on the geological features and rock properties of the host rock salt formation. Different operating conditions are simulated. Safety evaluation criteria for completion casing and caverns are proposed. Thresholds of the indicators consisting of the criteria are given to find the potential minimum Gas pressure and the safe working duration of the two caverns. Calculation results indicate that axial strain (along the vertical direction) can perfectly reflect the effects of low Gas pressure on the safety of completion casing. The indicators calculated based on the stresses have advantages compared to those based on deformation in assessing the safety of the salt cavern under such low Gas pressure and short operating time conditions. The minimum Gas pressure gradient of KING-1 and -2 caverns at the casing shoe can decrease from about 7 kPa/m to 5 kPa/m, viz., the minimum Gas pressure can decrease from 7 MPa to 5 MPa. The maximum duration for 5 MPa is no more than 118 days. Taking KING-1 cavern as an example, the working Gas volume can increase about 17.3%. Research results can provide references for Jintan salt cavern UGS coping with Gas shortages.
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determination of the maximum allowable Gas pressure for an underground Gas storage salt cavern a case study of jintan china
Journal of rock mechanics and geotechnical engineering, 2019Co-Authors: Tongtao Wang, Chunhe Yang, Jianjun Li, Gang Jing, Qingqing Zhang, J J K DaemenAbstract:Abstract Increasing the allowable Gas pressure of underground Gas storage (UGS) is one of the most effective methods to increase its working Gas Capacity. In this context, hydraulic fracturing tests are implemented on the target formation for the UGS construction of Jintan salt caverns, China, in order to obtain the minimum principal in situ stress and the fracture breakdown pressure. Based on the test results, the maximum allowable Gas pressure of the Jintan UGS salt cavern is calibrated. To determine the maximum allowable Gas pressure, KING-1 and KING-2 caverns are used as examples. A three-dimensional (3D) geomechanical model is established based on the sonar data of the two caverns with respect to the features of the target formation. New criteria for evaluating Gas penetration failure and Gas seepage are proposed. Results show that the maximum allowable Gas pressure of the Jintan UGS salt cavern can be increased from 17 MPa to 18 MPa (i.e. a gradient of about 18 kPa/m at the casing shoe depth). Based on numerical results, a field test with increasing maximum Gas pressure to 18 MPa has been carried out in KING-1 cavern. Microseismic monitoring has been conducted during the test to evaluate the safety of the rock mass around the cavern. Field monitoring data show that KING-1 cavern is safe globally when the maximum Gas pressure is increased from 17 MPa to 18 MPa. This shows that the geomechanical model and criteria proposed in this context for evaluating the maximum allowable Gas pressure are reliable.
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Determination of the maximum allowable Gas pressure for an underground Gas storage salt cavern – A case study of Jintan, China
Elsevier, 2019Co-Authors: Tongtao Wang, Chunhe Yang, Gang Jing, Qingqing Zhang, J J K DaemenAbstract:Increasing the allowable Gas pressure of underground Gas storage (UGS) is one of the most effective methods to increase its working Gas Capacity. In this context, hydraulic fracturing tests are implemented on the target formation for the UGS construction of Jintan salt caverns, China, in order to obtain the minimum principal in situ stress and the fracture breakdown pressure. Based on the test results, the maximum allowable Gas pressure of the Jintan UGS salt cavern is calibrated. To determine the maximum allowable Gas pressure, KING-1 and KING-2 caverns are used as examples. A three-dimensional (3D) geomechanical model is established based on the sonar data of the two caverns with respect to the features of the target formation. New criteria for evaluating Gas penetration failure and Gas seepage are proposed. Results show that the maximum allowable Gas pressure of the Jintan UGS salt cavern can be increased from 17 MPa to 18 MPa (i.e. a gradient of about 18 kPa/m at the casing shoe depth). Based on numerical results, a field test with increasing maximum Gas pressure to 18 MPa has been carried out in KING-1 cavern. Microseismic monitoring has been conducted during the test to evaluate the safety of the rock mass around the cavern. Field monitoring data show that KING-1 cavern is safe globally when the maximum Gas pressure is increased from 17 MPa to 18 MPa. This shows that the geomechanical model and criteria proposed in this context for evaluating the maximum allowable Gas pressure are reliable. Keywords: Underground Gas storage (UGS) salt cavern, In situ stress testing, Maximum Gas pressure, Gas penetration failure, Microseismic monitorin
Daniel J K Ross - One of the best experts on this subject based on the ideXlab platform.
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characterizing the shale Gas resource potential of devonian mississippian strata in the western canada sedimentary basin application of an integrated formation evaluation
AAPG Bulletin, 2008Co-Authors: Daniel J K Ross, Marc R BustinAbstract:Devonian–Mississippian strata in the northwestern region of the Western Canada sedimentary basin (WCSB) were investigated for shale Gas potential. In the subsurface, thermally mature strata of the Besa River, Horn River, Muskwa, and Fort Simpson formations attain thicknesses of more than 1 km (0.6 mi), encompassing an area of approximately 125,000 km2 (48,300 mi2) and represent an enormous potential Gas resource. Total Gas Capacity estimates range between 60 and 600 bcf/section. Of particular exploration interest are shales and mudrocks of the Horn River Formation (including the laterally equivalent lower Besa River mudrocks), Muskwa Formation, and upper Besa River Formation, which yield total organic carbon (TOC) contents of up to 5.7 wt.%. Fort Simpson shales seldom have TOC contents above 1 wt.%. Horn River and Muskwa formations have excellent shale Gas potential in a region between longitudes 122W and 123W and latitudes 59N and 60N (National Topographic System [NTS] 94O08 to 94O15). In this area, which covers an areal extent of 6250 km2 (2404 mi2), average TOC contents are higher (3 wt.% as determined by wire-line-log calibrations), and have a stratal thickness of more than 200 m (656 ft). Gas capacities are estimated to be between 100 and 240 bcf/section and possibly greater than 400 tcf Gas in place. A substantial percentage of the Gas Capacity is free Gas caused by high reservoir temperatures and pressures. Muskwa shales have adsorbed Gas capacities ranging between 0.3 and 0.5 cm3/g (9.6–16 scf/t) at reservoir temperatures of 60–80C (140–176F), whereas Besa River mudrocks and shales have low adsorbed Gas capacities of less than 0.01 cm3/g (0.32 scf/t; Liard Basin region) because reservoir temperatures exceed 130C (266F). Potential free Gas capacities range from 1.2 to 9.5 cm3/g (38.4 to 304 scf/t) when total pore volumes (0.4–6.9%) are saturated with Gas. The mineralogy has a major influence on total Gas Capacity. Carbonate-rich samples, indicative of adjacent carbonate platform and embayment successions, commonly have lower organic carbon content and porosity and corresponding lower Gas Capacity (1% TOC and 1% porosity). Seaward of the carbonate Slave Point edge, Muskwa and lower Besa River mudrocks can be both silica and TOC rich (up to 92% quartz and 5 wt.% TOC) and most favorable for shale Gas reservoir exploration because of possible fracture enhancement of the brittle organic- and siliceous-rich facies. However, an inverse relation between silica and porosity in some regions implies that zones with the best propensity for fracture completion may not provide optimal Gas Capacity, and a balance between favorable reservoir characteristics needs to be sought.
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shale Gas potential of the lower jurassic gordondale member northeastern british columbia canada
Bulletin of Canadian Petroleum Geology, 2007Co-Authors: Daniel J K Ross, Marc R BustinAbstract:Abstract The Lower Jurassic Gordondale Member is an organic-rich mudrock and is widely considered to have potential as a shale Gas reservoir. Influences of Gordondale mudrock composition on total Gas capacities (sorbed and free Gas) have been determined to assess the shale Gas resource potential of strata in the Peace River district, northeastern British Columbia. Sorbed Gas capacities of moisture-equilibrated samples increase over a range of 0.5 to 12 weight percent total organic carbon content (TOC). Methane adsorption capacities range from 0.05 cc/g to over 2 cc/g in organic-rich zones (at 6 MPa and 30°C). Sorption capacities of mudrocks under dry conditions are greater than moisture equilibrated conditions due to water occupation of potential sorption sites. However, there is no consistent decrease of sorption Capacity with increasing moisture as the relationship is masked by both the amount of organic matter and thermal maturation level. Clays also affect total Gas capacities in as much as clay-rich mudrocks have high porosity which may be available for free Gas. Gordondale samples enriched with carbonate (calcite and dolomite) typically have lower total porosities than carbonate-poor rocks and hence have lower potential free Gas contents. On a regional reservoir scale, a large proportion of the Gordondale total Gas Capacity is free Gas storage (intergranular porosity), ranging from 0.1-22 Bcf/section (0.003-0.66 m3/section). Total Gas-in-place Capacity ranges from 1-31.4 Bcf/section (0.03-0.94 m3/section). The greatest potential for Gas production is in the south of the study area (93-P) due to higher thermal maturity, TOC enrichment, higher reservoir pressure, greater unit thickness and improved fracture-potential.
