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Collaborating Authors
Well Completion
Abstract Slotted liners are used extensively in the majority of steam assisted gravity drainage (SAGD) operations conducted in Western Canada due to their superior mechanical strength and integrity in contrast to other mechanical sand-control devices. These liners are required because of the generally poorly or unconsolidated nature of the majority of formations in which SAGD applications are conducted. These liners can have a variety of configurations with varying slot density, slotting patterns, slot apertures and slot internal geometries. The overall objective of a successful slotted liner design is to ensure that the liner allows the maximum production of bitumen and other fluids with a minimum pressure drop, while retaining the majority of the formation sand and preventing infill of the horizontal section of the well with solids and erosion and failure of downhole pumps and surface equipment. This paper describes a detailed lab test protocol which was successfully developed over a number years for the design and evaluation of slot geometry for SAGD applications, describes test procedures used and quantifies some of the major mechanisms discovered that lead to the plugging of slots. It has been found that in addition to grain size of the sand under consideration and slot geometry, that clay content of the formation, flow velocity, wetting phase type and pH play crucial roles in the plugging mechanism of slotted liners. Clay plugging at the top portion of the slots has been found to be the dominant damage mechanism. Introduction SAGD is being used extensively in Western Canada and other areas in the world as an effective and economic means for the recovery of heavy oil and bitumen reserves and represents the current primary technology for the exploitation of this large hydrocarbon resource(1-5).
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.89)
- Geology > Mineral > Silicate > Phyllosilicate (0.76)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
Abstract Slotted liners are used extensively in the majority of steam assisted gravity drainage operations conducted in Western Canada due to their superior mechanical strength and integrity in contrast to other mechanical sand control devices. These liners are required due to the generally poorly or unconsolidated nature of the majority of formations in which SAGD applications are conducted. These liners can have a variety of configurations with varying slot density, slotting patterns, slot apertures and slot internal geometries. The overall objective of a successful slotted liner design is to ensure that the liner allows the maximum production of bitumen and other fluids with a minimum pressure drop, while retaining the majority of the formation sand and preventing infill of the horizontal section of the well with solids and erosion and failure of downhole pumps and surface equipment. This paper describes a detailed lab test protocol which was successfully developed over a number years for the design and evaluation of slot geometry for SAGD applications, describes test procedures used and quantifies some of the major mechanisms discovered that lead to the plugging of slots. It has been found that in addition to grain size of the sand under consideration and slot geometry, that clay content of the formation, flow velocity, wetting phase type and pH play crucial roles in the plugging mechanism of slotted liners. Clay plugging at the top portion of the slots has been found to be the dominant damage mechanism. Introduction Steam assisted gravity drainage (SAGD) is being used extensively in Western Canada and other areas in the world as an effective and economic means for the recovery of heavy oil and bitumen reserves and represents the current primary technology for the exploitation of this large hydrocarbon resource. Key factors in the successful operation of a SAGD process include;Keeping the differential pressure between the lower (production) horizontal well and the upper (injection) well very low to prevent steam coning between the two spatially adjacent wellbores. This allows effective vertical propagation of the steam chamber upwards from the injector, and gravity motivated drainage of the mobilized bitumen down the sides of the steam chamber to the production well. Retaining the formation sand to prevent infill of the producing well (and injection well during periods of possible backflow) with solids which may result in wellbore plugging or mechanical issues with various types of artificial lift systems. Slotted liners have proven to be the sand control device of choice in most SAGD applications to date due to their superior mechanical integrity for long horizontal well completions. Different slotting methods have been developed over the past decade, including (Figure 1);Conventional ‘straight’ cut slots prepared using a single blade plunge into the liner. ‘Keystone’ cut slots prepared using two separate blade plunges to form a single slot, with the blade angle differing between each plunge to form a slot with an ‘aspect’ ratio that has the top of the slot smaller than the base of the slot to aid in the passage of any sand grains/fines that may enter the slot
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (0.77)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
Abstract Previous studies described the theory and application of CO2 miscible hydrocarbon fracturing fluids for gas well stimulation. These fluids are ideally suited to gas reservoirs susceptible to phase trapping resulting from high capillary pressures when water-based fluids are used. Gas reservoirs particularly prone to phase trapping are those with in situ permeability less than 0.1 mD, those with initial water saturations less than what would be expected from normal capillary equilibrium (subnormally water saturated) and those that are under pressured. Such reservoirs represent a growing proportion of the market. This, combined with increased gas prices, creates a strong need for an optimized gas well fracturing fluid system. Hydrocarbon-based fracturing fluids present an ideal solution to phase trapping concerns associated with water-based fluids provided the hydrocarbon fluid can be effectively and quickly removed from the formation after the fracturing treatment. This paper investigates in more depth what constitutes an ideal hydrocarbon-base oil for this application. This involves consideration of many factors including cleanup mechanisms, safety, cost and capability to be gelled and broken. In order to meaningfully evaluate fluid clean up, regained core permeability evaluations must be conducted by accurately duplicating downhole conditions. This paper presents testing methodologies designed to achieve this goal. To illustrate the need for these methodologies, the applicable phase behaviour and fluid displacement mechanisms by which these fluid systems operate are discussed. Topics covered will include:Methane drive fluid recovery mechanism involving the use of CO2 with hydrocarbons and resulting effect on interfacial tension (IFT). Secondary recovery mechanism based on vapour pressure of light hydrocarbons resulting in their being produced back in the gas phase with methane. Application of these concepts to address phase trapping in low-permeability gas reservoirs and how these effects are accentuated in formations that may be subnormally water-saturated, have low reservoir pressure or have low permeability. The need to simulate downhole conditions accurately to properly represent the recovery mechanisms. This includes duplication of temperature, pressure and fluid-loss mechanisms. Duplicating leakoff is the key to representative duplication of phenomena at the fracture face. Compare nitrogen to methane for reference and fluid recoveries and discuss why it is necessary to use methane to obtain proper simulation and modelling of the actual field performance of the fracture fluids. To illustrate fluid performance and demonstrate test methodologies, results of a regain permeability evaluation conducted with the optimum fluid and test methodologies discussed will be presented. It will be shown that in a formation known to be highly sensitive to water-based fluid retention (phase trapping), 100% regain permeability can be achieved at a minimal 140 kPa of applied drawdown pressure. Introduction The use of water-based fracturing fluids in low-permeability reservoirs may result in the loss of effective fracturing half length due to phase trapping effects associated with the retention of a large portion of the introduced water-based fluid in the formation.
- North America > United States > Texas (0.47)
- North America > Canada > Alberta (0.30)
- South America > Brazil > Brazil > South Atlantic Ocean (0.89)
- North America > United States (0.89)
- Asia > Pakistan (0.89)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract Previous publications described the theory and application of CO2 miscible hydrocarbon fracturing fluids to gas well stimulation. The fluids are ideally suited to gas reservoirs susceptible to phase trapping due to high capillary pressures when waterbased fluids are used. Reservoirs particularly prone to phase trapping are those with low permeability (less than 0.1 md), those that are subnormally water-saturated, and those that are under pressured. In order to conduct meaningful rheological evaluations for etermination of fluid properties and required chemical concentrations, it is essential that downhole conditions be accurately duplicated. The most fundamental requirement is that the gelled hydrocarbon and liquid CO2 be combined and homogenized below the critical temperature of CO2 (31 °C) and at a pressure above the bubble point of the resulting fluid mixture to ensure one miscible phase. This normally requires a minimum initial pressure f at least 20 MPa. Temperature is increased to the bottomhole static temperature of the well under consideration as the test progresses. This requires that the rheometer have a pressure rating high enough to withstand the increased pressure caused by expansion. This paper presents several different testing methodologies designed to provide representative rheology vs. time with all chemicals present, and to provide varying insights into fluid behaviour. The first utilizes a conventional bob and sleeve configuration in a heated pressure chamber rated to 102 MPa and 204 °C(5). This allows one to gather shear stress vs. shear rate data as a function of time. Normal Power Law n' and k' parameters are calculated and are in turn used to calculate apparent viscosity vs. time. Secondary mixing is provided by a helical fin attached to the outside of the sleeve, which creates a rotational flow pattern in the rheometer. The second methodology utilizes a capillary tube viscometer allowing for precise and accurate control of the shear rate. The capillary tubes used are capable of 68 MPa at 204 °C and are sized according to the expected viscosity range and range of desired shear rates. The fluid of interest is displaced through the tube using a push-pull system of two positive displacement syringe (Ruska) pumps?one in injection and one in extraction mode to keep the system pressure at the desired level. Varying the injection rate allows one to vary the shear rate as desired. Shear stress vs. shear rate data are collected as a function of time, again allowing normal power law parameters as well as apparent viscosity to be calculated. The third methodology uses an oscillating (sinusoidal) strain. The resulting stress has an elastic component and a viscous component. G' is the elastic component and can be thought of like a spring constant. A Newtonian liquid has no storage modulus (G'). Elastic behaviour is important for suspending proppant at low shear rates. This methodology therefore provides insights into fluid behaviour that complement those obtained using shear stress vs. shear rate measurements.
- North America > Canada > Alberta (0.30)
- North America > United States > Texas (0.29)
Design and Performance of a Water Disposal Well Stimulation Treatment in a High Porosity and Permeability Sand
Harding, T.G. (University of Calgary) | Varner, J. (Nexen Petroleum International Ltd.) | Flexhaug, L.A. (Nexen Petroleum International Ltd.) | Bennion, D.B. (Hycal Energy Research Laboratories)
Abstract Injectivity problems associated with produced water disposal have been ongoing in the Masila project in Yemen. Disposal wells experience an immediate low injectivity upon commencement of injection as compared to the productivity measured during pumping clean-up of the wells. It has been hypothesized that this behaviour, referred to as the check-valve effect, is caused mainly by mobile formation fines in the near-well vicinity. Injectivity often declines further because of plugging by impurities in the disposal water. Laboratory and field work have been done to test several methods of improving water disposal well performance, including the application of horizontal wells and proppant fracture stimulation of vertical wells. Another technique tried in the field was a stimulation treatment involving HCl/HF acid followed by a thin-film polymer. The intent of the treatment was to destroy potentially mobile formation fines in the near wellbore area and then to stabilize those that remained in an attempt to reduce the check-valve effect. The acid and polymer treatment was developed through laboratory core testing and was employed on a newly drilled water disposal well. The procedures and results of the laboratory work are described along with the design and implementation of the stimulation treatment. The injection performance of the well is examined relative to other disposal wells in the field. Initial results of the stimulation treatment were disappointing but the well has improved over time to become a moderately good injector. However, the results of the test have not provided enough encouragement to date to warrant further work in the field. Introduction The disposal of produced water in the Masila project in the Republic of Yemen has been the subject of a number of earlier papers. Field water production has been rising steadily in recent years due to the strong aquifer support in the Upper Qishn reservoir section. These reservoirs are high porosity and permeability and exhibit superior production characteristics. Current oil and water production levels are 36,566 and 198,728 m/d, respectively. All of the produced water is disposed of through reinjection into the producing formations. Injectivity problems continue due to the nature of the formations and the quality of the disposal water. Details of the injectivity problems and investigations as to their causes have been discussed previously. The performance of four horizontal disposal wells and the results of four proppant fracture stimulated vertical disposal wells have been presented. In addition, a stud has been published of continuous high-pressure injection above formation parting pressure as an aid to injectivity. Laboratory and field trials have indicated that injectivity problems are caused by a combination of native reservoir fines migration, formation plugging by injected solids and oil, and the formation of calcite scale downhole. Several authors have discussed such injectivity problems and their causes in some detail. In addition to the use of horizontal wells and proppant fractured stimulated vertical wells, a field trial was conducted of an acid stimulation technique designed in the laboratory.
- Asia > Middle East > Yemen (0.55)
- North America > Canada (0.47)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Abstract Previous publications described the theory and application of CO2 miscible hydrocarbon fracturing fluids to gas well stimulation. The fluids are ideally suited to gas reservoirs susceptible to phase trapping due to high capillary pressures when water-based fluids are used. Reservoirs particularly prone to phase trapping are those with low permeability, less than 0.1 md, those that are subnormally water-saturated, and those that are under pressured. In order to conduct meaningful rheological evaluations for determination of fluid properties and required chemical concentrations, it is essential that downhole conditions beaccurately duplicated. The most fundamental requirement is that the gelled hydrocarbon and liquid CO2 be combined and homogenized below the critical temperature of CO2 (31 °C) and at a pressure above the bubble point of the resulting fluid mixture to ensure one miscible phase. This normally requires a minimum initial pressure of at least 20 MPa. Temperature is increased to the bottomhole static temperature of the well under consideration as the test progresses. This requires that the rheometer have a pressure rating high enough to withstand the increased pressure caused by expansion. This paper presents several different testing methodologies designed to provide representative rheology vs. time with all chemicals present, and to provide varying insights into fluid behaviour. The first utilizes a conventional bob and sleeve configuration in a heated pressure chamber rated to 102 MPa and 204 °C. This allows one to gather shear stress vs. shearrate data as a function of time. Normal power law n' and k' parameters are calculated and are in turn used to calculateapparent viscosity vs. time. Secondary mixing is provided by a helical fin attached to the outside of the sleeve, which creates a rotational flow pattern in the rheometer. The second methodology utilizes a capillary tube viscometer allowing for precise and accurate control of the shear rate. Thecapillary tubes used are capable of 68 MPa at 204 °C and are ized according to the expected viscosity range and range of desired shear rates. The fluid of interest is displaced throughthe tube using a push-pull system of two positive displacement syringe (Ruska) pumps, one in injection and one in extraction mode to keep the system pressure at the desired level. Varying the injection rate allows one to vary the shear rate as desired. Shear stress vs. shear rate data are collected as a function of time again allowing normal power law parameters as well as apparent viscosity to be calculated. The third methodology uses an oscillating (sinusoidal) strain. The resulting stress has an elastic component and a viscous component. G' is the elastic component and can bethought of like a spring constant. A Newtonian liquid has no storage modulus (G'). Elastic behaviour is important for suspending proppant at low shear rates. This methodology therefore provides insights into fluid behaviour that complement those obtained using shear stress vs. shear rate measurements. Introduction Unconventional gas reservoirs including tight gas, shale gas, and coalbed methane are becoming critically important components of current and future gas supply.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
Abstract Previous studies described the theory and application of CO2 miscible hydrocarbon fracturing fluids for gas well stimulation. These fluids are ideally suited to gas reservoirssusceptible to phase trapping resulting from high capillary pressures when water-based fluids are used. Gas reservoirs particularly prone to phase trapping are those with in situ permeability less than 0.1 md, those with initial water saturations less than what would be expected from normal capillary equilibrium (subnormally water saturated), and those that are under pressured. Such reservoirs represent a growing proportion of themarket. This, combined with increased gas prices creates a strong need for an optimized gas well fracturing fluid system. Hydrocarbon-based fracturing fluids present an ideal solution to phase trapping concerns associated with waterbased fluids provided the hydrocarbon fluid can be effectively and quickly removed from the formation after the fracturing treatment. This paper investigates in more depth what constitutes anideal hydrocarbon-base oil for this application. This involves consideration of many factors including cleanup mechanisms, safety, cost, and capability to be gelled and broken. In order to meaningfully evaluate fluid clean up, regainedcore permeability evaluations must be conducted by accurately duplicating downhole conditions. This paper presents testing methodologies designed to achieve this goal. To illustrate the need for these methodologies, theapplicable phase behavior and fluid displacement mechanisms by which these fluid systems operate are discussed. Topics covered will include:Methane drive fluid recovery mechanis minvolving use of CO2 with hydrocarbons and resulting effect on interfacial tension (IFT). Secondary recovery mechanism based on vapour pressure of light hydrocarbons resulting in their being produced back in the gas phase withmethane. Application of these concepts to address phase trapping in low-permeability gas reservoirs and how these effects are accentuated in formations that may be subnormally water-saturated, havelow reservoir pressure, or have low permeability. The need to simulate downhole conditionsaccurately to properly represent the recovery mechanisms. This includes duplication of temperature, pressure, and fluid-loss mechanisms. Duplicating leakoff is the key to representative duplication of phenomena at the fracture face. Compare nitrogen to methane for reference and fluid recoveries and discuss why it is necessary to use methane to obtain proper simulation and modeling of the actual field performance of the fracture fluids. To illustrate fluid performance and demonstrate test methodologies, results of a regain permeability evaluation conducted with the optimum fluid and test methodologies discussed will be presented. It will be shown that in a formation known to be highly sensitive to water-based fluid retention (phase trapping), 100% regain permeability can be achieved at a minimal 140 kPa of applied drawdown pressure. Introduction The use of water-based fracturing fluids in low-permeability reservoirs may result in loss of effective fracturing half length due to phase trapping effects associated with the retention of a large portion of the introduced water-based fluid in the formation. This problem is increased by the water-wet nature of most tight gas reservoirs (where no initial liquid hydrocarbon saturation is, or ever has been, present) due to the strong spreading coefficient of water in such a situation
- North America > United States (0.94)
- North America > Canada > Alberta (0.29)
- Geology > Geological Subdiscipline > Geomechanics (0.47)
- Geology > Mineral > Silicate > Phyllosilicate (0.30)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Design and Performance of a Water Disposal Well Stimulation Treatment in a High Porosity and Permeability Sand
Harding, T.G. (Nexen Petroleum International Ltd.) | Varner, J. (Nexen Petroleum International Ltd.) | Flexhaug, L.A. (Nexen Petroleum International Ltd.) | Bennion, D.B. (Hycal Energy Research Laboratories)
Abstract Injectivity problems associated with produced water disposal have been on going in the Masila project in Yemen. Disposal wells experience an immediate low injectivity upon commencement of injection as compared to the productivity measured during pumping clean up of the wells. It has been hypothesized that this behaviour, referred to as the check-valve effect, is caused mainly by mobile formation fines in the near-well vicinity. Injectivity often declines further because of plugging by impurities in the disposal water. Laboratory and field work has been done to test several methods of improving water disposal well performance including the application of horizontal wells and proppant fracture stimulation of vertical wells. Another technique tried in the field was a stimulation treatment involving HCl/HF acid followed by a thin-film polymer. The intent of the treatment was to destroy potentially mobile formation fines in the near wellbore area and then to stabilize those that remained in an attempt to reduce the check-valve effect. The acid and polymer treatment was developed through laboratory core testing and was employed on a newly drilled water disposal well. The procedures and results of the laboratory work are described along with the design and implementation of the stimulation treatment. The injection performance of the well is examined relative to other disposal wells in the field. Initial results of the stimulation treatment were disappointing but the well has improved over time to become a moderately good injector. However, the results of the test have not provided enough encouragement to date to warrant further work in the field. Introduction The disposal of produced water in the Masila project in the Republic of Yemen has been the subject of a number of earlier papers. Field water production has been rising steadily in recent years due to the strong aquifer support in the Upper Qishn reservoir section. These reservoirs are high porosity and permeability and exhibit superior production characteristics. Current oil and water production levels are 230,000 BOPD and 1,250,000 BWPD, respectively. All of the produced water is disposed of through reinjection into the producing formations. Injectivity problems continue due to the nature of the formations and the quality of the disposal water. Details of the injectivity problems and investigations as to their causes have been discussed previously. The performance of four horizontal disposal wells and the results of four proppant fracture stimulated vertical disposal wells have been presented. In addition, a study has been published of continuous high-pressure injection above formation parting pressure as an aid to injectivity. Laboratory and field trials have indicated that injectivity problems are caused by a combination of native reservoir fines migration, formation plugging by injected solids and oil, and the formation of calcite scale downhole. Several authors have discussed such injectivity problems and their causes in some detail. In addition to the use of horizontal wells and proppant fractured stimulated vertical wells, a field trial was conducted of an acid stimulation technique designed in the laboratory. This technique was intended to first destroy reservoir fines in the near wellbore area and then to stabilize those that remained.
- Asia > Middle East > Yemen (0.55)
- North America (0.46)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Abstract Gravel packs are commonly used to minimize sand production in unconsolidated sandstone reservoirs. The migration of particulates and fines into the gravel packs often has a severely reducing effect on the permeability of the packs and the subsequent productivity of the well. Detailed laboratory studies were undertaken using 12/20 and 20/40 mesh silica gravel to ascertain the optimum gravel size to minimize formation damage to gravel packs in the Battrum field. The Battrum field is a shallow unconsolidated sandstone reservoir located in Saskatchewan, Canada, producing a low API gravity crude oil over an area of approximately 3900 hectares with 180 active injection and production wells. Currently a large portion of the field is under enhanced recovery using a commercial scale in-situ combustion technique. The results of detailed laboratory studies, including detailed size and sieve analysis of the formation, classification of the different lithologies and detailed laboratory tests to investigate at reservoir conditions the flow of gravel and fines into different sizes of gravel packs are documented. Tests include detailed petrography and computerized petrographic image analysis on actual sections of gravel and formation sand interfaces and illustrate the mechanism of fines entrainment in the gravel packs and provide associated permeability reduction data. Details of field gravel pack treatments are also provided in the paper. Test results indicated an increased propensity for gravel pack plugging in the coarser (12/20) mesh gravel in comparison to the 20/40 mesh gravel. Simultaneous multiphase flow of both oil and water was also found to have an increasing effect on rapidity and severity of apparent plugging. The results presented provide insight into optimum gravel to sand sizing ratios for this field and have potential application to other similar reservoirs. THE BATTRUM FIELD The Battrum field was discovered by Mobil Oil Canada (MOCAN) in 1955 and is located in southeast Saskatchewan, Canada (Figure 1). Mobil currently operates units 1, 2 and 3 of the field. The majority of the reserves in the reservoir are produced from four district stratigraphic layers from sandstone fades of the Jurassic Roseray Formation. The four layers in the Roseray formation at Battrum define an off lapping parasequence set and have been numbered according to depositional sequence as R1, R2, R3 and R4. These layers were deposited in response to a west to east progradation of a wave dominated clastic shoreline. The layers are defined by marine flooding surfaces which document periods of relative sea level rise. The architecture of the Roseray units is determined by this origin and two episodes of post depositional erosion. Sedimentary structures indicate that the majority of the Roseray reservoir facies were deposited in a mechanical fashion by wave and/or wind generated currents. Layers R1 and R2 are the major producing units in the western portion of the field while layers P3 and R4 contain the majority of the reserves in the eastern section. The reservoir sands are, in general, very fine to fine grained, moderately to well sorted and poorly consolidated. Reservoir quality is very much controlled by grain size with layer R2 containing the largest amount of high quality sand. Over 42% of the 39.2 × 10+6 m3 (247 million barrels) of moveable oil in place is present in this layer. In general the better quality laminated Roseray sands (which were the subject of this study) represent moderately sorted quartzose sublitharentites with good modified primary intergranular porosity supplemented by occasional grain moldic porosity. The sandstone framework generally consists of subangular monocrystalline quartz grains with much lesser amounts of chert grains, rock fragments and detrital feldspars. There are only trace amounts of authigenic quartz cement and generally no carbonate cements. Detrital, recrystallized and authigenic clays characterize the rock. Kaolinite clay dominates (about 4% of the bulk rock fraction) with lesser amounts of illite (2%) and smectite (1%). Quartz is the major residual constituent with trace amounts of potassic feldspar and pyrite. The high kaolinite concentration and trace smectite indicate that the Battrum matrix is potentially sensitive to fines and sand mobilization and some potential for clay swelling and sloughing. P. 181^
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Well Completion > Sand Control > Gravel pack design & evaluation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)