Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Well Drilling
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 A number of factors must be considered in the design of miscible displacement processes. This paper discusses a new approach that relates primarily to the laboratory and modelling studies that precede the EOS-based compositional simulation of reservoir performance during the vapourizing/condensing gas drive process. The phase behaviour of a solvent/oil system and determination of miscibility conditions by various special PVT experiments (including the swelling test, RBA, slim tube test, and the continuous multiple-contact experiment) are reviewed along with their importance in building an accurate EOS model to be used in compositional simulation. In addition to experimental PVT data, a special core flow test design for measuring the relative permeabilities to generated fluids by forward/reverse multiple contact experiments is discussed. Based on laboratory PVT and SCAL data, a novel interfacial tension-dependent model of relative permeability and capillary pressure data is presented along with the advantages if incorporated into commercial EOS-based compositional simulation software packages. Introduction Mass transfer between the gas and oil components dominates the displacement characteristics of miscible or near-miscible floods. The overall displacement efficiency of any oil recovery displacement process can be considered conveniently as the product of microscopic and macroscopic displacement efficiencies. In equation form: where E = overall displacement efficiency, ED = microscopic displacement efficiency, and EV = macroscopic (volumetric) displacement efficiency. Microscopic displacement relates to the displacement or mobilization of oil at pore scale. That is, ED is a measure of effectiveness of the displacing fluid in moving (mobilizing) the oil at those places in the rock where the displacing fluid contacts the oil. ED is reflected in the magnitude of the residual oil saturation, Sor, in the regions contacted by the displacing fluid. Macroscopic displacement efficiency relates to the effectiveness of the displacing fluid(s) in contacting the reservoir in a volumetric sense. EV is a measure of how effectively the displacing fluid sweeps out the volume of a reservoir, both areally and vertically, as well as how effectively the displacing fluid moves the displaced oil toward production wells. It is desirable in an Enhanced Oil Recovery (EOR) process that the values of ED and Ev, and consequently E, approach 1. An idealized EOR process would be one in which the displacing fluid removed all oil from the pores contacted by the fluid (Sor →0). Several physical/chemical interactions occur between the displacing fluid and the oil that can lead to efficient microscopic displacement (low Sor). These include miscibility between the fluids, decreasing the interfacial tension (IFT) between the fluids, oil volume expansion, and reducing oil viscosity. The maintenance of a favourable mobility ratio between displaced and displacing fluids also contributes to better microscopic displacement efficiency. EOR processes are thus developed with consideration of these factors. The goal of an acceptable EOR fluid is to maintain favourable interaction(s) as long as possible during the flooding process. In enhanced recovery operations, oil entrapment occurs due to complex interactions between viscous, gravity, and capillary forces.
- Europe (0.46)
- North America > Canada (0.29)
Water and Oil Base Fluid Retention in Low Permeability Porous Media - an Update
Bennion, D.B. (Hycal Energy Research Laboratories Ltd.) | Thomas, F.B. (Hycal Energy Research Laboratories Ltd.) | Schulmeister, B. (Hycal Energy Research Laboratories Ltd.) | Romanova, U.G. (Hycal Energy Research Laboratories Ltd.)
Abstract Phase trapping refers to the temporary or permanent trapping of oil or water based fluids introduced into a porous media during drilling or completion operations which result in a reduction in the effective permeability to the desired producing or injected phase. This problem has emerged in recent years as a major mechanism of formation damage, most notably in low permeability gas producing formations. This paper reviews the current state of the art with respect to new technology which is being used to identify formations that are particularly susceptible to this mode of formation damage, as well as describing some of the most current technology being used to avoid and remove these problems. This includes the use of various types of new non-alcohol based surface tension reducing agents, foamed fluids and other surfactants, transient wettability modifying agents, oil based fluids, as well as CO2 or nitrogen based fracturing technology. The potential advantages of some of these new technologies and where they have the greatest degree of potential application are discussed. Background Phase trapping is a common mechanism of formation damage that can occur in a variety of oil, gas or water bearing formations and can create severe reductions in productivity or injectivity. The problem has been documented in numerous publications in the literature as well as in previous publications by the authors . The basic mechanism of a phase trap refers to either the transient (sometimes referred to as a ‘phase load’) or permanent (phase trap or block) retention of water, oil or sometimes gas based fluids which are generally introduced from an outside source into the formation during drilling and completion operations. There are also situations, such as retrograde condensate gas reservoirs or the depletion of black oil reservoirs, where the creation of potentially permeability reducing near wellbore phase traps may occur through the normal depletion process of the reservoir. Common Types of Phase Traps The most common types of phase traps can be summarized as follows; Gas Producing Formations –Water based phase trapping (caused by water based drilling, completion or kill fluids) –ydrocarbon based phase trapping (caused by hydrocarbon based drilling, completion or kill fluids) or by retrograde condensate liquid dropout in rich gas producing situations Oil Producing Formations –Water based phase trapping (caused by water based drilling, completion or kill fluids) –Gas based phase trapping (caused by gas liberation by sub-bubblepoint production) Water Producing Formations –Hydrocarbon based phase trapping (caused by hydrocarbon based drilling, completion or kill fluids) –Gas based phase trapping (caused by free gas injection) Gas Injection Wells –Water based phase trapping (water of condensation) –Oil based phase trapping (compressor lubricant carryover) Phase trapping is caused by an interaction of capillary pressure and relative permeability phenomena in porous media. A simplified formulation of the capillary pressure equation in porous media can be expressed as; (Equations (1))(Available in full paper)
- North America > Canada > Alberta (0.30)
- North America > United States > Louisiana (0.28)
- North America > United States > West Virginia (0.28)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Tennessee > Appalachian Basin (0.99)
- (7 more...)
Abstract Early exploration well tests in the Colville River Field (also known as Alpine) drilled with water-based mud systems exhibited unexplainably high near wellbore residual skin damage as documented by pressure build-up testing. Typical formation damage echanisms including clay reactions, mechanical damage, and gas trapping could not explain the damage. Between March 1998 and July 2001, laboratory testing determined imbibition-induced water trapping to be the primary formation damage mechanism. In situ water saturation is significantly lower than the residual or connate water saturation, a condition rarely encountered in the field. Lab tests quantified impacts and identified methods to minimize or eliminate formationdamage. This paper documents how successful identification of a unique damage mechanism improved drilling results in a low permeability sandstone. Introduction Exploration drilling results in Colville River prospects consistently demonstrated higher than expected near wellbore skin damage as measured by build-up test analysis. Investigations into more common damage mechanisms such as solids migration and clay swelling could not explain the damage. Early reservoir core studies indicated that residual water saturations from relative permeability curves should be higher than the observed initial water saturations. Later studies with traced core confirmed initial water saturations were considerably less than normal connate water saturations. Further lab work confirmed the water-blocking tendency by measuring water imbibition and permeability recovery during regain permeability tests. Various drilling fluids were tested, with oil-muds consistently delivering lower permeability losses than water-based fluids. For a number of operational reasons, all wells on the first development pad (CD1) were drilled with brine-based fluids. The second pad (CD2) development team accepted the lab results and, after demonstrating the potential benefits of oil-based mud drilling, convinced the drilling team to develop and test a suitable mud program. Initial test results confirmed the lab results and conclusions when Well CD2–47 came in flowing at 300% more than predicted, based on equivalent brine-based mud completions in comparable pay to date. Following this early success, the oil-mud program was expanded and has consistently delivered more productive wells in line with expectations from the lab work. Background The Colville River Field (also known as the Alpine Field) is located approximately 100 km due west of the Prudhoe Bay Field on the north slope of Alaska (see Figure 1). It contains 70 × 10 m of recoverable reserves, with approximately 160 x?10 m of oil-inplace. Production is from the Alpine Oil Pool, a very fine-grained Jurassic age shallow marine sandstone complex with stratigraphically trapped 40 °API oil. The reservoir is normally pressured and undersaturated. Initial reservoir pressure is approximately 5,500 kPa above the bubble point, and the primary recovery mechanism is solution drive. Figure 2 presents a log and petrophysical overview, and Table 1 provides a summary of key reservoir properties. The field was discovered in 1994 with the drilling of the Bergschrund No. 1. Further delineation confirmed the prospect during subsequent winter seasons, and gravel pad construction began during the 1998 winter season.
- Europe > United Kingdom > Irish Sea > East Irish Sea > Liverpool Bay (0.81)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.54)
- Geology > Mineral > Silicate > Phyllosilicate (0.89)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.56)
- North America > United States > Alaska > North Slope Basin > Western North Slope > Colville River Field > Kingak Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- North America > United States > Alaska > North Slope Basin > Western North Slope > Colville River Field > Alpine Field > Kingak Formation (0.98)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (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)
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 Reservoirs can sometimes be very sensitive to drilling fluids. Typically, the lower the permeability of the rock, the greater the likelihood of experiencing phase interference effects, and as the average diameter of the porous features decreases, the greater the capillary pressure. Often this phase interference effect significantly reduces well productivity and, hence, alternative drilling fluids are used. Moreover, aqueous phase fluids can react with the reservoir rock causing clay swelling, clay flocculation, and fines migration. In an attempt to mitigate the above mentioned deleterious phenomena, alternative, non-aqueous drilling muds are sometimes used. These are designed to be compatible with the reservoir fluids in situ and, because they are hydrocarbon-based, they do not interact with the rock matrix. One of the drawbacks, however, is the mixing that occurs with the oil in situ. When earlytime samples are taken, the oil is contaminated with the drilling fluid. This is a near-wellbore and early-time problem that is selfcorrecting as more fluids are produced from the well. However, for small volume samples (typically bottom hole samples), contamination can seriously distort the properties measured for the sample. The small-volume samples are often very expensive to procure and many of the reservoir development decisions are based on the properties of these small samples. Therefore, these properties need to be accurately measured. How can the contamination be quantified both in terms of mass or mole per cent in the fluid and its impact on the sample properties? This paper describes two technologies developed to achieve this. The first is applicable to synthetic hydrocarbon drilling fluids where the concentration of components is restricted to very few components. The second technique applies to those fluids that contain a more broad distribution of hydrocarbon components. The results indicate that the resolution of contamination can be achieved to within 1 mass% accuracy. Using the degree of contamination with Equation of State methods, the properties of the actual uncontaminated reservoir fluid can be predicted. Objective The objective of this work is to develop a technique that will quantify how much contamination is present in the sampled oil and then provide a means by which PVT parameters for reservoir fluid can be approximated from a contaminated sample. The basis for this work is having no "clean" oil available and therefore the uncontaminated properties must be extrapolated from the available samples. The scope of the work consists of:Mathematical development; Additional experimental data on selected samples; Validation of mathematical approach; and, Estimation of the oil-based mud filtrate contamination on selected samples and test cases. Methodology Depending on the type of drilling fluid, the determination of the amount of contamination can be straightforward or it may be somewhat more involved. From the authors' experience, drilling fluids whose compositional distribution is very narrow are the easiest to correct. This type will be discussed in the first section of this paper. Those drilling fluids that possess a much broader distribution of components are more difficult to quantify.
- North America (0.46)
- Europe (0.46)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract A number of factors must be considered in the design of miscible displacement processes. This paper discusses a new approach that relates primarily to the laboratory and modeling studies that precede the EOS based compositional simulation of reservoir performance during the vaporizing/condensing gas drive process. The phase behavior of a solvent/oil system and determination of miscibility conditions by various special PVT experiments including swelling test, RBA, slim tube test and continuous multiple-contact experiment are reviewed along with their importance in building an accurate EOS model to be used in compositional simulation. In addition to experimental PVT data, a special core flow test design for measuring the relative permeabilities to generated fluids by forward/reverse multiple contact experiments is discussed. Based on laboratory PVT and SCAL data, a novel interfacial tension-dependent model of relative permeability and capillary pressure data is presented along with the advantages if incorporated in the commercial EOS based compositional simulation software packages. Introduction Mass transfer between the gas and oil components dominates the displacement characteristics of miscible or near-miscible floods. The overall displacement efficiency on any oil recovery displacement process can be considered conveniently as the product of microscopic and macroscopic displacement efficiencies. In equation form, Equation(1) (Available in full paper) where E = overall displacement efficiency, ED = microscopic displacement efficiency, and EV = macroscopic (volumetric) displacement efficiency. Microscopic displacement relates to the displacement or mobilization of oil at pore scale. That is, ED is a measure of effectiveness of the displacing fluid in moving (mobilizing) the oil at those places in the rock where the displacing fluid contacts the oil. ED is reflected in magnitude of the residual oil saturation, Sor, in the regions contacted by the displacing fluid. Macroscopic displacement efficiency relates to the effectiveness of the displacing fluid(s) in contacting the reservoir in a volumetric sense. EV is a measure of how effectively the displacing fluid sweeps out the volume of a reservoir, both areally and vertically, as well as how effectively the displacing fluid moves the displaced oil toward production wells. It is desirable in an EOR process that the values of ED and EV and consequently E, approach 1. An idealized EOR process would be one in which the displacing fluid removed all oil from the pores contacted by the fluid (Sor ?0). Several physical/chemical interactions occur between the displacing fluid and the oil that can lead to efficient microscopic displacement (low Sor). These include miscibility between the fluids, decreasing the IFT between the fluids, oil volume expansion, and reducing oil viscosity. The maintenance of a favorable mobility ratio between displaced and displacing fluids also contributes to better microscopic displacement efficiency. EOR processes are thus developed with consideration of these factors. The goal with an acceptable EOR fluid is to maintain the favorable interaction(s) as long as possible during the flooding process. In enhanced recovery operations, oil entrapment occurs due to complex interactions between viscous, gravity and capillary forces.
Abstract Early exploration well tests in the Colville River Field (also known as Alpine) drilled with water-based mud systems exhibited unexplainably high near-wellbore residual skin damage documented by pressure build-up testing. Typical formation damage mechanisms including clay reactions, mechanical damage, and gas trapping could not explain the damage. Between March 1998 and July 2001, laboratory testing determined imbibition-induced water trapping to be the primary formation damage mechanism. Insitu water saturation is significantly lower than the residual or connate water saturation, a condition rarely encountered in the field. Lab tests quantified impacts and identified methods to minimize or eliminate formation damage. This paper documents how successful identification of a unique damage mechanism improved drilling results in a low permeability sandstone. Introduction Exploration drilling results in Colville River prospects consistently demonstrated higher than expected near wellbore skin damage when measured by build-up test analysis. Investigations into more common damage mechanisms such as solids migration and clay swelling could not explain the damage. Early reservoir core studies indicated residual water saturations from relative permeability curves should be higher than observed initial water saturations. Later studies with traced core fluids confirmed initial water saturations were considerably less than natural connate water saturations. Further lab work confirmed the water-blocking tendency by measuring water imbibition and permeability recovery during regain permeability tests. Various drilling fluids were tested, with oil muds consistently delivering higher regained permeability than water-based fluids. For a number of operational reasons, all wells on the first development pad (CD1) were drilled with brine-based fluids. The second pad (CD2) development team accepted the lab results and after demonstrating the potential benefits of oil-based mud drilling, convinced the Drilling team to develop and test a suitable mud program. Initial test results confirmed the lab results and conclusions when well CD2–47 came in flowing 300% more than predicted, based on equivalent brine-based mud completions in comparable pay. Following this early success, the oil mud program was expanded and has consistently delivered more productive wells in line with expectations from the lab work. Background The Colville River Field (also known as the Alpine Field) is located approximately 60 miles due west of the Prudhoe Bay Field on the north slope of Alaska (see Figure 1). The oil pool contains 429 MMSTB of recoverable reserves, with approximately 1 billion barrels of oil-in-place. Production is from the Alpine Oil Pool, a very fine-grained Jurassic age shallow marine sandstone complex with stratigraphically trapped 40° API oil. The reservoir is normally pressured and undersaturated. Initial reservoir pressure is approximately 800 psia above the bubble point, and primary recovery mechanism is solution drive. Tables 1 and 2 (below) present a log and petrophysical overview as well as a summary of key reservoir properties.
- Europe > United Kingdom > Irish Sea > East Irish Sea > Liverpool Bay (0.81)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.54)
- Geology > Mineral > Silicate > Phyllosilicate (0.90)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.56)
- North America > United States > Alaska > North Slope Basin > Western North Slope > Colville River Field > Kingak Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- North America > United States > Alaska > North Slope Basin > Western North Slope > Colville River Field > Alpine Field > Kingak Formation (0.98)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Early exploration well tests in the Colville River Field (also known as Alpine) drilled with water-based mud systems exhibited unexplainably high near-wellbore residual skin damage as documented by pressure buildup testing. Typical formation damage mechanisms including clay reactions, mechanical damage, and gas trapping could not explain the damage. Between March 1998 and July 2001, laboratory testing determined imbibition-induced water trapping to be the primary formation damage mechanism. Insitu water saturation is significantly lower than the residual or connate water saturation, a condition rarely encountered in the field. Lab tests quantified impacts and identified methods to minimize or eliminate formation damage. This paper documents how successful identification of a unique damage mechanism improved drilling results in a low permeability sandstone. Introduction Exploration drilling results in Colville River prospects consistently demonstrated higher than expected near wellbore skin damage as measured by build-up test analysis. Investigations into more common damage mechanisms such as solids migration and clay swelling could not explain the damage. Early reservoir core studies indicated residual water saturations from relative permeability curves should be higher than observed initial water saturations. Later studies with traced core confirmed initial water saturations were considerably less than normal connate water saturations. Further lab work confirmed the water-blocking tendency by measuring water imbibition and permeability recovery during regain permeability tests. Various drilling fluids were tested, with oil muds consistently delivering lower permeability losses than water based fluids. For a number of operational reasons, all wells on the first development pad (CD1) were drilled with brinebased fluids. The second pad (CD2) development team accepted the lab results and after demonstrating the potential benefits of oil based mud drilling, convinced the Drilling team to develop and test a suitable mud program. Initial test results confirmed the lab results and conclusions when well CD2-47 came in flowing 300% more than predicted, based on equivalent brine-based mud completions in comparable pay to date. Following this early success, the oil mud program was expanded and has consistently delivered more productive wells in line with expectations from the lab work. Background The Colville River Field (also known as the Alpine Field) is located approximately 60 miles due west of the Prudhoe Bay Field on the north slope of Alaska (see Figure) 1 . It contains 429 MMSTB of recoverable reserves, with approximately 1 billion barrels of oil-in-place. Production is from the Alpine Oil Pool, a very fine-grained Jurassic age shallow marine sandstone complex with stratigraphically trapped 40 ° API oil. The reservoir is normally pressured and undersaturated. Initial reservoir pressure is approximately 800 psia above the bubble point, and primary recovery mechanism is solution drive. Tables 1 and 2 (below) present a log and petrophysical overview as well as a summary of key reservoir properties. The field was discovered in 1994 with drilling of the Bergschrund No. 1. Further delineation confirmed the prospect during subsequent winter seasons, and gravel pad construction began during the 1998 winter season. Field construction for the processing facilities and pipeline infrastructure commenced in the winter of 1999, followed closely by development drilling in May, 1999.
- Europe > United Kingdom > Irish Sea > East Irish Sea > Liverpool Bay (0.81)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.54)
- Geology > Mineral > Silicate > Phyllosilicate (0.90)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.56)
- North America > United States > Alaska > North Slope Basin > Western North Slope > Colville River Field > Kingak Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- North America > United States > Alaska > North Slope Basin > Western North Slope > Colville River Field > Alpine Field > Kingak Formation (0.98)
- Well Drilling > Formation Damage (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)