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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 CD2โ47 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 ร 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 ยฐAPI 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)
Summary Early exploration well tests in the Colville River field (also known as the Alpine reservoir) drilled with water-based mud (WBM) systems exhibited unexplainably high near-wellbore residual skin damage 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. In-situ water saturation is significantly lower than 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 low-permeability sandstone. Introduction Exploration drilling results in early Colville River prospects consistently returned higher than expected near-wellbore skin damage measured by buildup-test analysis. Investigations into more common damage mechanisms, such as solids migration and clay swelling, could not explain the damage. Early concerns over water imbibition stemmed from relative-permeability response developed during reservoir-core studies, which indicated observed initial-water saturations were significantly less than expected residual-water saturations. Later studies using traced core fluids confirmed that initial-water saturations were considerably less than natural connate-water saturations, which would be expected for strongly water-wet formations in capillary equilibrium with a free-water contact. Follow-up 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-based muds (OBMs) consistently delivering greater 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. As drilling commenced on the second pad (CD2), production engineers reviewed the lab results and, after demonstrating the potential benefits of OBM drilling, convinced the drilling team to develop and test a suitable mud program. Field experience confirmed the lab results and conclusions when a newly drilled well, CD2-47, came in flowing 300% of predicted rates based on brine-based mud completions in comparable pay. Following this early success, the OBM program was expanded and has consistently delivered more productive wells in line with lab-derived expectations. Background The Alpine reservoir of the Colville River field is approximately 60 miles west of the Prudhoe Bay field on the North Slope of Alaska (see Fig. 1). This reservoir contains 429 million STB of recoverable reserves, with approximately 1 billion bbl 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 DEGREE API oil. The reservoir is normally pressured and undersaturated. Initial reservoir pressure is approximately 800 psi above the bubblepoint, and the primary recovery mechanism is solution drive. Tables 1 and 2 present a log and petrophysical overview, as well as a summary of key reservoir properties. The field was discovered in 1994 with the drilling of Bergschrund No. 1. Further delineation confirmed the prospect during subsequent winter seasons, and gravel-pad construction began during the 1998 winter season. Field construction of processing facilities and pipeline infrastructure began in the winter of 1999, which was followed closely by development drilling in May 1999. Major process modules arrived in March of 2000, and first oil was delivered in November. The development strategy uses horizontal completions in a direct line-drive configuration, while maximizing recovery through application of pattern waterflood and miscible water-alternating-gas injection. Early Exploration Results Following the early success of the Bergschrund No. 1 discovery well, additional wells were drilled during the winters of 1995 and 1996 to further delineate the reservoir and define reservoir properties. Geologic cores and bottomhole-fluid samples were collected from two of the earliest wells: Neve 1 and Alpine 1A. Because of the brief Arctic-winter exploration season, only select wells were production tested. Upon completion of production testing, a pressure build-up test was conducted to observe pressure build-up response of the reservoir. Early well results indicated higher levels of formation damage than routinely observed in North Slope wells. Table 2 lists results from early well testing.
- 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 (0.88)
- 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)
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 ยฐ 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)
Abstract Initial saturations of hydrocarbons and water, existing in porous media, control reserves in place and, in many cases, the deliverability/recovery of these reserves. Hence, their accurate determination is essential for proper economic and reservoir engineering evaluation and optimization. Electric logging techniques are commonly used to estimate initial fluid saturations, but may suffer from problems with accurate determination of the log calibration constants for a given reservoir rock, as well as the accurate determination of in situ water resistivity in some situations. Advanced logging techniques, such as magnetic resonance, have been used in recent years to estimate the saturation of bound and free water. The use of these techniques is increasing, but cost and other factors have limited their widespread usage. Various types of reactive tracers and other in situ techniques for the determination of initial fluid saturations have also been used to attempt to determine initial fluid saturations with varying degrees of success. Another family of techniques, on which this paper concentrates, is the actual measurement of in situ initial or swept zone fluid saturations on samples of appropriately obtained, preserved, handled and analysed core material. Different coring techniques and fluid and coring procedures will be discussed, along with the elative merits and advantages/disadvantages of each. Illustration of the results of various techniques will be given with respect to their cost, effectiveness, and accuracy of the data generated. Introduction Initial fluid saturations, defined as the fraction of the interstitial space in a pore system occupied by oil, water, and gas, are key factors in the determination of initial reserves of actual and recoverable hydrocarbons in place and dominate reservoir flow properties due to the strong influence they exhibit on relative permeability . Surprisingly, in many reservoirs, initial fluid saturations are virtually unknown or improperly measured, resulting in gross over or under estimation of oil or gas reserves in place. The improper determination of these initial saturations may also greatly affect thepotential for formation damage due to phase trapping, resulting in a poor appraisal of deliverability. In some cases, improper initial saturation estimates can lead to the bypassing of potentially productive pay zones, resulting in significant lost reserves or the erroneous completion of ineffective pay and wet or no production from the completed zone. Why Is it Important to Have a Proper Knowledge of Initial Fluid Saturations Improper determination of the initial oil, water or gas saturations existing in porous media may often lead to expensive mistakes in the development of a field. In some cases, large amounts of capital are invested where minimal reserves are present or marginal flow is obtained. In other cases, viable pay is overlooked due to a perceived belief, from improper saturation evaluations, that the pay will be wet or non-productive. The hazards involved with an inadequate understanding of initial saturation conditions can generally be grouped into three categories. Poor Initial Reserves Evaluation Oil or gas in place is based on a simple volumetric calculation of hydrocarbon volume present in the effective porosity of the system.
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract Initial saturations of hydrocarbons and water, that exist in porous media, control reserves in place and, in many cases, the deliverability/recovery of these reserves. Hence, their accurate determination is essential for proper economic and reservoir engineering evaluation and optimization. Electric logging techniques are commonly used to estimate initial fluid saturations, but may suffer from problems with accurate determination of the log calibration constants for a given reservoir rock, as well as the accurate determination of in-situ water resistivity in some situations. Advanced logging techniques, such as magnetic resonance, have been used in recent years to estimate the saturation of bound and free water. The use of these techniques is increasing, but cost and other factors have limited their widespread usage. Various types of reactive tracers and other in-situ techniques for the determination of initial fluid saturations have also been used to attempt to determine initial fluid saturations with varying degrees of success. Another family of techniques, on which this paper concentrates, is the actual measurement of in-situ initial or swept zone fluid saturations on samples of appropriately obtained, preserved, handled and analyzed core material. Different coring techniques, fluids and coring procedures will be discussed, along with the relative merits and advantages/disadvantages of each. Illustration of the results of the use of various techniques will be given with respect to their cost, effectiveness and accuracy of the data generated. Introduction Initial fluid saturations, defined as the fraction of the interstitial space in a pore system occupied by oil, water and gas, are key factors in the determination of initial reserves of actual and recoverable hydrocarbons in place and dominate reservoir flow properties due to the strong influence they exhibit on relative permeability. Surprisingly, in many reservoirs, initial fluid saturations are virtually unknown or improperly measured, resulting in gross over or under estimation of oil or gas reserves in place. The improper determination of these initial saturations may also greatly affect the potential for formation damage due to phase trapping, resulting in a poor appraisal of deliverability. In some cases, improper initial saturation estimates can lead to the bypassing of potentially productive pay zones, resulting in significant lost reserves or the erroneous completion of ineffective pay and wet or no production from the completed zone. WHY IS IT IMPORTANT TO HAVE PROPER KNOWLEDGE OF INITIAL FLUID SATURATIONS Improper determination of the initial oil, water or gas saturations existing in porous media may often lead to expensive mistakes in the development of a field. In some cases, large amounts of capital are invested where minimal reserves are present or marginal flow is obtained. In other cases, viable pay is overlooked due to a perceived belief, from improper saturation evaluations, that the pay will be wet or non-productive. The hazards involved with an inadequate understanding of initial saturation conditions can generally be grouped into three categories: Poor Initial Reserves Evaluation. Oil or gas in place is based on a simple volumetric calculation of hydrocarbon volume present in the effective porosity of the system.
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
This paper (SPE 52889) was revised for publication from paper SPE 35242, first presented at the 1996 SPE Permian Basin Oil and Gas Recovery Conference held in Midland, Texas, 27-29 March. Original manuscript received for review 11 April 1996. Revised manuscript received 29 April 1997. Paper peer approved 17 April 1998. Summary Underbalanced drilling (UBD) has been used with increasing frequency to minimize problems associated with invasive formation damage, which often greatly reduce the productivity of oil and gas reservoirs, particularly in openhole horizontal well applications. UBD, when properly designed and executed, minimizes or eliminates problems associated with the invasion of particulate matter into the formation as well as a multitude of other problems such as adverse clay reactions, phase trapping, precipitation, and emulsification, which can be caused by the invasion of incompatible mud filtrates in an overbalanced condition. In many UBD operations, additional benefits are seen because of a reduction in drilling time, greater rates of penetration, increased bit life, a rapid indication of productive reservoir zones, and the potential for dynamic flow testing while drilling. UBD is not a solution for all formation damage problems. Damage caused by poorly designed and/or executed UBD programs can rival or even greatly exceed that which may occur with a well-designed conventional overbalanced drilling program. Potential downsides and damage mechanisms associated with UBD will be discussed. These include the following.Increased cost and safety concerns. Difficulty in maintaining a continuously underbalanced condition Spontaneous imbibition and countercurrent imbibition effects. Glazing, mashing, and mechanically induced wellbore damage. Macroporosity gravity-induced invasion. Difficulty of application in zones of extreme pressure and permeability. Political/career risk associated with championing a new and potentially risky technology. We discuss reservoir parameters required to design an effective underbalanced or overbalanced drilling program, laboratory screening procedures to ascertain the effectiveness of UBD in a specific application and review the types of reservoirs that often present good applications for UBD technology. P. 214
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract Formation damage is a very reservoir specific process, but extensive studies indicate that generalities can often be drawn with respect to certain types and mechanisms of damage which are more prevalent with various reservoir types. This paper provides a mechanistic discussion of various types of formation damage common to horizontal wells, such as fluid-fluid and rock-fluid incompatibilities, solids invasion, effect of overbalance pressure, aqueous phase trapping, chemical adsorption, wettability alteration, microbiological activity, and fines migration. These phenomena are discussed and how they specifically relate to the following formation types:Clean and dirty homogeneous sands. Clean and dirty laminated sands. Unconsolidated sands. Fractured sands. Homogeneous carbonates. Fractured carbonates. Vugular carbonates. Recommendations for various fluid types and procedures which have experienced success in certain situations are also presented. Laboratory testing of fluids and representative core samples is highlighted as a potential diagnostic tool to select the optimum fluids for drilling, completion, stimulation and workover treatments. Use of these guidelines can, in many cases, narrow the choice of potential fluids considered for use in a given lithofacies type and increase the efficiency of the optimization process. Introduction Horizontal drilling is being utilized in an ever increasing fashion to exploit reservoirs exhibiting thin pay zones, problems with water or gas coning, to obtain greater reservoir exposure and to maximize the productive potential of naturally fractured reservoirs. Reductions in the productivity of these horizontal wells due to improperly or inadequately designed drilling, completion or workover programs is a frequent occurrance. This paper documents common areas for potential reductions in the productivity of horizontal wells completed in oil or gas bearing formations due to invasive formation damage and provides general criteria for the design and selection of fluids and operating programs to minimize potential damage. Invasive Formation Damage Formation damage can be described as any phenomenon induced by the drilling, completion or stimulation process or by regular operations resulting in a permanent reduction in the productivity of a producing oil or gas well or the reduction in the injectivity of a water or gas injection well. Invasive formation damage can occur by the introduction of:Foreign potentially incompatible fluids into the formation. Natural or artificial solids. Extraneous immiscible phases. Physical mechanical damage. Further information on some of the specific mechanisms of these various types of invasive damage will be elucidated upon later in the paper. Formation Damage in Horizontal vs. Vertical Wells A detailed discussion of mechanisms of formation damage in horizontal wells has been presented in the literature. Formation damage tends to be more significant in horizontal vs. vertical wells for a number of reasons, some of these being:Longer fluid exposure time to the formation during drilling and greater potential depth of invasion in situations where sustained fluid and solids losses to the formation are apparent.
- North America > United States (0.68)
- Europe > Norway > Norwegian Sea (0.25)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.91)
Abstract As the industry seeks to increasingly exploit reserves of natural gas contained in low permeability intercrystalline sandstone and carbonate formations (<20 mD in permeability) many questions have arisen as to the optimum practices to drill and complete horizontal and vertical wells in these systems as well as the best techniques to hydraulic or acid fracture these formations to obtain economic production rates. This paper provides a summary of recent work which has been conducted in the diagnosis and remediation of problems associated with tight gas reservoirs. Information on the importance of reservoir quality assessment and initial saturation determination is presented as well as a detailed discussion of common damage mechanisms which can affect the productivity of tight gas formations. These include fluid retention problems, adverse rock-fluid and fluid-fluid interactions, counter-current imbibition effects during underbalanced drilling, glazing and mashing, condensate dropout and entrainment from rich gases, fines mobilization and solids precipitation. The impact of these problems during drilling, completion, workover and kill operations is reviewed and suggestions presented for the prevention and potential remediation of these problems. Specific examples of where these problems have been observed in 23 different common Western Canadian lower permeability gas horizons are presented in a summary format for informative purposes. Introduction Vast reserves of valuable natural gas and associated liquids exist trapped in low permeability intercrystalline and microfractured carbonate and sandstone formations throughout the world. Due to the low inherent viscosity of gas, conditions can be such that these reserves can be recovered from these low permeability strata in situations where the economic recovery of conventional liquid hydrocarbons would be impossible. This paper describes various mechanisms which can influence the effective recovery of gas from low permeability formations and presents a variety of drilling, completion, production and remediation techniques that have proven useful recently in optimizing the recovery of gas from formations of this type. The definition of a "low" permeability reservoir is somewhat arbitrary, but for the purposes of this paper would be considered to be formations which have a surface routine average air absolute permeability of less than 20 mD. In-situ reservoir condition permeabilities in these types of reservoirs are generally less than 1 mD and can range down into the micro Darcy range (10-6 D) in many situations. Although the emphasis in this paper is specifically on low permeability gas reservoirs, much of the information presented is also applicable to higher permeability gas bearing formations. What is the Challenge? If we consider what could cause uneconomic production rates from a low permeability gas bearing formation, the options generally will fall into six categories, these being;Poor reservoir quality - period! Adverse initial saturation conditions Damage induced during drilling and completion Damage induced during hydraulic or acid fracturing Damage induced during kill or workover treatments Damage induced during production operations P. 117
- Geology > Mineral (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.88)
- Geology > Geological Subdiscipline (0.67)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)