Because flow regimes in highly deviated and horizontal wells are quite different from those of vertical wells, velocity and hold up distribution are required for accurate flow rate and fluid entry determinations in multiphase flow. Production logging in horizontal wells can be challenging due to undulations and completions such as sand screen. In this paper, we present a field example that utilized advance production logging tool with distributed velocity and hold up distribution using tractor conveyance in sand screen completion. In this job, advanced production logging tool was further integrated with an additional spinner and pulse neutron tool to detect fluids in possible annulus space between screen and open hole. Results were exceptionally good measuring hold up and velocities. All the measurements showed that annulus space was filled with sand and fluid entries were determined confidently. In addition, it was shown that the single spinner in multiphase horizontal flow could not determine velocities of each phase unless totally immersed in one phase. The observations and recommendations were further discussed in this challenging production logging environment. Introduction Horizontal production logging operation has a main objective of obtaining flow profile of oil, gas and water contributions. The integration of flow profile with petrohysical and geological data will help to characterize the reservoir. Flow profile in vertical and horizontal wells is required for the proper evaluation of well performance. The determination of water entry intervals is very essential in the well performance evaluation. Increasing water production will influence well performance and considerably reduce oil production. As stated by many studies1,2, measuring or calculating the productivity of horizontal wells has been difficult because of their long length in the formation compared to vertical wells. The conventional production logging tools developed for vertical wells do not perform well in horizontal wells due to highly segregated flow in the horizontal section. For instance, gradiomanometer totally loses its accuracy, and spinners and capacitance holdup measurements are significantly affected by the stratified flow regimes that are common in horizontal wells if the deviation is more 70 degrees. Small changes in well deviation can cause large changes in fluid velocity and holdup, particularly at lower flow rates. In this paper, a field example of oil and water flow in horizontal well is presented. The presented horizontal well has a very complicated completion in the openhole section. The horizontal well produces relatively heavy oil and water from this complicated completion, which was designed to prevent the sanding in the wellbore. Flow Regimes in Horizontal Wells In vertical wells or near verticals wells that have deviations less than 20° mixed flow of water and oil flows with smooth velocity profile as shown from Fig.1. For the wells with deviations between 20° and 85°, flow regimes are generally quite complex.3 Heaviest phase segregates to the bottom of the pipe due to gravity and mixing layer is located on the upper side of the hole with dispersed bubbles of oil. This flow structure has large gradients in the velocity and holdup profiles. For wells with deviation between 85° and 95°, the flow becomes stratified. Water flows at the bottom with oil on the top and the flow has a strong dependence on the well deviation for low flow rates. At high flow rates the dependence on borehole deviation is smaller because the increasing shear frictional forces against the wall and interface dominate.
The Minagish Oolite is a thick undersaturated carbonate oil reservoir in the Minagish field in West Kuwait (Fig. 1) containing several billion STB. It is a mature but relatively undeveloped reservoir. Since discovery in 1959, it has produced 10% of its OOIP under a combination of natural depletion, gas re-injection and aquifer drive. Initial reservoir pressure had declined by about 450 psi prior to the Gulf war in 1990. The well blowouts following the war caused a significant pressure drop of another 700 psi. Following the blowout, plans were made to redevelop the West Kuwait fields and increase the production rate starting in 2001 and to sustain the plateau for at least 5 years. This strategy called for three-fold increase in the production rate of Minagish Oolite reservoir. Since the existing well inventory and the loss of the gas re-injection facility could not sustain the desired plateau rate, additional field development was required. To achieve the production target, a multidisciplinary team was formed to evaluate options. The recommended plan required the drilling of additional producers and installing a field-wide peripheral waterflood. The reservoir, however, presented a number of significant challenges to waterflooding, such as the presence of a substantial and not well defined tarmat near the oil/water contact, and uncertainties of lateral and vertical heterogeneities. In 1997 a full-field simulation model was developed, but this model didn't capture the water movement properly because of insufficient reservoir data at that time. As new core was obtained, a refined reservoir description was developed. Building on lessons learned from the previous full-field model and sector models, a new full-field model was developed which significantly improved well-by-well history matches. Although containing twice as many grid cells, the new model ran up to four times faster than the previous model by making use of the Analytical Aquifer option within the model, improved relative permeability curves and other model refinements. This paper traces the history of the field and the systematic evolution of the development plan. The reservoir simulation efforts including modeling strategy, history matching events, prediction runs, future direction and challenges are also addressed. Introduction Numerical simulators are an important tool for reservoir management, providing management the ability to observe how alternate development plans and operating strategies will affect future oil production and recovery. As additional information is acquired and new technologies are developed, it is necessary to periodically update the reservoir simulation tools. This report identifies the reasons for building a new model, the differences between it and the previous model, and documents the data-sources, files and the methodology used to construct the new model. The previous model (FFM 97) was constructed and initialized in 1997. The model was based on a course 12-layer reservoir description and history matched reservoir performance up through the start of dumpflood water injection. In predictive mode, however, the model did not adequately predict the rapid water movement in the northeast quarter of the field or the arrival of initial water in the peripheral producers. Sector models constructed at the same time indicated that a refined reservoir description that incorporated the observed barriers and high permeability streaks should provide an improved match of the observed water movement.
The Minagish Oolite is a thick undersaturated carbonate oil reservoir in the Minagish field in West Kuwait (Fig. 1) containing several billion STB. It is a mature but relatively undeveloped reservoir. Since discovery in 1959, it has produced 10% of its OOIP under a combination of natural depletion, gas re-injection and aquifer drive. Initial reservoir pressure had declined by about 450 psi prior to the Gulf war in 1990. The well blowouts following the war caused a significant pressure drop of another 700 psi. Following the blowout, plans were made to redevelop the West Kuwait fields and increase the production rate starting in 2001 and to sustain the plateau for at least 5 years. This strategy called for three-fold increase in the production rate of Minagish Oolite reservoir. Since the existing well inventory and the loss of the gas re-injection facility could not sustain the desired plateau rate, additional field development was required. To achieve the production target, a multidisciplinary team was formed to evaluate options. The recommended plan required the drilling of additional producers and installing a field-wide peripheral waterflood. The reservoir, however, presented a number of significant challenges to waterflooding, such as the presence of a substantial and not well defined tarmat near the oil/water contact, and uncertainties of lateral and vertical heterogeneities. In 1997 a full-field simulation model was developed, but this model didn't capture the water movement properly because of insufficient reservoir data at that time. As new core was obtained, a refined reservoir description was developed. Building on lessons learned from the previous full-field model and sector models, a new full-field model was developed which significantly improved well-by-well history matches. Although containing twice as many grid cells, the new model ran up to four times faster than the previous model by making use of the Analytical Aquifer option within the model, improved relative permeability curves and other model refinements. This paper traces the history of the field and the systematic evolution of the development plan. The reservoir simulation efforts including modeling strategy, history matching events, prediction runs, future direction and challenges are also addressed. Introduction Numerical simulators are an important tool for reservoir management, providing management the ability to observe how alternate development plans and operating strategies will affect future oil production and recovery. As additional information is acquired and new technologies are developed, it is necessary to periodically update the reservoir simulation tools. This paper identifies the reasons for building a new model, the differences between it and the previous model, and documents the data-sources, files and the methodology used to construct the new model. The previous model (FFM 97) was constructed and initialized in 1997. The model was based on a course 12-layer reservoir description and history matched reservoir performance up through the start of dumpflood water injection. In predictive mode, however, the model did not adequately predict the rapid water movement in the northeast quarter of the field or the arrival of initial water in the peripheral producers. Sector models constructed at the same time indicated that a refined reservoir description that incorporated the observed barriers and high permeability streaks should provide an improved match of the observed water movement.
In the early 1990s oil and gas exploration and development in Manitoba decreased dramatically. Between 1989 - 1991, only six geophysical programs were run. By the end of 1991 the amount of Crown land under disposition had dropped to 25,800 ha, a 12 year low. In 1992, only 28 wells were drilled in the province. In 1993 Manitoba Energy and Mines recognized that simply providing a stable and competitive fiscal regime was not enough to attract new companies and new investment to Manitoba. A more aggressive approach was need to encourageExploration activity, in particular targeting under-explored pre-Mississippian formationsThe application of new technologies, i.e., horizontal drilling and 3D seismicRecompletions and workovers of existing wells and optimization of existing waterflood projects The culmination of our efforts was the introduction of the Petroleum Exploration Assistance Program (PEAP) in November 1995. PEAP provides assistance to companies exploring for oil and gas in Manitoba. The program provides funding of up to 20% of eligible expenditures to a maximum of $200,000 per company in any fiscal year. PEAP funding has been approved at $1 million a year for three years. PEAP in combination with Manitoba's Drilling Incentive Program (MDIP) and other competitive advantages has resulted in a tremendous increase in oil and gas activity in the province. Crown land under disposition has more than quadrupled to 113,566 ha. Over 1,900 km of seismic was run in 1996, more than in the previous seven years combined. A total of 57 wells were drilled last year of which 28 or 49% were exploratory including 15 pre-Mississippian tests. This paper outlines the initiatives of Manitoba Energy and Mines to attract oil and gas investment to Manitoba and the competitive advantages enjoyed by operators in the province. A brief overview of Manitoba's geology provides a framework for a summary of oil and gas activity in the province. Included is a description of PEAP and MDIP. A comparison of Crown royalty, production tax and petroleum incentives between Manitoba and Saskatchewan is provided to illustrate the attractiveness of investment in Manitoba. Introduction The mission of Manitoba Energy and Mines, Petroleum and Energy Branch is to foster investment in the sustainable development of Manitoba's petroleum resources. The Branch believes there is the potential for substantial ongoing exploration in Manitoba. The Branch also recognizes that there is tremendous competition for capital investment and, to quote David Tuer, President and CEO of PanCanadian Petroleum, "capital knows no borders"(1). The Branch has a four-prong strategy to provide the best business climate in Canada for oil and gas investment:Develop easy to understand workable regulations, policies and proceduresDevelop and disseminate resource informationEnsure Manitoba's petroleum fiscal regime is effective and CompetitiveWork to achieve a high level of awareness of our competitive Advantages The first step in development of workable regulations was completed in 1994 when Manitoba's new Oil and Gas Act was proclaimed.
The Minagish Oolite is a thick undersaturated carbonate oil reservoir in the Minagish field in West Kuwait (Fig. 1) containing several billion STB. It is a mature but relatively undeveloped reservoir. Since discovery in 1959, it has produced 10% of its OOIP under a combination of natural depletion, gas re-injection and aquifer drive. Initial reservoir pressure had declined by about 450 psi prior to the Gulf war in 1990. The well blowouts following the war caused a significant pressure drop of another 700 psi. Following the blowout, plans were made to redevelop the West Kuwait fields and increase the production rate starting in 2001 and to sustain the plateau for at least 5 years. This strategy called for three-fold increase in the production rate of Minagish Oolite reservoir. Since the existing well inventory and the loss of the gas re-injection facility could not sustain the desired plateau rate, additional field development was required. To achieve the production target, a multidisciplinary team was formed to evaluate options. The recommended plan required the drilling of additional producers and installing a field-wide peripheral waterflood. The reservoir, however, presented a number of significant challenges to waterflooding, such as the presence of a substantial and not well defined tarmat near the oil/water contact, and uncertainties of lateral and vertical heterogeneities. In 1997 a full-field simulation model was developed, but this model didn't capture the water movement properly because of insufficient reservoir data at that time. As new core was obtained, a refined reservoir description was developed. Building on lessons learned from the previous full-field model and sector models, a new full-field model was developed which significantly improved well-by-well history matches. Although containing twice as many grid cells, the new model ran up to four times faster than the previous model by making use of the Analytical Aquifer option within the model, improved relative permeability curves and other model refinements. This paper traces the history of the field and the systematic evolution of the development plan. The reservoir simulation efforts including modeling strategy, history matching events, prediction runs, future direction and challenges are also addressed. Introduction Numerical simulators are an important tool for reservoir management, providing management the ability to observe how alternate development plans and operating strategies will affect future oil production and recovery. As additional information is acquired and new technologies are developed, it is necessary to periodically update the reservoir simulation tools. This paper identifies the reasons for building a new model, the differences between it and the previous model, and documents the data-sources, files and the methodology used to construct the new model. The previous model (FFM 97) was constructed and initialized in 1997. The model was based on a course 12-layer reservoir description and history matched reservoir performance up through the start of dumpflood water injection. In predictive mode, however, the model did not adequately predict the rapid water movement in the northeast quarter of the field or the arrival of initial water in the peripheral producers. Sector models constructed at the same time indicated that a refined reservoir description that incorporated the observed barriers and high permeability streaks should provide an improved match of the observed water movement. Since completion of the FFM 97, significant drilling activity and data acquisition has improved the understanding of the reservoir. Between January 1998 and August 2000, 25 wells have been drilled (including 7 wells being cored) and 10 wells were RFT'd across the entire reservoir. This additional data, particularly the core, has significantly improved the geological understanding of the reservoir. One significant improvement has been in defining the areal extent and vertical distribution of the tarmat, which is the major controlling factor affecting water influx and pressure support from the surrounding aquifer and dumpflood injection rates.
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