The Issaran field, a heavy-oil reservoir with reserves of approximately 500 MM bbl of oil, was discovered in 1981. The producing horizons were carbonate formations of Miocene age occurring at an average depth of 2,200 ft. The oil being produced on artificial lift was of 9° to 12° API in a viscosity range of 3,000 to 5,000 cp. Before mid-1999, nine wells had been drilled in the field with a cumulative production of about 450 BOPD. This field did not command high priority because of its low productivity and the low prices that heavy crude attracts. However, with the oil price increases in 1999 and 2000, the Egyptian government made a concerted effort toward developing this field. New and applied technology provided considerable returns within 1 year of new investments. The field has been producing as much as 1,800 BOPD (a four-fold increase), from five new wells drilled in the area. Plans were made for thermal recovery in the form of steam stimulation for this heavy-oil reservoir, but first, it was necessary to produce under "cold production." Several industry publications1–3 have addressed cold production, predominantly pertaining to sandstone reservoirs. This paper highlights the experiences, challenges, and practical solutions in optimizing production from a fractured, carbonate reservoir. Several leading-edge technologies and optimization techniques that are effective in less-challenging reservoirs have contributed tremendously to enhancing production from this heavy-oil reservoir. The path to success began with the definition of the reservoir-flow mechanism, optimized perforating schemes, ehnanced carbonate stimulation, and improved completion designs. Introduction Field research1 reveals that most heavy-oil production comes from unconsolidated sands originating from fluvial-deltaic deposition. The successful mode of cold production in such wells has been to produce formation sand along with the oil. The use of well-completion designs that allow such recovery is known as sand management. Rate increases of up to 20 times the sand-free oil-production rate (with no sand control) have been reported.4 Several other nonthermal recovery mechanisms for increasing productivity have been identified, such as foamy oil and horizontal well completions (possible variations into multilateral completions) and hydraulic fracturing. In contrast to fluvial-deltaic sandstones, carbonate reservoirs are generally products of a much more serene depositional environment where processes such as cementation, compaction, and recrystallization of the rock resultin a tight and more rigid matrix. In such reservoirs, sand management techniques are not applicable. However, diagenesis in carbonates can sometimes open conduits to flow in the form of fractures or vugs. The task then becomes to identify such fractures and capitalize on their possible contribution to flow. Background The Issaran field was developed initially with the drilling of eight wells between 1981 and 1987. The Issaran oilfield is a major accumulation in terms of oil in place. It is estimated to have approximately 500 MM STB. The field is located 180 miles southeast of Cairo, and 2 miles inland of the western shore of the Gulf of Suez (Fig. 1, Page 8). The Issaran field is of the Miocene age. The field primarily consists of three oil-bearing reservoirs ranging in depth from 1,000 to 2,000 ft. These are the Upper and Lower Dolomite and the Nukhul formations (Fig. 2, Page 9). More recently, the Nukhul formation was further subdivided into the Gharandal formation. The references made to Nukhul in this paper also include the Gharandal formation, unless otherwise specified.
The primary objective in the design of a perforating program is to remove or minimize any impedance to the desired fluid movement from the reservoir to the cased wellbore. The possible damage that could occur from drilling-fluid contacting the formation is one of the significant problems that must be addressed in selecting the perforation technique. As drilling fluid enters the formation, it can deposit solid matter, cause clay swelling, and induce chemical precipitation, creating a damaged zone area around the wellbore. All of these resulting phenomena reduce the size of the pores available for fluid flow. In addition to the induced drilling fluid damage, the radial displacement of formation materials during the perforating event causes crushing and compacting of the area that immediately surrounds the perforation (better known as the crushed zone area), which will subsequently result in a reduced permeability envelope around the perforating tunnels. Perforating the well in an underbalanced condition using super deep penetrating "premium" charges has proven to be an effective technique in removing near wellbore damage, as it allows the formation pressure to remove the damaged rock instantly. However, if the formation pressure is too low to move the damaged rock, permeability at the face of the perforation can be greatly reduced. In many wells, the damage can be so severe that only 25 percent of the perforations will produce. This paper reviews the successful application of a combined propellant and perforating technique in depleted, highly laminated sand reservoirs. In the case histories discussed, applying this technique resulted in stimulated wellbore conditions that improved flow efficiency. The results from the pressure transient analysis are included and will verify the attained productivity improvements. The paper also discusses the initial operational problems encountered in implementation of the propellant/perforating technique and the precautionary methods that were taken to address these scenarios. Introduction Agiba Petroleum Company currently operates six producing fields Off and onshore in Egypt. The Raml and El-Faras fields, located in the Qattara depression area of the western desert, are the two fields that will be targeted in this discussion. The fields under consideration for exploration and development in this area are considered marginal as they include fields with small reservoirs that produce from the Bahariya formation. The Bahariya is a heterogeneous formation both vertically and laterally, consisting of multi-layered, interbeded glauconitic rich sandstone, limestone and extensive shale beds. The commercial development of these fields required a prudent approach that concentrated on minimizing expenditures with rapid realization of production, to ensure that optimum cash flow patterns were obtained and hence maximize the Net Present Value (NPV) on invested capital. Given the conditions of the field, the primary requirement for their production, therefore, was to determine a method to maximize the productivity index in a cost effective manner aimed at increasing the flow rate for a given driving force (i.e. formation drawdown). Accordingly, it was critical that an optimum perforating scheme is to be implemented in Agiba's completions, in order to establish effective connectivity to the reservoir.
Inadequate flow efficiency in perforated wells in cased-hole completions has been a major concern in the oilfield since the first use of perforating gun systems. Because of this, one of the primary needs in design of a perforated completion is the accurate assessment of the efficiency of the proposed perforation scenario to transmit fluid from the reservoir to the wellbore. Flow efficiency is affected by such conditions as the number of perforations actually open to flow, degree of damage around the perforations, formation physical properties, in-situ stress conditions influencing the perforator penetration, and extent of formation crushing around the perforation. This complex interaction of perforating geometry, formation characteristics, and perforating environment precludes traditional, global solutions to design or analyze perforated completions in order to achieve optimum productivity results. Each case must be addressed individually, and all possible information must be considered; (e.g., Cores, logs and well test results). Unfortunately, existing industry models used to design and optimize perforated completions are fairly basic and have relied primarily on section I API Perforator Test Data (i.e. perforator penetration and entrance-hole results obtained from testing the perforating system under surface conditions in concrete targets) for predicting downhole perforation performance. Since these models obviously do not reflect the actual reservoir conditions, field performance often falls short of predicted results because an accurate validation method for optimizing the gun selection process has not been applied. This paper will review a new quantitative method based on the unique properties of the reservoir that has been developed to optimize perforating design for individual wells. The process is based on experimental data from laboratory tests as well as theoretical (i.e. numerical and analytical) modeling to identify optimal parameters needed for efficiency in perforated completions. Case Histories showing the successful implementation of the quantitative method will be presented. The results attained from the process design technique will be validated against actual post-perforation, pressure-transient-analysis field data to demonstrate the productivity improvement that is possible through the use of this perforating solution. Introduction Wells drilled to access petroleum formations cause a pressure gradient between the reservoir pressure and that at the bottom of the well. During production or injection, the pressure gradient forces fluids to flow through the porous medium. Darcy's law, the most fundamentally basic petroleum engineering relationship, suggests that the production rate is proportional to the pressure driving force (draw-down) and the reservoir permeabilityEquation 1 The fluid viscosity µ also enters the relationship and for radial flow through an area 2prh, equation (1) becomesEquation 2 Where Pwf and rw are the bottom hole flowing pressure and wellbore radius respectively.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe primary objective in the design of a perforating program is to remove or minimize any impedance to the desired fluid movement from the reservoir to the cased wellbore. The possible damage that could occur from drilling-fluid contacting the formation is one of the significant problems that must be addressed in selecting the perforation technique. As drilling fluid enters the formation, it can deposit solid matter, cause clay swelling, and induce chemical precipitation, creating a damaged zone area around the wellbore. All of these resulting phenomena reduce the size of the pores available for fluid flow. In addition to the induced drilling fluid damage, the radial displacement of formation materials during the perforating event causes crushing and compacting of the area that immediately surrounds the perforation (better known as the crushed zone area), which will subsequently result in a reduced permeability envelope around the perforating tunnels.Perforating the well in an underbalanced condition using super deep penetrating "premium" charges has proven to be an effective technique in removing near wellbore damage, as it allows the formation pressure to remove the damaged rock instantly. However, if the formation pressure is too low to move the damaged rock, permeability at the face of the perforation can be greatly reduced. In many wells, the damage can be so severe that only 25 percent of the perforations will produce. This paper reviews the successful application of a combined propellant and perforating technique in depleted, highly laminated sand reservoirs. In the case histories discussed, applying this technique resulted in stimulated wellbore conditions that improved flow efficiency. The results from the pressure transient analysis are included and will verify the attained productivity improvements.The paper also discusses the initial operational problems encountered in implementation of the propellant/perforating technique and the precautionary methods that were taken to address these scenarios.
fax 01-972-952-9435.References at the end of the paper. AbstractThe Issaran field, a heavy-oil reservoir with reserves of approximately 500 MM bbl of oil, was discovered in 1981. The producing horizons were carbonate formations of Miocene age occurring at an average depth of 2,200 ft. The oil being produced on artificial lift was of 9° to 12° API in a viscosity range of 3,
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