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Abstract The Mauddud carbonate reservoir is the main oil producer in Bahrain oilfield that has been undergoing crestal gas injection with natural aquifer support at the flanks. It has been producing since 1932 and currently in a very mature stage. Due to its rocks wettability characteristics (preferentially oil-wet nature), the residual oil left behind gas and water fronts range from 20–70%. One of the potential options to recover portion of this residual oil is through Chemical Flooding possibly Alkaline-Surfactant-Polymer (ASP) flood. A project was hence initiated to investigate its technical and economical feasibility. It was decided to carry out field experiments to gauge the reservoir response through well-bore treatments before proceeding with a full-scale study and field pilot implementation. Initial field-testing on single-well huff-and-puff basis with experimental recipes provides sufficient positive indications for the project to proceed. The results of these initial tests are presented in this paper. Introduction The subject Mauddud Reservoir has been under crestal gas injection for pressure maintenance for the past 65 years. While expanding gas cap influences the recovery from the crestal portions of the reservoir cap, the north and south flanks are influenced by water displacement from the aquifer. Being a preferentially oil wet reservoir it has been observed that very high water cuts prevail even with oil saturations as high as 70–80% in the water contacted areas. Therefore, it is necessary to produce it albeit at water cuts as high as 98–99% and high rates of about 3500 bpd. It was therefore decided to look for a wettability reversal treatment and flood scheme to recover trapped oil, which would otherwise be bypassed. Towards this end single-well Alkaline-Surfactant (AS) treatments were carried out in several wells with different Alkali/Surfactant formulations. The first phase of the experiment involved the accurate testing of the wells' produced fluids to obtain reliable water cuts following which base saturation logs (RST-C/O) was obtained. Thereafter treatments were carried out and additional saturation logs (RST-C/O) were recorded soon after the treatment. After a soaking time of about 72 hours, wells were flowed back and the water cuts were monitored until wells returned to their original performances. Prior to the treatments the wells were acidized and pressure buildup surveys were run on the subject wells in order to assess skin damage. These buildups helped eliminate any stimulation effects from the post treatment performance.
- North America > United States (1.00)
- Asia > Middle East > Bahrain (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.25)
- Asia > Middle East > Bahrain > Awali Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract The Saih Rawl field (SR) is the biggest gas field in Oman, containing condensate rich gas in the Barik sandstone reservoir and dry gas in the deeper Miqrat sandstone reservoir. Production to date was mostly from the Barik reservoir, at which most wells are completed, resulting in the reservoir pressure dropped to a current average of 260 to 470 bar form the initial pressure of 513 bar. Furthermore the layered nature of the reservoirs and the varying hydraulic fracturing of the different units, production from the various units differed significantly resulting in significant vertical differential depletion of the reservoir. The field's CGR (Condensate Gas Ratio) of the Barik reservoir has dropped from 480 m3/MMm3 to 300 m3/MMm3 as a consequence of liquid drop out resulting the Barik reservoir pressure dropping to below the dew point pressure, and the increasing dry gas production from Miqrat reservoir through commingled production from some of the wells. Well performance in the Saih Rawl field is affected by the flow impairment caused by the condensate dropout, the quality of the placed hydraulic fractures in terms of their efficiency and geometry, and completion type, single reservoir or commingled in the two reservoirs of Barik and Miqrat. This makes predicting well performance a very complex undertaking. The limited worldwide experience in developing tight gas-condnesate reservoirs possed a genuine challenge for the initial development planning of this field in the mid-1990s. In particular the prediction of the long term production behaviour. Production of gas/condensate wells in tight reservoirs with liquid drop-out is still one of the most challenging subjects in reservoir engineering today. The Saih Rawl field provides one of the first sets of comprehensive data on this phenomenon. The paper reviews actual reservoir performance in the Saih Rawl field over the first 40 months of its production life. For example, high well declines have been observed (upto 50% per annum), the effect of fluid mixture of the rich and dry gas, resulting from the commingled production, the potential cross-flow of the dry gas to the rich gas as was indicated by condensate production and the well capacity. Dynamic models, calibrated by historic production data, are used to assess these effects and to predict future production performance. Introduction The Saih Rawl field (SR), discovered in 1991, is the biggest gas field in Oman with total reserves (1.1.2002) of over 15 Tscf. The field contains condensate rich gas in the Barik sandstone reservoir and dry gas in the Miqrat sandstone reservoir The datum depths of these reservoirs are 4370 and 4850 mss respectively. The field is a layer-cake type with 8 and 6 gas bearing geological units in Barik and Miqrat respectively, separated by laterally extensive pressure sealing heteroliths. The Barik reservoir has a 220m gas column with average porosity of 7.6%. The Miqrat reservoir has a 100m gas column with an average porosity of 6.8%. Permeabilities of both reservoirs are in the range of 0.02 - 10 mD. All the production wells to date have been hydraulically fractured to increase flow rates (See Figure A). The initial reservoir pressure was 513 bar for the Barik and 581 bar for the Miqrat reservoir. The dew point pressure is 425 bar for the Barik rich gas. The Saih Rawl field is produced to meet a gas demand that is varying throughout the year, while ensuring a production capacity to meet a contractual maximum annual daily load (MADL) demand, this production philosophy also has the objective to maximize early condensate production without affecting the fields ultimate gas condensate recovery.
- Asia > Middle East > Oman > Al Wusta Governorate > Ghaba Salt Basin > Saih Rawl Field > Miqrat Formation (0.99)
- Asia > Middle East > Oman > Al Wusta Governorate > Ghaba Salt Basin > Saih Rawl Field > Barik Formation (0.99)
- Asia > Middle East > Oman > Bashair Sandstone Formation (0.98)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract Oil field operations involve a certain amount of risk. The risk factor increases significantly when dealing with sour hydrocarbons due to the highly toxic nature of hydrogen sulfide. This aspect takes a great deal of importance when large areas of such field are inhabited in addition to high population density towns in very close proximity to the field. This paper will address the challenges and safety concerns when developing sour crude oil fields in inhabited areas from production engineering perspective. Application of proven technologies such as smokeless flare system, permanent downhole monitoring system, and remotely controlled wellhead equipment and data acquisition will be discussed. These systems can minimize the impact of oil well clean-up operations on environment, frequent well interventions and well-site visits for safe operations in a field producing from reservoirs with relatively high hydrogen sulfide content in the hydrocarbons. Utilization of these systems will enhance the safety of oil field operations as well as the inhabitants in the nearby areas. Introduction The giant Qatif field was discovered in 1945 and is located about 50 km north of Dhahran. The field has an elongated anticline with two domes; one in the north and one in the south (Fig. 1). The major part of the field extends over onshore populated agricultural areas and major highways and about 15% of the field extends offshore shallow water depths. The field has seven oil bearing reservoirs and one gas bearing reservoir. Three oil bearing reservoirs have been produced in the past at relatively low production rates and are being further developed to produce a blend of 500,000 BOPD of Arabian Light crude grade (33–35° API). These reservoirs have practically no or very limited aquifer support due to existence of tar mats below the oil zone and poor petrophysical rock properties towards the aquifer. A peripheral water injection system will provide pressure support to these reservoirs. The three targeted reservoirs contain sour hydrocarbons with the hydrogen sulfide (H2S)content in the flashed gas as high as 16 mole%. Development Strategy Continued expansion of suburban and agricultural areas over the years has made the development of Qatif field particularly challenging. Stringent safety guidelines are being followed to develop the field while taking advantage of proven technologies. The potential drill sites were thoroughly scrutinized and approximately 45% were rejected due to safety concerns. Saudi Aramco's safety standards permitted drilling activity on a few drill sites only during a certain time window due to the dynamic nature of the development project. To improve drainage and lower the number of required wells, most of the development wells are horizontal completions. Loss of some drill sites due to safety concerns necessitated extended reach wells to effectively drain parts of the reservoirs overlain by populated areas (Fig. 2). Extended reach drilling will also be utilized to access some offshore areas of the field from drill sites along the coastline to minimize offshore facilities. In the environmentally sensitive area of Qatif field additional safety measures have been put into practice while drilling wells. However, this paper will highlight safety measures and use of technologies related to production practices in the following areas:Well clean-up and testing Corrosion control measures for wells Remote data acquisition Automation Proven technologies are being utilized to minimize the impact of oil well clean-up operations on environment, remote emergency shut down, minimize well interventions for routine data acquisition and remote well testing and control.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.71)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.54)
Abstract The Bahrain field is an asymmetrical anticline trending in the North-South direction. The field was discovered in 1932. The field is a multi-stack carbonate and sandstone reservoirs most of them oil bearing. The fluids range from tarry oil in Aruma zone to dry gas in the Khuff zones. The geology of the field is extremely complex with a large number of faults especially in the Wasia group formations, which contain the major oil reservoirs of the Bahrain field. These reservoirs are at different stages of the production cycle. Following a 3-D seismic acquisition campaign in the year 2000, Bapco took up an integrated study to develop numerical models as the main tool to assess alternative production mechanisms. This integrated study faced a significant number of challenges, which had to be overcome with innovative ideas. The challenges included representing communication between reservoirs through faults, complex rock and fluid distribution from heavy oil to gas condensate, gas injection, aquifer encroachment and fracture intensity. Although the hardware required for handling the large simulation models was meticulously selected based on benchmark data of the various machines, the geological complexities posed serious problems while running the simulation models. This paper describes the challenges faced by the joint Bapco-CGG team and the approaches adopted to overcome these challenges. Introduction Bapco decided in 1999 to perform an integrated study encompassing all the oil and gas reservoirs of the Bahrain field (Figure.1), as part of an improved oil and gas asset management strategy. This study, involving 17 reservoirs (Figure.2), is most likely one of the largest single integrated study ever conducted by a company. Such performance is not a surprise from a company that produces oil and gas since 1932 (the first in the Arab Gulf). The integrated study was performed in two phases. In phase 1 the deepest (gas) reservoirs of Khuff and Unayzah (pre-Khuff) were studied while the remaining fifteen reservoirs (from the shallow zones down to the Arab zones) were studied in phase 2. Phase 2 of the project involved 22 CGG and 18 Bapco staff members. To perform the work 19 main software packages (mostly Unix based) were required and the total man-days in phase 2 were 3500 for CGG staff and 1600 for Bapco staff. Phase 2 involved the evaluation of the following 15 reservoirs: Rubble, Ostracod, Magwa, Aa-Ab, Ac, Mauddud, Cab, Cc, Cd, Kharaib, Arab-A, Arab-B, Arab-C, Arab-D and Fadhili (Figure: 2). The Rubble, Ostracod and Magwa are often grouped in the so-called Shallow zones. The Cab, Cc and Cd are also known as the Nahr Umr reservoirs while the Aa-Ab, Ac, Mauddud, Cab, Cc, and Cd are also known as the Bahrain zones. To address the management issues for these 15 reservoirs, nine numerical models were built and initialized. The history matching has been completed for some models and the others are in progress. During the History Matching process some of the numerical models encompassing more than one reservoir were sub-divided leading to a total of 17 numerical simulation models which are currently being used. This paper presents a brief description of the methodologies and steps involved in the study of these reservoirs and focuses mainly on the challenges faced by the joint Bapco-CGG team in building the simulation models and the approaches adopted to overcome these challenges, during phase 2 study.
- Phanerozoic > Paleozoic (1.00)
- Phanerozoic > Mesozoic > Cretaceous (0.93)
- Phanerozoic > Mesozoic > Jurassic > Lower Jurassic (0.46)
- Geology > Geological Subdiscipline > Stratigraphy (0.94)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Government > Regional Government > Asia Government > Middle East Government > Bahrain Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Bahrain > Awali Field (0.99)
- Asia > Middle East > Oman > Central Oman > South Oman Salt Basin > Nahr Umr Formation (0.98)
- Asia > Middle East > Saudi Arabia > Thamama Group > Kharaib Formation (0.89)
- Asia > Middle East > Saudi Arabia > Eastern Province > Arabian Basin > Widyan Basin > Fadhili Field (0.89)
Abstract How do one ensure consistent work quality and process in a large organization with multiple projects and a wide range of technical staff with various competencies and experience ? A web base Production Technology workflow was developed to meet the challenge. Production Technology work process was mapped, reviewed, validated, improved and integrated with other subsurface related disciplines in field development i.e. Geophysics, Geology, Petrophysics, Reservoir Engineering, Drilling and Petroleum Economics. The web base workflow was then implemented across the organization. Steps taken in the mapping, review, validation, improvement and integration process, learning points and benefits of developing such a system are discussed in this paper. The workflow was categorized into issues identification, term of reference, data acquisition, processing, interpretation, model and archive for all disciplines. Knowledge and experiences of all Production Technologists in the organization was compiled and mapped. A high level workflow was first developed. Points of integration with other disciplines were identified. A "drilled down" process was used to detail out each step until the lowest level consisting of guidelines on each work step. Steps in preparing the workflow consist of:Preparing a high level work flow Appointing each engineer to prepare a specific work - process covering well completion design, material selection, sand control, well flow modeling, completion fluids, cement evaluation, wellhead & Christmas trees, artificial lift, etc. A review process to improve the work flow and formulate the best way to put it in a web base format A validation process with selected projects to ensure all steps are considered and realistic The web site was implemented across the organization Encouraging project teams to follow the work process Learning points includes :in-house experiences are more important with consultants as facilitator to compile and integrate the process fitting workflow of different disciplines in the same categories needs flexibility engineers working on daily business can contribute to corporate initiatives concentrated and focus workshop sessions speed up the process Benefits of the web base workflow includes:a reference point for engineers to perform their job more efficient mentoring and guidance from experienced engineers to young engineers a reference point to quality check work and approve Field Development Plan one point data base to compile work experiences, company standards and previous work reports for reference
- Asia (0.95)
- North America > United States > Texas (0.28)
- North America > Mexico > Tamaulipas > Burgos Basin (0.99)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.99)
- North America > Mexico > Coahuila > Burgos Basin (0.99)
Abstract The Salt Creek Field, located approximately 110 miles northeast of Midland, TX, is a heterogeneous, Pennsylvanian-aged carbonate build-up in the Permian Basin. Successive implementation of infill drilling and improved recovery processes, coupled with effective reservoir management, have led to oil recovery of over 50 percent and expected ultimate recovery as high as 60 percent. Salt Creek field was discovered in 1950 and a centerline water injection program began in 1953. A 40-acre development program was initiated in 1970 and was completed in 1984. The waterflood pattern was also changed from a centerline drive to a field wide inverted nine-spot. In 1985, a reservoir continuity study led to a 20-acre infill drilling program that added over 150 wells, changing the pattern to a five-spot. A miscible carbon dioxide (CO2) flood was initiated in 1993, and then expanded to the underlying residual oil zone. Reservoir management has been a key element in maximizing recovery at Salt Creek. Consistent acquisition and maintenance of appropriate well and reservoir data has allowed detailed zonal tracking of production and injection volumes (CO2 and water). Geologic models, in combination with production logs and production data, have been used to manage and optimize CO2 and water injection at the flow unit level. Effective communication processes have been established between the field operators and the technical staff to calibrate engineering and geologic data with field experience and to enhance real-time decision making. A 3D seismic survey covering the entire field was acquired in 2000 to better define productive field limits and reservoir geometry. Currently, a study integrating engineering and geoscience data is underway to further improve reservoir characterization. The study is expected to result in improved sweep efficiency through better conformance control and additional drillwells to capture unswept reserves. Introduction The Salt Creek field was discovered in March 1950 by the Caroline Hunt Trust Estate #1 J.W. Young well which flowed 2,184 stb/D. The field is located in the southwestern United States, in Kent County, Texas (Figure 1). The field was initially developed on 80-acre spacing. Gas injection pressure maintenance operations began in June 1952, followed by a water injection support program in May 1953. The field axis is oriented northwest to southeast and is about 6 miles long by 4 miles wide. The Salt Creek Field Unit (SCFU), which was formed in April 1952, contains about 12,100 acres. Production is from a heterogeneous Canyon Lime reservoir at a depth of 6,300 ft. The original reservoir pressure and temperature were 2,900 psi and 130°F, respectively, with a bubble point pressure of approximately 1,250 psi. The Salt Creek reservoir contains a light sweet crude with an API gravity of 39 degrees. The Salt Creek field is composed of two main limestone buildups that do not appear to be in pressure communication (Figure 2). The smaller build-up is called the northwest extension (NWE) and the larger is called the south main body (SMB). From 1952 to 1966, production was limited to about 10,000 stb/D by state allowables (Figure 3). Reservoir pressure was maintained during this period by water and gas injection that met or exceeded reservoir withdrawals. Between 1967 and 1972, the allowable increased to 37,800 stb/D, which the field was capable of producing for a short period of time. The field then went on decline, which was mitigated by a drilling program during the 1970's that reduced portions of the field to 40-acre spacing.
- North America > United States > Wyoming > Johnson County (1.00)
- North America > United States > Texas > Kent County (1.00)
- North America > United States > Texas > Midland County > Midland (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.90)
- 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)
- (23 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (3 more...)
Abstract The quantity of direct interest in the flow through porous media is not the properties of the matrix (e.g. grain size distribution) but rather the properties of the pore (e.g. pore size distribution). The determination of representative capillary pressures is of vital important for the mapping of the reservoir fluid distribution. Mercury porosimetry or mercury injection-capillary pressure curves are commonly used to measure the distribution of pores and pore throat sizes. Pore aperture size estimated from mercury injection tests has been used to categorize the rock by pore type, evaluate seals for traps and to explain the locations of stratigraphic hydrocarbon accumulations. In image analysis, the OM (Optical Microscopy) images provide macroporosity information, whereas the ESEM (Environmental Scanning Electronic Microscopy) images yield information on microporosity. Comparison of total porosity determined from plugs indicates that macroporosity and microporosity values based on image analysis match the plug data, confirming the validity of the method. The combination of macroporosity and microporosity data yields pore size distribution and pore shape information that can explain the distribution of physical properties, in particular permeability. Permeability can mainly controlled by the macropore shape in high-permeability samples, and by the amount of intrinsic microporosity in the low permeability samples. In this investigation three pore and port geometric systems have been recognized,Type-1 system that belongs to mud dominated bioclastic peloidal packstone, at the top of reservoir, with good porosity and fair permeability shows large and smooth pores and ports as bimodal, Type-2 system presented in mud dominated bioclastic peloidal packstone / grainstone with fair porosity and low permeability shows moderate to small pores and ports and Type-3 system that has been seen in ploidal bioclastic grainstone and mud dominated planctonic foraminiferal packstone, packstone /wackestone and wackestone with low porosity and low permeability shows small pores and ports as matrix porosity. Introduction Few realistic visual aids exist for envisioning the tortuous paths taken by fluids flowing through porous rock. The distribution of a nonwetting phase, such as crude oil in water-wet rock, can be even more difficult to envision. However pore space in sedimentary rocks is a crucial factor in hydrocarbon reservoir characterization. The size and geometry of the pore are related to variability in grain size, sorting and packing as well as to factors such as the mineralogy and the diagenetic history of the formation. The pore geometry and the pore aperture size that corresponds to displacement pressure can be determined from a mercury injection test. Reservoir engineers and petrophysicists are interested in how permeability and porosity related to pore aperture size and pore aperture size distribution, primarily so they can estimate permeability, whereas exploration geologists have been interested in using pore aperture to evaluation the sealing capacity of cap rocks. The purpose of this paper isDetermination and classification of the deposit by rock types in the reservoir by using Petrographic characteristics and Petrophysical data, Investigation of relationships between porosity, permeability and image (OM and ESEM) analysis and Investigation of the pore aperture size and pore aperture size distribution by using the mercury injection capillary pressure curves and routine core analysis data. The case of study is an upper most Cenomanian Carbonate Reservoir. Plug samples that selected for Conventional Core Analysis (CCAL) have been taken from the core, approximately every foot for horizontal plugs and every meter for vertical plugs. High quality thin sections prepared from sidewall cores conventional by impregnating the samples with Alizarin. The thickness of the core in the reservoir is 28m and the total number of prepared samples is 109 (83 horizontal plugs, and 26 vertical plugs).
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (3 more...)
Abstract 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.
- Asia > Middle East > Kuwait > Jahra Governorate (0.25)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- North America > United States > California > San Joaquin Basin > Elk Hills Field (0.99)
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Basin > Widyan Basin > Wafra Joint Operations Block > Wafra Field (0.99)
- Asia > Middle East > Kuwait > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Basin > Widyan Basin > Wafra Joint Operations Block > Wafra Field (0.99)
- (22 more...)
Abstract The use of a custom-designed water-based drill-in fluid, to minimise reservoir damage and facilitate successful open hole gravel pack completions, was vital to ensure a successful operation and maximise gas production in Rashpetco's Rosetta field offshore Egypt, due to the nature of the producing sand. Prior to drilling and completion operations, extensive laboratory work was conducted including core flood return permeability and formation/fluid compatibility studies in addition to gravel and screen studies. The drill-influid formulation and particle size distribution was optimised to ensure athin, impermeable filter cake and minimal filtrate invasion. The low-solids saturated salt/potassium chloride drill-in fluid system helped stabilise inter-bedded shales while drilling the reservoir section. No losses of completion brine were experienced during the gravel packing operations and gas production flow rates on all the wells drilled in the Rosetta field exceeded expectations without requiring any stimulation. Based on this proven success, the same technique will be implemented onRashpetco's West Delta Deep Marine (Scarab/Saffron deepwater development campaign) to minimise the reservoir damage and maximise production. Introduction The Rosetta field is one of Rashpetco's Mediterranean Sea area gas fields. It lies northeast of Alexandria in a relatively shallow water depth of 65metres. The field is composed of stacked reservoirs which are mainly sand with shale inter-beds. The sand is unconsolidated and highly permeable. The drill-in fluid had to be designed to be non-damaging and, to achieve this, core plugs were required to study the effect of different fluids on there servoir permeability and flow characteristics. Simulated gravel pack tests on unconsolidated core material can be problematic and the results variable and, in this case, the available core samples were fairly poor. However, meaningful data was obtained from the laboratory work conducted and the drill-in fluid was eventually selected on the basis of these tests and on the fluid's excellent track record in major projects. The Rosetta field was developed and completed using a Baradril-n™ low-solids saturated salt/potassium chloride drill-in fluid, which was selected following the core flood study. This drill-in fluid was used successfully to drill the 81/2" reservoir sections in the field with minimum filtrate invasion and maximum shale inhibition which facilitated the successful evaluation of all logging data. The wells showed some initial permeability restriction but this minor impairment cleaned up with continuous production. Geology The reservoir sand beds are unconsolidated, highly permeable and fine to coarse grained. The analysis of wire-line data for the stacked reservoirs showsa well-developed coarsening upward sequence which succeeds the under lying prodelta claystone which can be more than 50 metres thick. This vertical association of lithofacies suggests a delta front environment.Indications of coals / organic material and bioturbation are suggestive of adelta plain environment. Incised channels with very steep basal contact, deltafront bar and slumping are a feature of sand bodies in this setting.
Abstract In this paper, an analytical solution is developed for waterflooding performance of stratified reservoirs with gravitational (bouncy) effects between adjacent layers. The ordering of layers is kept unchanged as obtained from core analysis or well logging or as randomly sampled from a specified distribution (usually a log-normal). Differential equations are obtained and solved for the rate of advance of the displacement fronts in two or three successive layers of decreasing permeability. The locations of the displacement fronts are used to obtain expressions for the time of water breakthrough in the successive layers and oil recovery factor and water cut at the time of breakthrough in the different layers. The effect of mobility ratio, gravity number and the Dykstra-Parsons coefficient of permeability variation on the performance are investigated. Expressions for pseudo relative permeabilities are also derived. Results. from the developed model were compared with those from conventional models that neglect gravity effecys. Introduction The methods available in the literature to predict linear waterflooding performance of stratified reservoirs are grouped into two categories depending on the assumption of communication or no-communication between the different layers. In the case of noncommunicating systems, no vertical crossflow is permitted between the adjacent layers.The method of Dykstra-Parsons is the basis for performance prediction in non-communicating stratified reservoirs. Reznik et al. extended the Dykstra-Parsons method to continuous real-time basis.These models assume piston like displacement in the different layers. El-Khatib applied the Bucley-Leverettfrontal advance theory to noncommunicating stratified reservoirs. A model for communicating stratified reservoirs was presented by Hiatt. This model assumes instantaneous crossflow between layers to keep the pressure gradient the same in all layers at any distance. Warren and Casgrove applied the Hiatt model to a system with log-normal permeability distribution and normal porosity distribution.. El-Khatib presented a closed form analytical solution for communicating stratified systems with log-normal permeability distribution. Hearn used the same model of Hiatt to develop expressions for pseudo relative permeabilities that can be used in numerical reservoir simulation to reduce a 3-dimensional model to a 2-dimensional areal model with average (pseudo) functions for the vertical direction. El-Khatib extended the work of Hiatt to account for variable rock properties other than the absolute permeability and compared performance of communicating and non-communicating systems. All the mentioned analytical models for prediction of waterflooding performance of stratified reservoirs neglect the effect of density difference between water and oil and thus do not account for vertical crossflow due to gravity.. The gravity effect wae ignored to obtain simple analytical solution. In these models, layers are arranged in decreasing order of permeability regardless of their actual location in the reservoir. However, with sufficient vertical permeability present in a stratified reservoir, the advancing water in a high permeability layer tends to crossflow to the underlying oil zone in a low permeability layer due to the density difference between oil and water. The downward flow of water and upward flow of oil due to phase density difference will delay water breakthrough in high permeability layers and increase oil recovery. The waterflooding performance in this case is expedted to be different from that predicted by models which ignore vertical gravitational crossflow. The actual position of layers in the reservoir will influence the waterflooding performance.
- 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...)