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This paper presents a sensitivity study of pattern waterflooding in a giant carbonate oil reservoir in North Kuwait, currently being produced by natural depletion. Fine grid models for different pattern types and well spacing were constructed and used to estimate time to breakthrough, ultimate recovery and production rate for a range of reservoir descriptions and fluid properties derived from core, log and lab studies. The total number of simulation runs necessary to cover all possible combinations was impractically large (close to 800). Consequently, a reduced selection (144) was chosen based on the theory of experimental design to maximise the information obtained. This theory identifies what combinations of input parameters should be chosen in order to provide accurate estimates of the effects of individual factors. Results were analysed using analysis of variance, which indicated the pattern, spacing and description factors which were important, and their effect on recovery. It also gave a prediction of recovery for all combinations of input parameters. Overall the results suggest that recovery is relatively insensitive to pattern type and spacing which implies that the choice of pattern and spacing can be guided by injectivity productivity and the required offtake rate. The results of this study will be used to guide future well placement for the waterflood development of this reservoir. The methodology presented in the paper illustrates the value of experimental design theory for planning and rapidly extrapolating the results of a reservoir simulation sensitivity study to cover additional combinations of input parameters. 1 Introduction A pattern waterflood is being designed for a giant platform-carbonate reservoir in North Kuwait, currently being produced by natural depletion. The waterflood development requires a substantial investment in wells and facilities and optimising the number and location of wells will be key to the success of this project. To assist the design of the development a simulation sensitivity study was conducted to understand the impact of the choice of well pattern and spacing and of uncertainties in description on recovery efficiency and rate. Pattern element models were developed for different well spacing and patterns for simulation using ECLIPSE. A range of generic descriptions was used, representative of the crest and mid-flank areas of the two fields in which the reservoir occurs. These were based on pvt, core and log data and were guided by the available dynamic data. The range of models reflected uncertainties in the description. A sensitivity study of waterflood performance was then conducted. Techniques of experimental design were used in planning and analysing the sensitivities so as to maximise information. 2 Alternative well patterns and spacing Four different patterns are considered: inverted 5, 7 and 9 spot and normal 7 spot. For each of these patterns a range of well spacing is evaluated: 100, 200 and 300 acres/well. Consideration of the number of injection and production wells required to produce a field suggests the following approach to selecting the optimum pattern and spacing:–From a knowledge of the relative injectivity and productivity of wells select the pattern with the appropriate injector : producer ratio (see table 1). Different patterns have different relative numbers of injection and production wells. P. 483^

Black Powder has identified as a significant problem in all areas of hydrocarbon production facilities and transit or export lines. The phrase 'Black Powder' in the oil industry used to describe a contaminant found from wellhead, Gathering Centers and gas export lines. The constituents of black powder are known to adversely affect the efficiency, integrity and reliability of oil and gas production, refining and transportation. Its combines of corrosion material such as Iron sulfide, Iron oxide, Wax, Asphaltene, silt and sands. Its vary from one location to another within the process of the oil and gas production. Its presence in all areas of upstream, midstream and downstream oil and gas production. It's affecting the flow assurance and quality of performance of the facilities from compressors, vessels, tanks, sensors and pipelines and finally impacting the refinery efficiency. Its major problem start to be present recently in oil industry which many different operators have different misunderstanding to overcome these phenomena of the black powder. The paper will be to look at best strategy and solution success to mitigate the problem of the black powder in Kuwait Oil Company from west Kuwait operation facilities to Refinery. It will highlight also roots cause, Impact and prevention plan. It will show how it help reduce gas flaring, minimization facility shutdown, reduce Flowlines leaks, and optimize chemicals consumption in operation facilities which lead to cost optimization.

One of the common methods of reducing or eliminating the emulsion is the use of different chemical demulsifiers depending on the type of crude oil and water cut. This method is widely used in Kuwait Oil Company (KOC) at wellheads and gathering centers (GC). However, some wells have practice increases of demulsifier dosage as a result of increase in water content. Consequentiality, KOC initiated a program for optimization of chemical consumption for water/oil emulsion separation in the surface facilities at West Kuwait. As a result, of one year oil field statistical analysis of crude oil emulsion collected data. The results indicate that there are four oil wells of a different physical property could be very helpful for our study. Such properties include emulsion viscosity, size of water droplets, surface active materials, resin to asphaltene ratio (R/As), emulsion temperature. Over and above the demulsifier efficiency and dosages were evaluating using the calculated emulsion separation index (ESI) and interfacial tension measurement. As a result the oil field laboratory test indicates that the viscosity of emulsion increases to at least from 12 to17% of its original value based on dry condition. The average droplet size distribution near to (1-10) m was highly effect on emulsion stability. Moreover the emulsion behavior was linked closely to the film form around the water droplets that are believed to result from the adsorption of high-molecularweight polar molecules (asphaltene) and fine inorganic solids. There surface-active behavior that makes them good emulsifiers. Also it was found there are a consistent relationship between emulsion stability and relative resin to asphaltene content R/As for all four of the field samples under study. The crude oil of high emulsified water, near 30%, contains low (R/As, 0.84). However, as resins to asphaltene ratio increased the emulsion become unstable and emulsified water decrease up 9 %. This relationship could be used as the method to indicate the more likely oil field areas of strong emulsions and the suitable practical methods for treatment. Also from the well head operating conditions collected data; emulsion temperature, well head pressure, salinity of emulsified water and IFT. From the laboratory bottle test and oilfield crude oil emulsions data. The demulsifiers dosage was predicted using the proposed empirical model. In addition it could be used as a good tool for the new or the incumbent demulsifier evaluation. stabilized by an emulsifying agent, resins, asphaltenes, and finely divided inorganic solids (Kenneth 1988;Elsharkawy et al. 2008). The dispersion of the first immiscible phase droplets into the other phase will increase the interfacial surface area and hence a greater interfacial free energy in the system (Pilehvari et al. 1988, Benayoune 1998, Guo et al. 2006. One of the early emulsion nature observations was conducted by Finga (1995), who characterized emulsions into three major categories namely; Stable, Meso-stable and Unstable, depending on the physi...

Reservoir souring often occurs as a result of secondary recovery using water-flood. Until recently, the mechanisms of souring were poorly understood but it is now possible to quantify and profile the development of sour gas production. The latest understanding of the mechanisms of reservoir souring have been used to model the souring potential of North Kuwait reservoirs, undertaken as part of a process of risk management in field development planning. The Kuwait Oil Company has taken this one step further by interfacing the souring model to a proprietary, state-of-the-art, steady state process simulation package, as part of a wider process of integrated field development. Interfacing a sub-surface souring model to a process facilities compositional simulation has resulted in the ability to assess, with an unusual degree of confidence, the technical and economic effects of reservoir souring on facilities design and operation. This knowledge has been used for the preliminary assessment of options for controlling souring in the future. To assure accuracy, the proprietary process simulation software thermodynamic generator, chosen for its ability to handle hydrogen sulphide, was independently validated by the thermodynamics section of BP Research Centre. This paper reviews the basis of the reservoir-souring model and shows the results obtained in terms of sour gas profiles predicted over a period of time. It then goes on to show in more detail how these results were linked into a process simulation model which was constructed to emulate both existing and future facilities configurations. The paper concludes by showing how the knowledge gained has allowed optimum decision making regarding the materials and equipment of the non-sour service facilities and the safety of operation. In addition, how this knowledge has been used for providing assurance and guidance for the planning of future production facilities.