This paper describes the study of the effect of asphaltene precipitation and deposition on the development of the Marrat field using a compositional simulation model with asphaltene modeling facilities. The model enables the simulation of asphaltene precipitation, flocculation, and deposition including adsorption, plugging, and entrainment, and the resulting reduction in porosity and permeability and changes in oil viscosity and rock wettability. A workflow was established in the study to i) characterize the equation of state (EOS) by analyzing the fluid PVT and asphaltene data from the lab; ii) calibrate the asphaltene model input parameters using the core flood experimental data; and iii) incorporate the EOS and the asphaltene parameters into the full field simulation model. The model was used to analyze the effects of asphaltene on various development scenarios, including depletion and water injection. For each scenario, the following were calculated and analyzed: field performance including production of oil, gas, and water; asphaltene behavior including precipitation, flocculation, adsorption, plugging and entrainment; formation damage and the effect of rock wettablity changes. The results show that the formation could be severely damaged near the producers where asphaltene is more likely to precipitate because of lower pressures (below the asphaltene onset pressure) and longer time exposure to a larger amount of oil. Formation damage could be reduced by flushing away the deposited asphaltene using higher flow rates if plugging is not significant. The water injection scenario with higher injection rate and higher production rate with BHP limit above 6,000 psia results in less asphaltene adsorption, more entrainment, and therefore less deposition. This in turn causes less permeability damage and more oil production. Introduction The Kuwait Oil Company (KOC) encountered the problem of asphaltene precipitation in Jurassic production wells located in producing areas in West and South East Kuwait. In West Kuwait (WK), the Jurassic production is primarily from the Marrat field. Out of about 45 wells in WK-Marrat 50% have a history of asphaltene cleanouts. These wells contribute to around 7% of the total oil production from WK which can amount to as much as 50 Mbbl/d. Here the reservoir pressure (around 9,500 psi) is considerably above the asphaltene onset pressure (AOP) (estimated between 2,000 psi to 4,000 psi). Therefore, there is no likelihood of asphaltene deposition in the reservoir. However, during production as the pressure of the produced fluid inside the tubing goes below the AOP, asphaltenes start to precipitate from the crude. Asphaltenes gradually deposit in the tubing, reducing its diameter, and in the process cause production rates to drop; eventually the well completely ceases to flow. Once this has occurred, the tubing in the well must be cleaned out to restore the well to production. The Marrat reservoir lies in the South Eastern part of Kuwait, within the giant Burgan field complex. It is a carbonate reservoir, existing at an average depth of 11,000 to 11,500 ft, subsea. The reservoir fluid is generally light, ranging in quality between 36 and 40 API degrees. The original oil in place is estimated to be two billion stock tank barrels. The original reservoir pressure at discovery was determined to be 9,650 psia. A log with the average properties of the reservoir is shown in Figure 1. The fluid is known to be asphaltenic 1 in nature, as evidenced by the deposition of asphaltenes in the production strings and surface production facilities, requiring periodic cleanup and treatment operations. In South and East Kuwait, all the wells in the Marrat reservoir were closed from 1998 to avoid further drop in the reservoir pressure, which had already dropped close to the AOP (the present reservoir pressure is around 8,400 psi and AOP ranges from 5,500 psi to 6,700 psi). Further reduction in reservoir pressure below the AOP could cause asphaltene deposition in the reservoir itself and result in formation damage. The decision was made to produce the wells only after a comprehensive development plan for reservoir pressure maintenance with implemented water injection.

Asphaltene precipitation can have profound effects on oil production during miscible flooding, heavy oil recovery, or even primary depletion. Even though asphaltene precipitation and eventual deposition have been known to have strong effects on permeability reduction (Turta et al., 1997;Minssieux et al., 1998), quantitative analysis of the process has not been studied extensively. This paper describes experimental work conducted to study the precipitation and deposition tendencies of asphaltenes within the rock material in the Marrat reservoir, South East Kuwait. Live asphaltenic reservoir fluids and carbonate cores of the Marrat reservoir were recovered and used at reservoir pressure and temperature conditions during core flood experiments. The live Marrat reservoir fluid was fully characterized, and subjected to pressure depletion tests to determine the asphaltene onset point at various temperatures.The results reveal preferential deposition of the precipitated asphaltenes with respect to the rock material. The characterization of the rock materials by CT-Scans had indicated the presence of local occluded porosities. These occluded sites were found to be the main influence on the pattern of deposition seen in the core samples. The study shows clearly that although asphaltenes may precipitate and deposit from the Marrat reservoir fluid, the propensity for permeability damage is in fact determined by the nature of the rock material. In addition, the tendency of the precipitated asphaltenes to aggregate into larger flocs that are generally friable influences the rock damage potential.Handling and treatment of asphaltenic fluids will continue to impact on reservoir operations, project costs and recovery efficiencies. Understanding the nature of asphaltenes and how they impact on the sub-surface behaviour of reservoir fluids will become more pertinent, as global oil demand forces a move towards heavy oils and / or highly asphlatenic fluids.

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This paper discusses the incorporation of Streamline simulation into the Reservoir Management Processes of the super giant Sabriyah oil field. For the Middle East region, streamline simulation has particular significance due to the magnitude of reserves and scale of development. Streamline simulation brings immediate added value, due to its ability to handle high-resolution full three-dimensional models with hundreds of thousands to millions of cells, incorporating large amounts of field and well events over substantial operation periods, be they historical (i.e. history-matching phase), immediate (i.e. on-going) or in the future (i.e. prediction phase). This technology can be used to guide and optimize development strategy. By incorporating streamline technology into existing and new reservoir development planning, we are able to demonstrate significant benefits and added value. This paper will conclude with an analysis and discussion of some of the results accrued from the incorporation of streamline technology in the case under review. These include: This paper also demonstrates where streamline technology should fit within the overall reservoir management processes: Introduction Reservoir management strategies have evolved over the last sixty years, from the days of purely analytic and analog approaches, to the days when computers started to be employed. Currently, numerical approaches solve the multi-dimensional problems associated with fluid flow in the porous media. One significant breakthrough in that path of evolution has been the development of the technology of streamline simulation. The application of streamline (or streamtube) simulation as a tool to aid in reservoir management, has generally found much favor today, in the areas of waterflood performance analysis, geological model screening or ranking, geological model upscaling, and in field-level history matching exercisesl. The essential or main benefit of streamline simulation is the often very dramatic improvement in simulation turn-around time that generally results from simulating very large, often multimillion cell geological models, incorporating highly variable heterogeneities, and a long production history in very few hours (sometimes minutes)2. Such rapid turn-around times have enabled the performance of numerous strategic analyses on candidate assets, at speeds which had previously been considered inconceivable, and most importantly, within the defined hours of a typical working day. This has resulted in demonstrable productivity increases, wherever the technology is properly positioned and utilized.

Coring reservoir rock has been an integral part of any oil & gas operator. With a vertically stacked multiple reservoirs in Kuwait stratigraphy cores are thus taken in various depth ranges from few hundred feet to higher than ten thousand feet. Wireline Coring technology, which has been successfully applied in various parts of the world, was found to be an alternative to cut down on rig time and maintain good quality of cores. Heavy oil shallow unconsolidated reservoir of Lower Fars was chosen to be tested with this innovative technology. This reservoir is as it is challenging for coring due to its highly unconsolidated nature with high intergranular porosity coupled with the issue of gravity settling of heavy oil which limits the individual core intervals. The CorionExpress® technology of NOV uses a PDC core bit which has a wireline- conveyed drilling insert to convert the core bit to drilling mode in matter of minutes. This helps in taking multiple cores with intermittent drilling without the need to take the string out. 140' of core was cut in continuous runs with drilling of intermediate shale and drilling to the final depth of the well successfully without any need to take the assembly out of hole. There was substantial time saving of about 30% in rig operation for coring and drilling even in this shallow reservoir where normal tripping time is much less. Recovery percentage was satisfactory considering the technology was applied without a huge advantage of past experiences and lessons for the conventional coring for the same reservoir. Gaps and lessons learnt indicated further scope to streamline the catcher and bit design for better recovery. It also requires rethink on operating procedures particularly in wireline rig up & rig down and core handling rig up & rig down for time saving. However, each of these factors need to be tailor made to the reservoir quality that is to be cored. This paper illustrates the thoughtful mix of technology, innovative techniques and proper coordination by aligning all concerned has helped in meeting the challenge of coring unconsolidated sand and it's processing to deliver a geologically acceptable core for laboratory studies.