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The Magwa-Marrat field started production early 1984 with an initial reservoir pressure of 9,600 psia Thirty-six (36) producer wells have been drilled until now. By 1999, when the field had accumulated ~92 MMSTB of produced oil and the reservoir pressure had declined to ~8000 psia, the field was shut-in until late 2003 due to concerns on asphaltene deposition in the reservoir that could cause irreversible damage and total recovery losses. The field was restarted in 2003 an it has been in production since then. By April 2018 the field had produced 220 MMSTBO, with the average reservoir pressure declined to 6,400 psia. As crude oil has been produced and the energy of the reservoir has depleted, the equilibrium of its fluid components has been disturbed and asphaltenes have precipitated out of the liquid phase and deposited in the production tubing. There is a concern that the reservoir will encounter asphaltene problems as the reservoir pressure drops further. The objective of this manuscript is to present the process to understand the reservoir fluids behavior as it relates to asphaltenes issues and develop a work frame to recognize and mitigate the risk of plugging the reservoir rock due to asphaltenes deposition with the end purpose of maximizing recovery while producing at the maximum field potential Data acquired during more than 30 years have been integrated and analyzed including 22 AOP measurements using gravimetric and solid detection system techniques, 17 PVT lab reports, 1 core- flooding study and 1 permeability/wettability study. Despite the wide range of AOP measured in different labs, it was possible to determine that the AOP for the Magwa-Marrat fluid is 5,600 ±500 psia and the saturation pressure is 3,200 ±200 psia. Results of this fluids review study indicates that it might be possible to deplete the reservoir pressure below the AOP while producing at high rates. Additional field testing and lab research have been proposed to 1) establish an adequate operating envelop for each well to optimize production and mitigate asphaltene deposition in the tubing to decrease downtime due to coiled tubing cleanouts which will reduce OPEX, 2) Support determination of a suitable reservoir pressure depletion to minimize CAPEX by implementing a pressure support project at an optimum reservoir pressure, and 3) Establish an appropriate field development strategy to produce the field at its maximum potential without jeopardizing the health of the reservoir while optimizing ultimate recovery

Sound development plans are based on complex 3-D 3-Phase multimillion grid reservoir simulation models. These models are used to run different scenarios where probability distributions are included to understand the impact of uncertainties and mitigate main risks that could raise during the life of the field. With today's available dominant supercomputers, reservoir engineers have the tendency to undervalue the power of classical reservoir engineering. However, in a fully connected reservoir tank that honors the basis of the material balance equation, material balance technique has been long recognized as a powerful tool for interpreting and predicting reservoir performance by estimating initial hydrocarbon in place and ultimate hydrocarbon recovery under various depletion scenarios. In brief, under the right conditions, material balance technique is a suitable tool for field development planning. The power of material balance to predict long term performance is undisputable, especially in the case of a prevailing uncertainty. This is the case of the Magwa-Marrat field, where the development plan has historically been driven by the potential risk of asphaltene deposition in the reservoir. The objective of this paper is to show a step by step process to integrate data to build a reliable model using material balance and how this model is utilized to progress a field development plan capable of managing uncertainty and provide the tools to mitigate risk. Pressure data is obtained from repeat formation tester (RFT), static data from shut-in pressures and reservoir superposition pressures from pressure transient analysis. The average reservoir fluids properties are retrieved from a compositional equation of state based on circa 20 PVT studies. The material balance model was successfully completed, and the resulting stock tank oil initially in place (STOOP) was compared to volumetric calculations. Solution gas, rock compaction and aquifer influx were determined as drive mechanisms. The Campbell Plot, diagnostic tool, was proven to be prevailing defining early energy to determine STOOIP and the aquifer properties were calculated by matching the distal energy The material balance model was then used to run different development strategies. This methodology captured the impact of depleting the reservoir down to Asphaltene Onset Pressure (AOP) as well as below AOP. The model was also used to define the requirements for water injection rates and startup of a water flooding project for pressure support. Additionally, the material balance work was implemented to support reservoir management and to maximize recovery factor. This paper presents an innovative approach of integrating asphaltene behavior from laboratory tests and fluid studies, combined with material balance to screen development scenarios for an efficient depletion plan including water injection to manage asphaltene risks and optimize ultimate recovery. Finally, a fully ground-breaking strategy, not reported earlier to the knowledge of the authors, has been established to manage the perceived main risk in the Magwa-Marrat reservoir.

Magwa-Marrat reservoir fluid is an asphaltenic hydrocarbon, exhibiting precipitation and deposition of asphaltene in the production system including the reservoir rock near wellbore and the tubing. The main objective of this work was to optimize production in Magwa-Marrat wells by remediation of tubing plugging and formation damage. Well interventions were prioritized based on potential production benefit resulting from the removal of productivity impairment. It was required to understand current formation damage in all wells, including those without recent pressure transient analysis (PTA). All PTA tests since 1983 for Magwa-Marrat reservoir were analyzed to determine the different reservoir parameters such as flow capacity (KH), Skin (S), reservoir boundaries, and the extrapolated reservoir pressure (P*). PTA derived permeability was compared to log derived permeability to quality control skin determination. Independently formation damage was estimated using the radial form of the solution of the diffusivity equation for pseudo steady state flow. Once a skin correlation for both PTA vs. Darcy's law equation was derived using out of date well performance, the formation damage for all wells was accessed using current productivity index to identify production optimization opportunities in wells without recent PTA. This work was combined with nodal analysis to separate vertical lifting performance and inflow performance relationship impact on total productivity detriment. Cross plot of PTA derived flow capacity (Kh) vs. Log derived Kh correlates very well with a slope and a coefficient of correlation close to 1.0. This was observed for wells located in the reservoir where there are not heterogeneities near wellbore such as boundaries or natural fractures. For these cases the higher than normally observed estimated skin explained poorer well productivity. After skin values were accessed for all wells, a production gain was estimated, and the wells were ranked based on potential benefit. A stimulation campaign was put in place based on the type of rock, formation damage and vertical lifting performance. Eight (8) wells were stimulated and they delivered approximately an additional 20% production for the field. This work was innovative in the sense that there was not pressure build up tests run prior to the interventions and such, there was not any production deferral. This was achieved by building the well performance understanding on a correlation that required petrophysical description, production rates and estimates of drainage area reservoir pressure.

One of the first sources for formation evaluation while drilling a well is the gas data provided by the mud logging services, that is used increasingly as preliminary real-time reservoir interpretation to identify gas-oil or oil-water contacts, reservoir entry points, lithological changes and other applications. Gas ratio analysis and interpretation is a very valuable formation evaluation tool for geologists and petrophysicists to characterize the hydrocarbon fluid types and rock properties. Gas ratios when used in combination with wireline or logging while drilling tools can help resolve uncertainties that otherwise could only be resolved by testing a well. Jurassic deeper wells (>11000 ft) with a varying pressure regimes, very often the wireline logging or Logging while drilling (LWD) logs are cancelled due to several drilling related complications especially mud gain/loss situations. In these wells, Gas while drilling becomes a very unique and important tool that can provide significant insight into the reservoir properties. The gases liberated from the formation at the surface helps us determine the composition of the reservoir fluids and also provides information about the lithological changes, water saturation, and the mobility of the hydrocarbons contained into the rock. This broad spectrum of hydrocarbons assisted by the surface gas analyzer allows the separation of producible mobile heavy hydrocarbons from water wet zones. This ability to differentiate allows operators to geosteer a horizontal well in thin units of potential reservoirs by avoiding water bearing zones and staying in producible hydrocarbon zones. The end result is the ability to intersect the maximum amount of net pay in the target zones. This paper highlights the case studies from deeper reservoirs of East Kuwait where a surface gas logging system employing a semi-permeable membrane extractor coupled with an advanced GC tracer chromatograph detector has been applied in some of wells drilled in Greater Burgan Magwa Marrat limestone reservoir. Advanced gas logging system was deployed in two vertical/deviated wells to characterize the gas ratios for the different units/zones of Marrat reservoir. The zonation from Gas ratio interpretation was validated with the available wireline logging data before using it for planning the horizontal well. The GWD and LWD were performed independently of each other to determine the effectiveness and reliability of the GWD method. GWD in conjunction with LWD was used for the first time in Kuwait to place a horizontal well in a thin (15-20 ft) layer of a deep Marrat reservoir. Use of realtime Gas ratio data and analysis, successfully helped to complete the well as planned high producer.