A reservoir simulation model, calibrated with 25 years of production history, was used to determine a cost effective reservoir management and production strategy, which optimises future recovery from an oil rim reservoir in the Betty Field, offshore Malaysia. The reservoirs consist of good quality sands in a coastal depositional environment with an anticlinal structure terminated at the crest with a growth fault. The history match confirmed that A6.0 reservoir, unlike all others in the field, which co-exist within a stacked sequence, is surprisingly isolated from the surrounding aquifers. Prior to its premature shut-in, oil production reached 5000 bopd. However, a drastic decline in reservoir pressure caused the evolution of a large secondary gas cap and a steeply increasing producing gas-oil ratio. The recovery factor for this reservoir stands at 25%, significantly less than for the best reservoirs in the field. After more than a decade shut-in, secondary and tertiary recovery methods investigated in this study included dump flooding from adjacent reservoirs, gas re-injection and water injection based on an extensive prior screening exercise. The limited prospective increase in reserves highlighted the need for a technically sound but also financially feasible solution. Since the current facilities were not intended for any pressure maintenance or enhanced oil recovery scheme, a number of technical limits arose due to space and weight constraints on the platform. Furthermore, fluid separation and export constraints had to be taken into account. Consequently the reservoir management plan required a field-wide optimization of the scheduled activities in order to identify bottlenecks in the gas handling capacity. Simultaneously with the model study, shut-in wells' production potentials were re-tested in order to gather additional data and, a water dumpflood pilot was implemented. Introduction and Field Overview The Betty field is located 40 km offshore Miri in the Baram Delta area of Sarawak, Malaysia. It was discovered in 1968, and its production started in 1978. The field consists of 22 stacked reservoirs of varying size and thickness at depths of 7200 to 9650 ft sub-sea. The average water depth is 225 ft. The field is operated by a single unmanned production platform that contains 24 well slots with 48 tubing strings. In the Betty field, some producing reservoirs have experienced high recovery efficiency, while in others the recovery has remained relatively low. One objective of a recent field redevelopment planning study was to investigate and resolve these recovery efficiency anomalies, and to identify areas where recovery could be improved. This is particularly important since, at the present time, no infrastructure such as a compression system or offshore water treatment facilities is available on the platform. Major changes would have to be implemented prior to any secondary or tertiary recovery method and would require economic justification. In addition, existing fluid export constraints, arising mainly from the current regional gas export scheme, had to be taken into account for an optimised field-wide reservoir management plan. A recent full field review[1] confirmed the presence of a strong aquifer drive throughout the Betty field, aquifer energy provided to the reservoirs combined with the favourable mobility ratio resulted in excellent sweep efficiency. However, one of the reservoirs (A6.0) was found to be almost entirely isolated from its aquifer, resulting in no discernible pressure support. It was estimated that the volume of the aquifer was approximately one hundredth of the aquifer in the adjacent reservoirs with about 0.25 billion barrels of water. Material balance as well as history matching with numerical simulation model confirmed solution gas drive as the predominant energy source for this reservoir. Among all the Betty reservoirs, this particular reservoir was considered the only viable candidate for investigation of secondary and tertiary recovery practices. The decision was based on the anticipated recovery targets and the economic prospects of any method for improved or enhanced oil * Now with Shell E&P

A revised Field Development Plan (FDP) for Betty Field was prepared based on a process that was simultaneously sensitive to reservoir and operational constraints and uncertainties. This so called "Optioneering" process was an iterative, multidisciplinary optimization task that generated an action plan based on multiple options developed by reservoir, production, drilling and facilities engineering and ranked by economics. The process specifically involved first generating a series of unconstrained production options, which then considered drilling reach and anti-collision limitations, and finally had the appropriate facilities and regional evacuation constraints imposed. To achieve this, history-matched numerical reservoir models were first run within the framework of an infill well-location optimization software package. Then, drilling constraints were imposed with drilling planning software and facility constraints were included via a surface coupling system for multiple-reservoir models. Uncertainties in the reservoir characteristics and in the facilities/evacuation schemes were addressed by quantifying their impact on the ultimate recovery efficiency. During the optioneering exercise, more than 100 unconstrained options for seventeen stacked reservoirs were identified from the perspective of infill drilling, pressure maintenance by gas injection and/or waterflooding, high pressure gas production, horizontal wells and production enhancement work. Based on typical costs and economic rank, the high potential unconstrained production options for each reservoir were determined. After imposing the drilling constraints, all reservoirs were then coupled to account for surface facility constraints. In the final analysis, five sidetrack wells reaching 12 new drainage points (NDP) over 10 reservoirs were designed. This infill drilling scheme will increase current reserves by 128%. Furthermore, a gas injection scheme identified as the optimum plan for A6.0 reservoir will increase current reserves by 28%. Field wide recovery factor will be improved by 9%. Introduction Oilfield development and management decisions are usually made under high risk and uncertain conditions that stem from both surface and subsurface unknowns. The optimized field and reservoir management can be achieved through successful uncertainty management. Uncertainty management has two main aspects: minimizing uncertainty followed by estimating risks from remaining uncertainty. Minimizing uncertainty reduces the risks and improves project economics. Uncertainty can be managed by integrating multi-discipline multi-scale data and utilizing 3-D numerical models as predictive tools. Then, estimating risk from the remaining uncertainty allows us to make informed investment decisions. An ideal FDP should not only include recommendations for an optimum development strategy with its implementation plan, but the estimated risks involved in executing the proposed plan. So the ideal plan would have two parts: optimization and risk assessment, which are also interrelated. However, ranking and screening of options for the plan should be done only after taking the risk factors into account. Therefore, an iterative procedure is required which generally converges after several iterations. Converging to an optimized field plan involves identifying the best suited activity, and then designing that activity to its optimum level. Final risk exposures for the selected activity are estimated and reported, whereby potentially high risk aspects are known to the implementation team and accounted for in economic evaluations. Generating options, and screening them to achieve an optimum FDP with its associated risks requires an optioneering process.

Most of PETRONAS fields in Malaysia have been producing for more than 20 years. At this advanced stage of depletion, reservoir driving forces are low. Organic deposition, particularly in the near-and-around well bore region and in production tubing, can further reduce the production of oil by restricting the flow passage from reservoir to wellbore. A study to address this issue with a view to rejuvenate the problem wells through laboratory analysis & pilot field implementation was conducted. A unique thermo-chemical system has been developed as an effective tool for 1:Removing the organic deposits near-and-around wellbore and production tubing, henceEnhancing the production from the treated wells. The two components of the system are injected simultaneously into the wellbore through production tubing. Upon mixing, both components will produce heat and reaction products. The heat generated capable to melt and dislodge the organic deposits. While, the reaction products will act as an effective solvents and surfactants for dispersion of organic species. The objective of this paper is to present the result of 4 wells treated by the thermo-chemical system. Well selection criteria based on production profile and well history is described. The implementation technique and a post treatment production gain are also highlighted. INTRODUCTION Crude oil is a complex mixture of various hydrocarbon components. Under reservoir conditions of high temperature and pressure, the crude oil components exist in two phases (liquid and gaseous) under thermodynamic equilibrium with connate water attained over geological times. Heavy hydrocarbon components such as asphaltenes, resins and waxes, which at normal surface conditions are solids, exist in solution, either colloidal or disperse form, in liquid hydrocarbons. Similarly, light hydrocarbons which are in gaseous form under normal surface conditions, exist in solution and vapour forms under equilibrium with each other. When a well is put on production, the produced liquid and gaseous phases (water, oil and gas) are subjected to lowering temperature and pressure along production pathway and as such pass through a continuum of dynamic phase equilibrium. As a result, oil soluble solids (asphaltenes, resins and waxes), water soluble solids (scales) and soluble gaseous start separating out from the produced oil. These separated/precipitated organic solids under favourable hydrodynamic conditions have the ability to agglomerate, grow in size and diffuse from bulk to interphases (rock surfaces and pipe walls) and form deposits. The produced formation fines (sand, silt, clay etc), water borne scales and fine corrosion product can get oil wetted and act as excellent nuclei for the initiation and growth of organic deposit particularly waxes. Therefore, the actual oilfield deposits are composed of organic solids, scales, formation fines and trapped oil. The organic deposit can be predominantly parrafinic or asphaltenic in nature depending upon the nature of crude oil, change of temperature and pressure equilibrium, production rate, etc. The deposition can take place at all locations along the production pathway viz-a-vis around wellbores, in production tubings, surface facilities, flowlines, pipelines and storage tanks. Deposits around wellbore (causes formation gdamage reflected by high skin for the well) and in production tubing, adversely effect the well productivity.

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After producing for more than nine (9) years, many wells in Sudan are suffering from lower production rate and increase in the skin value due to formation (Sand Stone) damage. Only re-perforation technique was used to mitigate formation damage problems; however, the results were not satisfactory.Considered the first time in the history of oil production in Sudan, Some of the idle producer wells in Greater Nile Petroleum Operating Company (GNPOC) operations fields were selected to treat their formation damage problems and to start the first Matrix Stimulation Engineering treatment.The results were outstanding where the oil production rate went up in the well TS-21 from 23 bopd to 1360 bopd. The well is still sustaining the high production rate after one year of treatment. The great success encouraged the implementation of the Matrix Stimulation treatment in different fields like Simber West where the results of the well SW-1 reached from 10 bopd to 900 bopd. This paper discusses the methods used in identifying the Matrix Stimulation candidates and the innovative solution including the lab tests and the chemical work done in order to determine the best fit for purpose chemical treatment to bring the wells back to production and optimize the production trend in the field of Toma South and Simber West. It describes the Matrix Stimulation of the well TomaSouth-21 as an example. Furthermore, it describes the entire lesson learnt from the execution and operation phase Last but not least, it shares the outstanding results and the way forward for the Matrix Stimulation business in Sudan. It gives a good reference and database for the stimulation treatment in Sudan since this paper is the first one to be written regarding Matrix Stimulation treatment in Sudan.