This paper reviews the case history of a saturated oil reservoir for the past ten years and examines the EOR prospects. The reservoir is overlain by a thick gas cap and underlain by an active aquifer and thus producing by a combination of gas cap expansion and water drive with slight contribution by solution gas. Material balance calculations indicated that the water drive is becoming more active. However, the study suggested that the oil band has not migrated into the gas cap as yet. This is possibly due to the presence of less permeable shaly lime stringers in the reservoir. If the pressure decline continued causing enough pressure differential for these stringers to break down, the oil band may move into the gas cap and some of it may be lost as irreducible oil saturation. To offset this, gas injection followed by recycling is found the most suitable method to recover the reserves efficiently. This process may find application in reservoirs of a similar nature wherever a sufficient gas source exists.

Geochemical data of oil integrated with geological and engineering data have contributed to an understanding of the mechanism and relative timing of hydrocarbon emplacement in shallow oil zones (Rubble, Ostracod & Magma) of Bahrain's Awali oil field. These zones contain heavy as well as light oil. It is observed that the different oil types reside in different reservoir compartments. To efficiently develop and produce from these reservoirs, it is required to know the current distribution of the oil types and whether they result from different charging histories (gradations developed during initial or late stage migration) and or post-emplacement alteration (i.e. water washing, biodegradation, gas stripping, gravity segregation or de-asphalting). The primary objective of the study was to determine the vertical and lateral continuity of the reservoir intervals to geographically identify areas for development drilling and EOR processes. A geochemical study involving an advanced gas chromatography technique was used which included:comparison of abundance of "inter-paraffin peaks" between the different oil samples,determination of the magnitude of the compositional differences between the oil "Star Diagrams" and "Cluster Diagrams", and"Slope Factor Analysis" where the relationship between molar concentration and molecular weight (carbon number) are compared between the oils. The Geochemical evaluation provided compositional data that helped to:Characterize the difference between the oils.Verify reservoir compartment-talization.Reveal the level of biodegradation, charging fluid type andrelative charge histories for the different fluid types.Identify the geographical distribution of the different fluid types and their relation to potential migration pathways (e.g. faults). In addition to providing information concerning the lateral continuity within specific reservoir intervals and vertical continuity between intervals, the geochemical data also indicate three charging events with oils of differing thermalmaturity:Primary: Charges of extremely immature oil wereintroduced along a nearly linear path which traverses the field from SE to NW. These lines could be the major fault (N-S) and fractures providing initial migration paths.Secondary: Oils of increasing maturity (mixtures of light& heavy oil) were introduced progressively, as the basinsubsided and the oil source matured. It is possible that the light liquids condensed from gas at the sites where theypresently occur, the oils acting as a stripping liquid.Tertiary: (Emplacement of highly mature oil). Thisprocess has occurred predominantly in the Mauddud oil bearing formation, produced primarily close to the perimeter of the field. Back Ground on Geochemical Techniques to assess Reservoir compartmentalization The geochemical approach adopted in the study is based on well established proposition that oils from discrete reservoirs tend to differ from one another in composition.[1–5] These compositional differences exist for one or more of the following three reasons:Processes like biodegradation, water washing, and evaporative fractionation that affect oil composition after oil enters a reservoir.Oil composition expelled from a source rock changes as the source interval is progressively buried and the thermal maturity of the source and the generated oil increases.More than one source rock (or source facies) may contribute oil to an accumulation.

Summary. Crestal gas injection has been used since 1938 for pressure maintenance in a preferentially oil-wet reservoir in the Bahrain field. This paper updates the gas injection history through July 1984, presents the benefits of gas injection, and discusses the finding that recovery in the gas-contacted area was greater than in water-invaded blocks. Introduction This is an update of two previous papers by Cotter and Shehabi. The Mauddud is the major oil-producing reservoir of the Bahrain field situated in an anticlinal feature of the Middle Cretaceous period. This is a highly undersaturated, low-dip, and preferentially oil-wet reservoir. Crestal gas injection has been used in the central block of the reservoir since 1938 for pressure maintenance, making it the first improved recovery project in the Arabian Gulf region. Numerous low-relief faults place the prolific Mauddud in juxtaposition with overlying, and underlying reservoirs. This provides additional production outlets for fluids. Initially, 0.2 PV of rich Arab-zone gas were injected from 1938 to 1973; this has been followed by lean Khuff gas. As of July 1984, 77% of the productive central block had been contacted by gas: the volumetric contact is 32%. Recovery in the contacted block is by a combination of gas drive and gravity drainage, whereas in the noncontacted north and south blocks, it is by water drive. Performance to date indicates much higher recovery in the Performance to date indicates much higher recovery in the gas-contacted central block than in the water-invaded north and south blocks. Reservoir analysis, including simulation, indicated improved oil recovery with higher gas injection. Accordingly, gas injection rates were increased by 40%, and more recently, an aggressive workover program was initiated to lower perforations and reduce free gas production. This has resulted in a rise in reservoir pressure, thus production. This has resulted in a rise in reservoir pressure, thus reversing peripheral water encroachment and maintaining oil production with no decline since mid-1983. As a result of the attractive response to gas injection in the central block. gas injection will be initiated soon in both the north and south blocks. This paper, while reviewing the gas injection history, presents the benefits of gas injection and describes the methods used to calculate the recovery factor in both gas-contacted and waterinvaded areas. Geology Lithologically, the reservoir rock is moderately soft to hard, fine-to-medium grained, fossiliferous. detrital, clean limestone. Much of the original rock has been altered by recrystallization and leaching. Leaching resulted in the creation of vugs and interconnecting channels. This makes the Mauddud formation an excellent reservoir with high porosity and uniform permeability. The reservoir has a porosity and uniform permeability. The reservoir has a fairly uniform thickness, averaging 110 ft [33.53 m], all of which is considered net pay. This reservoir is a highly faulted. elongated anticline with dips as low as 5 degrees [0.09 rad]. There are numerous faults in the crestal area with fewer on the flanks and on the north and south plunges. The displacement of the majority of the faults is less than 30 ft [9.14 m]. Because the thickness of the reservoir is 110 ft [33.53 m], it is in juxtaposition with other zones across the faults and possibly in communication with them. Fig. 1 is a structural possibly in communication with them. Fig. 1 is a structural cross section drawn cast/west across the reservoir. The two major faults with displacement above 50 ft [15.24m ] separate the central block from the north and south blocks. These faults, plus the extended distance from the crestal injection location. prevent the expansion of the gas cap into these remote areas. Reservoir Characteristics Rock Properties. Rock and fluid properties of the reservoir were reported earlier by Cotter. Essentially, he reported the average porosity and permeability as 25% and 40 to 60 md, respectively. There are no impermeable intervals to affect vertical permeability. Shehabi concluded, from laboratory investigation of preserved cores, that the reservoir is preferentially oil-wet. Because of the very rare occurrence of an oil-wet system worldwide, serious doubts are expressed and deliberated whenever such data are presented. To reconfirm the earlier observations, new laboratory studies were conducted recently for wettability determination. This time the studies were made on "fresh" (not cleaned before testing) core samples by Aniott's method. The results indicate a wettability index to oil of 0.60 and to water of 0.002. JPT P. 363

Bahrain field, discovered in 1932, is a highly faulted asymmetrical anticline trending in North - South direction (Fig.1). There are as many as seventeen oil producing and three gas producing reservoirs within Jurassic to upper Cretaceous formations apart from the Khuff gas zones below in Permian limestone formations (Fig-2). These reservoirs occur with divergent lithology, rock and fluid properties. Some of them are saturated while some are highly under saturated. Some of them are oil wet and some water wet. They operate under various drive mechanisms and pressure maintenance schemes. Gas injection in Mauddud, which is one of the major oil producing zones in Bahrain field, has been in operation for the last 65 years. Gas injection in Arab-D is in progress from 1986. Pilot peripheral water injection is in progress in wara sands in NE area of the field since 1995. Additionally, different production mechanisms like gas lift, pumping and stop cocking for GOR control is applied. The field being mature and structurally complicated naturally demands an integrated approach for effective reservoir management to ensure maximum recovery. Due to application of diverse reservoir management techniques, reservoir characterization, Geo statistical application for anisotropy and increased accuracy for simulation, the field has been producing with minimum annual decline (Fig-3). By integrating the Geological, Seismic and reservoir / production data the productive limits of various reservoirs have been extended adding substantial reserves. This paper briefly discusses the approach adopted in the effective reservoir management of this giant mature oil field. Introduction Bahrain Field is one of the largest oil and gas fields in the world. The field has been on production for the last 70 years and has produced around 20% of the initial oil in place. Currently about 400 wells are producing from fifteen reservoirs. The effective reservoir management techniques which include Development Drilling, active work over operations and applying new production enhancement projects have provided the road map to success in arresting the decline rate. Data acquisition and analysis was the key to all the methods applied in Bahrain field (Fig-4). A program called Petro vision was utilized in computerizing the data from all the 700 wells drilled so far. Seismic data, reservoir rock typing and formation evaluation has given valuable insight into reservoir performance and future well work opportunities. The reviews also highlighted the need for development of certain marginal shallow reservoirs and location of infill wells in certain areas in view of the inadequate drainage due to geological complexities. This made it necessary to drill more wells and initiate some IOR techniques for some of the zones. The field is now under active development program and several wells are being worked over for zonal changes and GOR control. Dual Strings (shallow zones in short string &Bahrain zones in long string) completions have also aided in developing the shallow zones, which were not, developed thus far due to poor economics. With reserves gradually adding up from new areas, it is required to continue the current development not only within the known productive limits but also in the extended areas. At this stage, the suitability of Horizontal Drilling was evaluated for two reservoirs and found successful. This is leading to efficient exploitation of reserves and improved economics for development. Further, it is also planned to initiate Improved Recovery pilot projects soon to evaluate and assess the suitability of these techniques for Bahrain Field. By these methods, it is anticipated that some more oil now classified as "Hypothetical", may also be recovered in addition to the currently estimated remaining reserves.

This paper describes how the fracture model for Ahmadi was incorporated into a single and dual porosity simulation model. It highlights the approach and methodology that has been used for understanding the reservoir connectivity and its drive mechanism. In addition, the effect of dual porosity model in improving the initial history match of the reservoir performance and its recovery mechanism has been studied.The two Ahmadi carbonate reservoirs in Bahrain Field (Aa and Ab) are thin, highly faulted and irregularly-fractured. The complexity of these reservoirs has prevented an efficient recovery with average production of wells to 15 Bopd. This has prompted a detailed integrated study to fully understand the recovery mechanism and to increase the wells' productivity.A conceptual model has been developed for the reservoir connectivity of Ahmadi reservoirs by integrating static and dynamic data. This comprehensive study that integrates transient welltesting and production data with cores and image logs to map fracture network derived using seismic facies has resulted in improving the understanding of reservoir connectivity and flow mechanism. This was accomplished by building Discrete Fracture Model (DFN) that was tuned and validated using sector local well test models to match KH and pressure responses.In order to reduce uncertainties in the model, different scenarios were built for different fracture intensity and aperture to derive appropriate parameters to pass to reservoir simulator for full field simulation. DFN model output was used in both single and dual porosity models to obtain production performance of the reservoirs.