This study reports reservoir geochemistry findings on the Greater Burgan field by a multidisciplinary, multiorganizational team. The major objectives were to determine if unique oil fingerprints could be identified for the major producing reservoirs and if oil fingerprinting could be used to identify wells with mixed production because of wellbore mechanical problems. Three potential reservoir geochemistry applications in the Burgan field are:evaluation of vertical and lateral hydrocarbon continuityidentification of production problems due to leaky tubing strings or leaks behind casing andallocation of production to individual zones in commingled wells. The latter two applications are especially important in many older fields, such as Burgan, where tubing and casing string leaks are a problem. For example, Burgan wells which produce Wara oil up the casing and Third Burgan oil up the tubing need to be monitored for the occurrence of mechanical problems. In this case, the chromatography method adds value by reducing the number of high-cost production logging runs and eliminating the associated lost production. Results from this study showed that oils from the major reservoir units are different from each other, even though the differences are small. Furthermore, a number of wells were identified where mixed oils were being produced because of previous mechanical problems. Both transient pressure testing and distributed pressure measurements provided corroborative evidence of some of these findings. Other data showed that Third Burgan oils were different in the Burgan and Magwa sectors, suggesting a lack of communication across the central graben fault complex. This finding supported the geologic model for the ongoing reservoir simulation studies. Success of the geochemistry project has spawned enlargement of the study, both in terms of size and scope. Introduction This paper describes the results from a joint project by Chevron Overseas Petroleum, the Kuwait Oil Company (KOC) and the Kuwait Institute for Scientific Research (KISR). About 50 oils were analyzed to assess the feasibility of applying reservoir geochemisty in the Burgan field. All analytical work was performed at KISR. Reservoir geochemistry involves the study of reservoir fluids (oil, gas and water) to determine reservoir properties and to understand the filling history of the field. Many of the established methods for exploration geochemistry can be used for this purpose. Reservoir geochemistry differs from other reservoir characterization methods by dealing primarily with the detailed molecular properties of the fluids in the C, -C35+ region rather than physical properties. A review of many of these methods can be found in Larter. Geochemistry techniques have been used to help solve reservoir problems for many years. During this time, oil geochemistry has been applied to the following reservoir characterization and management problems:–Evaluation of hydrocarbon continuity–Analysis of commingled oils for production allocation–Identification of wellbore mechanical problems–Evaluation of workovers–Production monitoring for EOR–Identification of reservoir fluid type from rock extracts–Characterization of reservoir bitumens and tar mats Many different analytical techniques have been used in these reservoir geochemistry studies. One of the most widely used is gas chromatography. When used for oil correlation it is often referred to as oil fingerprinting. In most reservoirs, the oil composition represents a unique fingerprint of the oil, which can be used for correlation purposes. This is an inexpensive method and can be very cost effective when compared to many production logging methods. P. 385^

Prior coarse grid simulation models in the Greater Burgan field were unable to capture the stratigraphically diverse nature of the Wara reservoir, and accurately match the existing historical data, resulting in unrealistic predictions of fluid flow from individual reservoir layers. Most simulation failures are blamed on the inability to correctly model reservoir heterogeneity, rather than problems associated with the data it is trying to match. In reality it is probably a function of both. This paper emphasizes the importance of a systematic review of historical production data to assure the accurate initialization of a simulation model and to assess if a full history match should or should not be undertaken. Not only does there need to be sufficient geologic and engineering detail to accurately characterize the fluid and flow properties of the Wara reservoir, but more importantly issues involving the validity, accuracy, and lack of historic data need to be addressed, before deciding whether a reasonable reservoir model for history match could be developed. The reservoir size, long history, and high production rates of the Greater Burgan field magnify the impact, and highlight the importance of correcting data errors, and recognizing data uncertainty and gaps. Introduction A reservoir simulation model is only as good as the data going into it. Data review and validation is necessary to understand the accuracy and limitations of the data and should always be the first step toward developing a successful reservoir simulation model. Results from a simulation based on inaccurate data may be more damaging to the planning and economics of developing a reservoir than not having a predictive simulation model at all. A systematic review of the Wara production data in the Greater Burgan field identified data problems that have changed prior simulation assumptions about the reservoir character, flow characteristics, and reservoir drive mechanisms. These results will help improve the history match and therefore the accuracy of future development prediction cases. Previous simulation studies in the Greater Burgan field identified the need for more pressure support in the Wara reservoir than what the modeled aquifer could provide. The source of this pressure support has been modeled as fluid influx from the underlying Burgan formation through faults or vertical migration where shale and carbonate barriers between the Burgan and Wara reservoirs may be locally missing. The key to determining the need for this additional pressure support is the assumption that the reported historical production is correct and properly represents the actual volume of fluid produced from the Wara reservoir. Because production data is the primary factor influencing the fluid flow and pressure characteristics in a simulation model it is imperative that this data be reviewed, validated, and updated to be as accurate as possible. The aim of this paper is to show the impact to the initialization of a reservoir simulation model by using reported data without investigating it's accuracy or relationship to historical field practices. Companion papers highlight other aspects of the ongoing effort to characterize the Wara reservoir. Background of the Wara Formation The Burgan field was discovered in 1936 with drilling of the Burgan #1 well into the Wara formation. Several delineation wells were drilled prior to World War II but full scale field development did not occur until 1946 when the first production from the field was exported. Production from the Greater Burgan Field has been primarily from the Wara and Burgan (third & fourth sand) reservoirs. P. 565

This Pawr was selected for presentation by an SPE Prwram Committee following review of information containad m an abstract submittad by the author(s). Contents of the paper, as presented, have not been retiewed by the =ety of Petroleum Eng,neers and are subject to correction by the author(s). The material, aa presented, does not necessarily reflect anỹ itlon of the Society of Petroleum Engmeera, Its o~cera, w members. Papers presented at SPE meetings are subject 10 pub~cafion mtiew by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for mmmetial Purpmaa without the~tten consent of the *lety of Petroleum Engineers is prohibited. Permission to reproduce In print is restnctad to an abstract of not more than 300 tis; hllustratlons may not be copied. The abslract must contain mnspicuous acknowledgment of Mere and by tiom the papr was presented. Write Librarian, SPE, PO. Sax 833836, Richardson, TX 75083-3836, U. S.A., fax Ot -972-952-9435. AbstractIn fluvially dominated delta plain reservoirs, such as the Wara formation in the Greater Burgan Field, characterizing a reservoir's flow properties accurately is essential in developing a sound reservoir model. This is easier said than done. Typically, lithofacies identified in cores are correlated to multiple log suite characteristics. These are then used to help define simulation flow properties in wells. In Greater Burgan, with over fif~years of production, much of the field development occurred before modem diagnostic logging tools became available. Therefore, direct correlation of core lithologies and corresponding lithofacies description to multilog character is not possible in the majority of wells.Relationships discovered between shale volume (V~H) ranges and effective porosity (~to permeability transforms allowed us to apply unique rock properties to flow units or "facies" de fried by the V~H-porosity ranges. These flow facies eliminated the difficult task of trying to predict changing lithologies and lithofacies in wells with limited log traces and no core.