Newly acquired full azimuth 3D seismic in conjunction with modern azimuthal acquisition and processing, and a fresh review of the regional structural model, has enabled the identification of strike-slip faults with greater certainty. Strike-slip faults are often difficult to identify in traditionally processed seismic due to the lack of vertical displacement. The resulting improvement in structural detail in the geological models has provided a better match with well production, performance and reservoir connectivity in mature Cooper Basin fields. The structural interpretation is independently supported by Pressure Transient Analysis (PTA) and image log data in one of the fields. Field examples are used to demonstrate the observed relationship between strike-slip faulting and hydrodynamic connection. Pressure data supports that fields previously thought to be separate are demonstrated to be connected via strike-slip corridors. Therefore, hydrodynamic disconnect occurs across strike-slip faults. An observed relationship between underperforming wells and proximity to interpreted strike-slip faults is also discussed. The integrated approach combining new full azimuth 3D seismic data with regional structural concepts, well performance and dynamic behaviour has led to the identification of new development and appraisal opportunities in several mature fields. Application of this multidisciplinary approach, including the structural model, seismic interpretation and analysis of dynamic data is recommended for all fields throughout the Cooper Basin with suitable full azimuth seismic data. This process should be embedded in future field development plans.

A detailed material balance study of the Northern Area Deep reservoirs was conducted to address anomalous trends identified from p/Z analyses. The material balance study was conducted using a novel application of Petroleum Experts' MBal software, and determined that previously unrecognised volumes of gas were cross-flowing between reservoirs predominantly behind casing in the wells. The magnitude of the cross-flow volumes significantly impacted well and reservoir performance, but were unable to be modelled or quantified. The approach that was adopted to model the inter-reservoir cross-flow using MBal as a “sub-surface abacus”, whereby injection of gas into the reservoirs was introduced manually to represent influx due to cross-flow. Additional production (on top of allocated produced volumes) was introduced to model the corresponding efflux of gas. Manually maintaining a volumetric balance between the efflux and influx profiles was difficult, but achievable, and provided an internally consistent method to model the complex dynamics of this reservoir system. Detailed simulation studies have been recently conducted on the Northern Area Deep reservoirs and have complemented the findings from this material balance study. The MBal model has been updated regularly with over 6 years of additional production and pressure data, and the model is still holding a good history match. This has provided high confidence in the model's robustness, and validates the adopted methodology, which has broader applications to enable material balance modelling of “non-geological” inter-reservoir cross-flow. The purpose of this article is to present the methods and practices employed in this process and to show how they can be applied to other fields/reservoirs.

With the widespread use of downhole pressure gauges (DHPG’s) to measure and record downhole pressures in oil and gas wells, engineers have been able to eliminate/reduce the wellbore effects that can mask true reservoir response. However, not every well is equipped with a downhole gauge; even fewer have the downhole gauge at the mid-completion depth, leaving fluids below the gauge that are subject to frictional pressure drop and changing fluid density/head due to heating/cooling. The reservoir signal (delta pressure vs time) can be slightly masked or completely overwhelmed by the change in pressure head due to changing fluid density as the well bore fluids cool or heat-up. The resultant measured rate of pressure change will therefore, not be representative of the actual reservoir response. In addition, frictional pressure loss as fluids travel up the well bore can appear as pressure loss due to completion skin. This causes wells to have an artifically high skin. Using raw pressure data that has not been accurately corrected for changing fluid head/density and frictional losses below the gauge can lead to inaccurate pressure-transient analysis (PTA) results (Hasan 1998). This paper will discuss the physics of these processes and explain the reasons for these errors in the PTA results, along with the impact of these errors. Finally, a method for properly correcting the measured pressure to mid-completion pressure will be described. To demonstrate these effects, case studies conducted on two gas wells, a gas-condensate well and an oil well will be presented.

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This paper describes the importance of well construction & well integrity and its relationship to reservoir management. Productivity enhancement studies in combination with reservoir simulation modeling on the Greater Heglig fields have revealed that well performances and production related problems were largely related to poorly designed wells and poor cementing practices. As a result, water channeling and cross flow across wellbore dominated true well performance characteristics contributing to very high water cuts in the majority of the producers in Greater Heglig fields. Separating the mechanically induced well behaviour from reservoir behaviour helped history matching the wells greatly, findings of which were subsequently validated during the study through running of ultra sonic imaging tool. The ultra sonic logging campaign proved the existence of channels, micro annuli's and cross flow across the wellbore causing a "water channeling phenomena" of up to 90% water cut across majority of the wells. As part of the productivity enhancement program for the Greater Heglig fields, a total of 23 sidetrack candidates have now been identified to capture the remaining developed reserves of ca. 30.0 MMstb, which will otherwise remain unproducible from the existing wellbore's. In addition to this, fit for purpose sidetrack well designs and construction together with good cementing practices will be required to ensure well integrity to improve reservoir management of the Greater Heglig fields. Introduction Greater Heglig is one of the major oil fields of GNPOC, Sudan. It was discovered in 1982 by Chevron and was put on-stream in June 1999. Its area encompasses some 380 sq. km, containing 8 producing oil fields with Heglig as the main field (Fig. 1). It holds around 800 MMSTB oil inplace in 2P category. The field was put on production based on the recommendation of FDP. To-date, 61 wells have been drilled in Greater Heglig field. Field production peaked to 64,000 kbopd in 2001. Plateau rate of around 50 kbopd was maintained for three years. It has produced cumulative oil of 123 MMSTB till April 2006 and is currently producing around 40 kbopd with 85% water cut (Fig. 2). Field is in mature stage of its producing life and is facing "Mid-life Crisis" mainly due to higher water cut. This paper focuses on finding out the reasons for high water cut and other field related problems. It also focuses on identifying bypassed oil and suggesting suitable reservoir management plan to improve field recovery. Geological Setting and Stratigraphy Greater Heglig oil field is located in the sedimentary basin of Muglad in interior Sudan. This area forms part of the Cretaceous-Tertiary Muglad basin in south-central Sudan. The basin was initiated as an extensional graben to the immediate south of the Central African Shear zone. An early phase of extensional tectonics led to rapid subsidence and lacustrine basin fills comprising the rich source rocks of the Lower Cretaceous Barremian-Neocomian Sharaf Formation and Albian-Aptian Abu Gabra Formation. The reservoir section in the Late Albian to Cenomanian Bentiu Formation accumulated as widespread sheet sandstones in response to a cessation of active extension and during a period of regional sag. It marks a fundamental change from an internally draining lake basin to larger scale sediment dispersal patterns transporting sediment out of the basin in the north and south. A sudden change from the sandstone-dominated successions of the Bentiu Formation to the shale-dominated interval of the Aradeiba Formation marks the onset of a second phase of extension and increased subsidence during the early Turonian. The Bentiu Formation comprises the main reservoir interval and is characterized by stacked successions of thick, amalgamated cross-bedded sandstones and intervening laterally extensive, thinner mudrock intervals. Sandstones of the overlying Aradeiba Formation are characteristically isolated within an otherwise mudrock-dominated succession. No significant thickening of stratigraphic units across faults is evident in the Heglig area. It is likely that subtle difference in subsidence due to differential compaction across buried grabens and half grabens will have influence on sediment dispersal patterns during Bentiu and Aradeiba times.