With the rapidly increasing costs of field development, one of the many challenges for any green or brown field development is to optimize the number and locations of development wells that would yield maximum sweep efficiency and recovery. A full field simulation model is generally constructed to assist in optimizing the development plans and in many occasions initial well planning is based on fixed well length, well orientation, well spacing, etc., before any iterative sensitivity runs are performed. It is recognized that in most cases, the decision was heavily influenced by a single reservoir property, such as permeability, without considering the effect of other inter-related parameters, such as movable oil volume, fluid viscosity, hydrocarbon pore volume, reservoir permeability-thickness and residual oil saturation. The need to analyze these variables in a structured and logical manner is therefore a challenge to ensure a technically sound decision making process. In this paper a modified approach, based on techniques already established (Molina et al., 2009), hereinafter called "Simulation Opportunity Index" (SOI) is introduced. It provides an innovative view on how a development strategy is addressed, and subsequently forms the basis of well placement optimization. All steps and equations to generate the desired indexes are discussed in this paper. We have successfully utilized industrial geological modeling software to perform the calculations and eventually generate the three main index properties in a 3D reservoir model. Using an in-house well planning tool, we can place new wells to optimize field development. This paper also presents a case study for a major oil field development in Saudi Arabia. Comparison between conventional approach and this modified technique clearly showed an improved field recovery performance.

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.

A major Malaysian offshore oilfield, which is currently operating under waterflooding for a quite long time and declining in oil production, plan to convert as chemical enhanced oil recovery (CEOR) injection. The CEOR journey started since the first oil production in year 2000 and proximate waterflooding, with research and development in determining suitable method, encouraging field trial results and a series of field development plans to maximize potential recovery above waterflooding and prolong the production field life. A comprehensive EOR study including screening, laboratory tests, pilot evaluation, and full field reservoir simulation modelling are conducted to reduce the project risks prior to the full field investment and execution. Among several EOR techniques, Alkaline-Surfactant (AS) flooding is chosen to be implemented in this field. Several CEOR key parameters have been studied and optimized in the laboratory such as chemical concentration, chemical adsorption, interfacial tension (IFT), slug size, residual oil saturation (Sor) reduction, thermal stability, flow assurance, emulsion, dilution, and a chemical injection scheme. Uncertainty analysis on CEOR process was done due to the large well spacing in the offshore environment as compared to other CEOR projects, which are onshore with shorter well spacing. The key risks and parameters such as residual oil saturation (Sorw), adsorption and interfacial tension (IFT) cut-off in the dynamic chemical simulator have been investigated via a probabilistic approach on top of deterministic method. The laboratory results from fluid-fluid and rock-fluid analyses ascertained a potential of ultra-low interfacial tension of 0.001 dyne/cm with adsorption of 0.30 mg/gr-of-rock, which translated to a 50-75% reduction in Sor after waterflooding. The results of four single well chemical tracer tests (SWCTT) on two wells validated the effectiveness of the Alkaline Surfactant by a reduction of 50-80% in Sor. The most suitable chemical formulation was found 1.0 wt. % Alkali and 0.075 wt. % Surfactant. The field trial results were thenceforth upscaled to a dynamic chemical simulation; from single well to full field modeling, resulting an optimal chemical injection of three years or almost 0.2 effective injection pore volume, coupled with six months of low salinity treated water as pre-flush and post-flush injection. The latest field development study results yield a technical potential recoverable volume of 14, 16, and 26 MMstb (above waterflooding) for low, most likely, and high cases, respectively, which translated to an additional EOR recovery factor up to 5.6 % for most-likely case by end of technical field life. Prior to the final investment decision stage, Petronas’ position was to proceed with the project based on the techno-commerciality and associated risks as per milestone review 5, albeit it came to an agreement to have differing interpretations towards the technical basis of the project in the final steering committee. Subsequently, due to the eventual plunging global crude oil price, the project was then reprioritized and adjourned correspondingly within Petronas’ upstream portfolio management. Further phased development including a producing pilot has been debated with the main objective to address key technical and business uncertainties and risks associated with applying CEOR process.

A major Malaysian matured offshore oilfield which is currently under waterflooding has been seen declining in production in recent years. Among various enhanced oil recovery (EOR) techniques evaluated, this field appears to be amenable to chemical EOR implementation. Chemical EOR project requires high capital and operating expenditure (CAPEX and OPEX) and often involve complex logistical and operational challenges in an offshore environment. A comprehensive study and technical road map plan from laboratory to pilot and then to full field reservoir simulation model has been established to reduce the project risks prior to field-scale chemical EOR implementation. For this study, detailed EOR screening and ranking evolution is conducted and confirmed that chemical EOR is ranked high among other EOR techniques and stands for better chance of success techno-economically. Subsequently, all the relevant field examinations to verify the incremental oil recovery from chemical EOR including extensive laboratory experiments such as fluid-fluid and fluid-rock evaluations and pilot tests by single well chemical tracer method were designed and implemented. This paper mainly presents the challenges and the strategies to build a realistic full field chemical EOR numerical simulation model (using CMG's STARS), which include history matching and waterflooding optimization process stages. The work has been carried out to address the best practice workflow for chemical EOR simulation, lessons learned from how to properly prepare and incorporate the chemical input data, identify uncertainties relate to project risks and minimize or mitigate the impact of risks to the project economics. Numerical simulation was utilized along with assisted optimization methods that combine experimental design and artificial intelligence (AI) techniques (using CMG's CMOST) to determine injection chemical concentration and chemical slug size for optimal oil recovery factor and project net present value (NPV). Sensitivity studies were also performed with the reservoir simulation models to determine the impact of effects such as residual oil saturation (Sor) reduction, chemical loss through adsorption, dilution effects on capillary number, salinity and viscosity effects, cooling effects, chemical reactions, among others. The study results show that chemical EOR injection is a technically feasible and economically viable option for this oilfield from subsurface, incremental oil recovery, and facilities stand points. Furthermore, the results of this risk assessment will facilitate and expedite the full field project execution and investment plan in future.

Economically achievable oil recovery factors for offshore fields are typically lower than for similar onshore fields due to larger well spacing, inadequate reservoir characterization and shorter economic field life. The key challenge for mature offshore field development is to leverage on surface and subsurface assets by progressively evaluating field redevelopment opportunities and executing phased projects to mitigate risks. Applying appropriate EOR techniques will help to maximize economic oil recovery and tap the relatively large remaining oil volumes in these offshore mature fields. In addition, the synergies among “making the most of what you have” (facilities rejuvenation, asset integrity, production optimization and production enhancement), infill drilling campaigns, implementation of water and/or gas injection schemes and the design/execution of EOR field development schemes are critical success factors. These highly integrated and risk-based field redevelopment planning efforts have gained momentum worldwide and this paper describes the learnings from a mature oil field offshore Malaysia. For the field under discussion, the current (primary) field development strategy of simultaneous production from multiple stacked reservoirs and continuous optimization of artificial lift will lead to modest oil recovery (30 to 35% average oil recovery factor). After more than 30 years on production and multiple previous infill drilling campaigns, the number of available drilling slots on the offshore platforms is limited, plus there are challenges in reaching attractive bypassed oil targets from existing platform/well locations. New well head platforms and intra-field pipelines are expensive, so the existing well drainage plan is compromised in terms of the number and location of production wells. To achieve the desired step up in economic oil recovery, a field redevelopment plan is required that logically combines various risk-based strategies and value adding components. This paper describes the range of subsurface and field development studies that were required to define an effective field redevelopment plan including EOR (iWAG). Realizing an offshore EOR project with an attractive and robust unit development cost is challenging, especially in the current environment of softening oil prices. This paper also discusses the strategies of defining a field redevelopment plan in this mature oil field through integration/synergy between efforts to safeguard the NFA production (No Further Activity) and additional infill combined with realization of iWAG. It is fully understood that the timing of development project implementation is important for economic value and that it would normally not be prudent to exhaust primary and secondary development options before embarking on tertiary EOR techniques, but a synergistic and risk-mitigation (phased) approach is necessary in these high cost, mature offshore field environments.