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S umm a ryThis paper describes a field study of a faulted, fractured, and multi-layered carbonate reservoir witti 17 years of production and pressure bistory from 59 Wells . The reservoir is supported by an extensive aquifer that bas been sweeping the hydrocarbon from bath the bottom and the edge . Early water breakthrough and rapidly increasing water cut bas been a major problem in many of the weila . The major objective of [bis study is to understand Huid movement in this complex multi-layered reservoir system, to locate the hydrocarbon that is trapped or unswept, and to recover' it in an optimum fashion . The field is currently producing at an average water cut of 84%. Three infill Wells have been drilled on locations recammended by the simulation, and veere found to be at their initial water saturation as predicted by the model .

Downdip versus updip gas injection options have been evaluated for a deepwater multi-reservoir development discovered and appraised over the last few years. At the time of the study, the development plan called for gas injection in the Alpha field until gas export to the mainland became available. The name of the field has been changed to preserve confidential data. The depositional model of the Alpha field envisages stacked turbiditic channel systems meandering from east to west. The field is tilted approximately 30 degrees north-south due to post-deposition tectonic movement. As a result, the apex region of each meandering channel may form attic-traps that can only be swept by a fluid lighter than oil. Whilst downdip gas injection offers the potential of recovering the oil in these attics, it also carries the risk of gas over-running towards updip producers causing excessive gas production. A study was performed to assess various gas injection scenarios using 2D and 3D reservoir simulation. A simple model utilising a single channel at various dip angles was built prior to any detailed simulation to study fluid movements and demonstrate proof of concept. Fully integrated geological sector and full-field models were then constructed using an object-based modelling technique to assess downdip and updip gas injection options in multiple equiprobable stochastic realisations. The study concluded that counter to conventional thinking, downdip gas injection both delays gas breakthrough and recovers more oil in this reservoir. These benefits were the result of: Downdip injection scenarios offering greater opportunities for gas solution in the highly undersaturated oil prior to accumulation at the crest;Increased offset between producer and injector.Displacement of trapped oil in tilted-channel attics improving sweep; Based on the outcome of this study, downdip gas injection was integrated into the development plan. Later developments in the project enabled gas export from first oil, rendering gas injection unnecessary.

The understanding of residual saturation in an oil field in mid-development is essential for estimating the cumulative production achievable, optimizing the future production mechanisms planned for infill targets, development of adjacent reservoir levels and optimizing the design of future facilities. The ACG (Azeri, Chirag, Gunashli) field is a giant oil field located about 120 km offshore in the South Caspian Sea, Azerbaijan. The field consists of multiple stacked clastic reservoirs including the Fasila and Balakhany formations, each with variable oil water contacts, and variable presence and fill level of gas caps. The Fasila reservoirs have been nearly fully developed. Both down flank water injection and crestal gas injection have been employed to drive oil towards producers. These two processes result in different residual oil “trapping” mechanisms which have been explored by logging and coring. Future development of overlying reservoirs can be optimized if we understand the effectiveness of these mechanisms to improve oil recovery and understand produced fluid compositions to enable facilities optimization to handle them. Established techniques to measure the residual oil saturation in a live field depletion, such as conventional open hole logging, pulsed neutron logging and direct core measurements have been employed. This paper investigates the methodology of each technique and the comparison of the magnitude and uncertainty of the saturations obtained. The sands in the ACG main reservoirs are relatively massive and high Net-to-Gross (NTG), however their clay content and distribution is quite variable leading to a range of rock types which behave differently under fluid sweep, and the presence of both intra reservoir sealing shales and lateral sand quality variations lead to a complex pattern of sweep behavior. It was considered that conventional core would be the principle measurement, with the most direct estimation of downhole fluid conditions as well as achieving all other coring objectives. Core was acquired on two pilot wells, one behind the water flood front and another behind the expanding crestal gas cap. Several innovative core analysis techniques were employed. A full conventional log suite was acquired in both wells as well as an open hole pass of a multi detector pulsed neutron log in the crestal gas swept well. The analysis of all this data has led to some interesting conclusions. Previous core flood experiments had led the team to believe gas is more efficient than water in terms of lowering residual oil saturation and reaching higher recovery factors. The new core demonstrated that such low residual oil saturations are achieved more slowly than originally thought, though it didn't change the view of efficiency of gas displacement relative to water. It is also likely that reservoir heterogeneity has had a bigger impact on the variation in residual oil saturation between layers than reservoir quality itself.

An automated modelling process for rapidly evaluating differing multi-field development production strategies under geological uncertainty has been developed. We demonstrate the use of the technique on the Charlie, Alpha, and Bravo (CAB) fields lying in deepwater, offshore Angola. The names of the fields have been changed to preserve confidential data. CAB is a planned clustered development with all CAB reservoirs producing back into a single Floating Production Storage and Offloading (FPSO) vessel. Due to a challenging seismic environment causing considerable geological uncertainty, stochastic modelling was used to populate reservoir models bounded by seismically interpreted deterministic channel system surfaces. The CAB team developed a systematic modelling workflow combining static and dynamic data for simulation using a multi-field reservoir simulator. Evaluating each new geological model was a manual process taking up to 10 days. To accelerate the modelling process, the entire workflow was automated and BP's Top-Down Reservoir Modelling (TDRM™) philosophy and toolkit (Williams et al., 2004) was used to investigate the affect on hydrocarbon recovery of different possible geological models. Automation involved generating stochastic geological realisations for each CAB field and simulating simultaneous production from all three fields with reinjection of the produced gas. Up to 30 different multi-field simulations could be generated and simulated every 24 hours, with the workflow using 10 CPUs Approximately 700 multi-reservoir simulation runs (2100 individual reservoir simulations) were conducted within a two month period. By automating the workflow, more time was available for evaluating simulation results and less time was spent preparing data and running the simulations. The automated workflow has been used to decide FPSO capacities and to gain confidence that the Charlie field could take all produced gas without flaring or significant loss of production. The workflow continues to be used to quantify the effects of geological uncertainty on different gas management strategies. Introduction There have been many studies over the past decade which investigate the affect of uncertainty on predicted performance and net present value (NPV) of single reservoirs (Friedmann 2003, Hoffmann 2006, Campozana 2008). There are further studies which extend the approach to look at the effect of uncertainty on managing multiple reservoirs (Kabir 2005, Cullick 2007). Broadly, these papers deal with some combination of reservoir flow uncertainties, surface facility uncertainties and/or economic uncertainties. Where attempts have been made to integrate both facilities, wellbore and reservoir performance, it has often been required to include a simplifying step either by using a spreadsheet instead of specialised software (e.g. Rodriguez et al. 2008) or by generating a proxy model to avoid using a fully integrated simulator (e.g Friedmann 2003). In this paper, we look at the effect of geological uncertainty on multiple reservoir performance using the specialised geological properties software and reservoir flow simulation software which would normally be used for a single deterministic study. CAB is an 'ultra-deepwater', offshore development consisting of the Charlie, Alpha and Bravo fields. All gas produced from all three fields is expected to be temporarily injected into the Charlie field for approximately 3 years until full gas export to the Angola Liquefied Natural Gas plant becomes available. The seismic image of the CAB fields is not clear enough to see the internal architecture of each reservoir and so decisions about FPSO capacities and gas management strategies had to take into account the geological uncertainty.