The Windalia reservoir is a 22,000 acre, 600 well oil reservoir with a 25 year waterflood history, complicated by stress induced fracturing and a major pattern realignment. The reservoir recovery performance was studied by an integrated combination of geostatistical, finite difference, and stream tube models. The methodology is an extension of previously published work' to larger and more complex reservoir problems. The basis of the approach is a geostatistical reservoir description derived from well logs and core data. Fine grid 2-D and 3-D models are developed to correlate sweep efficiency as a function of characteristic reservoir stratigraphics. These correlations are translated into fractional flow functions and pseudo relative permeabilities which are used in full field stream tube models and 2-D areal finite difference models. The stream tubes provide recovery calculation and front tracking and the areal model provides a calculation for pressure and well productivity. The methodology provided a reasonable representation of the reservoir and its well histories for an efficient expenditure of labor and computer time. Model construction, well history matching and forecasts were completed in four months, a significant improvement over previous attempts to model this reservoir. Refinement, update and sensitivities continue as a reservoir management process. Introduction The Windalia Sand Reservoir was discovered in 1964 on Barrow Island, which lies about 40 miles off the coast of western Australia. The reservoir is a heterogeneous sandstone, generally subdivided into nine layers. Six lithofacies have been identified from core: flat laminated mudstones, bioturbated sandy mudstones, bioturbated muddy sandstones, bioturbated sandstones, carbonate cemented beds, and carbonate concretions. These lithofacies are complexly interbedded and occur throughout the nine layers. The Windalia was initially developed on 40 acre, 5- and 9-spot waterflood patterns in the late 1960's. There was a general conversion to line drive in 1974 with various infill and realignment projects since that time. There are currently 650 production and injection wells, as shown on Fig. 1, producing 14,000 B/D of oil and 33,000 B/D of water. The reservoir has now produced 240 million barrels of oil from an OOIP estimated to be in the 750 million - 1 billion barrel range. STUDY OBJECTIVE The objective of this project was to derive a history matched model of the reservoir which could be used to forecast infill drilling and workover response and to assist in general reservoir management. During the past 15 years there had been several attempts to build simulation models for the Windalia, all of them unsatisfactory because of the heterogeneity of the formation, the large number of wells, and the various realignment and infill projects which characterize its history. In the current study, the technique of hybrid simulation was used as a means of accommodating the size and complexity of the reservoir, and its history, for a reasonable expenditure of time and cost. P. 627^

The importance of the flow unit approach to reservoir description has been recognised recently, but its application to predict porosity, permeability and water saturation from well logs has not been attempted in previous studies. This Paper describes a genetic approach to reservoir description, which combines lithofacies analysis with discriminant analysis and probability field simulation for the identification and characterisation of flow units on the basis of core and log data. Lithofacies with distinct depositional, diagenetic and petrophysical characteristics, which essentially act as lithohydraulic flow units, have been identified from cores. A set of discriminant functions is then computed using log data from cored wells to identify lithofacies from wireline logs in uncored wells. Each lithofacies has been found by regression analysis to possess a distinct porosity and permeability relationship. The lithofacies‐specific relationships between sonic travel time and core porosity is also established by regression analysis. Porosity and permeability values predicted from regression analysis lack variability when compared to actual core data. Hence, probability field simulation is applied to add fine‐scale variation to the values predicted from regression analysis. The techniques described here can be applied to any type of reservoir. The application of these techniques has resulted in an improved prediction of porosity, permeability and water saturation for a shaly, glauconitic reservoir in the North West Shelf area of Australia, where traditional log analysis has been proved to be difficult to apply.

The Saladin Oil Field is located immediately east of Thevenard Island, 25 km northwest of Onslow, in the Barrow Sub- basin, northwest Australia. Saladin 1, drilled in 1985 on a structure mapped from 1984 and older seismic data, tested 47° API oil at 875 kL/d (5510 B/D) from the Early Cretaceous Barrow Group. Additional shallow- water seismic was shot in 1985 and a Telseis* survey conducted in early 1986 over Thevenard Island and its fringing shoals. Saladin 2 in 1986, and Saladin 3 in 1987, tested at 1745 and 1790 kL of oil per day respectively (10 975 and 11 280 BOPD), setting successive Australian single- zone flow records. The fourth well, Saladin 7, was drilled in 1988 on a 1987 seismic line and tested at 1720 kL of oil per day (10 820 BOPD).The oil occurs in southeast- dipping Barrow Group sands overlain by and upthrown against Muderong Shale across the northeast- trending Saladin Fault. The Barrow Group sands have porosities around 24 per cent and permeabilities averaging 5- 6 darcies. Some claystone layers are present, and carbonate cement reduces porosity but less so permeability in parts of the oil column. A bioturbated sand has low permeabilities due to clay burrow- linings.Oil- in- place is currently estimated at 11 MkL (70 MMBBL). Field development will involve offshore platforms and deviated wells from Thevenard Island, on which oil storage and treatment facilities will be placed, and an offshore loading terminal for tanker transport. First oil production is scheduled for mid- 1989.

The Greater Vanza Longui Area (GVLA) field is located in Area B of the offshore Cabinda, Angola Block 0 concession. GVLA is a multi field development and will target hydrocarbon resources in the Cretaceous Pinda formation that contain reservoirs with rich gas condensates and underlying volatile oil rims. The objective of this paper is to demonstrate the rigorous subsurface evaluation process employed for developing a large offshore gas condensate field. The strength of the reservoir evaluation is the large amount of good quality appraisal data gathered and used to benchmark subsurface inputs. There have been 6 reservoir penetrations, 4 DSTs and 3 full reservoir cores and multiple fluid samples. A structured workflow was followed to identify and incorporate the uncertainties in the subsurface assessment. Probabilistic forecasts helped to fully characterize and realistically assess the uncertainties. The uncertainties were grouped mainly into static and dynamic categories. The impact of the static uncertainties was assessed using 3-D geological models. Geologic models were built upon a core-based sequence stratigraphic framework for the Pinda formation. The facies, petrophysical properties and top depth of reservoir were varied to capture the uncertainty ranges seen in the GVLA wells and analogue fields. These models captured the net-to-gross uncertainty which has the largest impact on hydrocarbons in-place and connectivity. The dynamic uncertainties were assessed using statistical design of experiments. Monte Carlo simulations were employed to generate the probabilistic estimates. Reservoir simulation with the compositional formulation was used as the primary forecasting method. Robust equation-of-state models were built to appropriately quantify natural gas liquids (LPGs) which were value drivers for the project. Various development alternatives (primary depletion, gas injection) were evaluated and detailed economic analysis were performed for concept selection. The production forecasts were verified with material balance models, analogues.

The Greater Vanza Longui Area (GVLA) field is located in Area B of the offshore Cabinda, Angola Block 0 concession. GVLA is a multi field development and will target hydrocarbon resources in the Cretaceous Pinda formation that contain reservoirs with rich gas condensates and underlying volatile oil rims.The objective of this paper is to demonstrate the rigorous subsurface evaluation process employed for developing a large offshore gas condensate field. The strength of the reservoir evaluation is the large amount of good quality appraisal data gathered and used to benchmark subsurface inputs. There have been 6 reservoir penetrations, 4 DSTs and 3 full reservoir cores and multiple fluid samples.A structured workflow was followed to identify and incorporate the uncertainties in the subsurface assessment. Probabilistic forecasts helped to fully characterize and realistically assess the uncertainties. The uncertainties were grouped mainly into static and dynamic categories.The impact of the static uncertainties was assessed using 3-D geological models. Geologic models were built upon a corebased sequence stratigraphic framework for the Pinda formation. The facies, petrophysical properties and top depth of reservoir were varied to capture the uncertainty ranges seen in the GVLA wells and analogue fields. These models captured the net-to-gross uncertainty which has the largest impact on hydrocarbons in-place and connectivity.The dynamic uncertainties were assessed using statistical design of experiments. Monte Carlo simulations were employed to generate the probabilistic estimates. Reservoir simulation with the compositional formulation was used as the primary forecasting method. Robust equation-of-state models were built to appropriately quantify natural gas liquids (LPGs) which were value drivers for the project. Various development alternatives (primary depletion, gas injection) were evaluated and detailed economic analysis were performed for concept selection. The production forecasts were verified with material balance models, analogues. OTC 24108developed using an FPSO for LPG sales, which provided a potential outlet for the discovered GVLA resource. Further appraisal of GVLA in 2008-2010 was completed by drilling the G6, G2 and G3 wells. The results of these wells, and their integration into the new reservoir models removed the geologic risk, reduced subsurface uncertainties, and confirmed hydrocarbon resources similar to pre-drill estimates. Regional GeologyThe GVLA development is comprised of five adjacent Pinda fault blocks. Longui Main is the large horst block on the western side of GVLA; Longui East is a down-thrown graben to the east of Longui Main; 79-B is comprised of a series of tilted and rotated horst blocks that dip to the east; Vanza is a northwest-southeast oriented horst block that along with the 80-E fault block forms the eastern edge of GVLA (see Fig. 2). Oil and gas are trapped by dip closure against bounding normal and listric faults that provide a seal along the boundaries of the individual fa...