The mechanism of two-phase flow through fractures is of importance in understanding many geologic processes. Currently, two-phase flow through fractures is still poorly understood. In this study, nitrogen-water experiments were done on both smooth and rough parallel plates to determine the governing flow mechanism for fractures and the appropriate methodology for data analysis. The experiments were done using a glass plate to allow visualization of flow. Digital video recording allowed instantaneous measurement of pressure, flow rate and saturation. Saturation was computed using image analysis techniques.

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This paper summarizes the approach used for applying integrated reservoir modeling to the tight gas sands of the Pinedale Anticline in western Wyoming. The simulation of tight gas sands such as those at Pinedale has always been challenging because of the high degree of heterogeneity that needs to be retained to replicate reservoir performance, coupled with computing constraints. Added to this, simulating the Pinedale reservoir has its own unique challenges due to its characteristically thick gross sand interval composed of multiple, heterogeneous sand bodies produced commingled in a well.An intensive data-gathering program to investigate optimum well spacing accompanied the simulation effort. A significant part of this program was the installation of pressure monitor wells 1 to detect communication with surrounding producers at the hydraulic fracture stage level. This was coupled with multiple time-lapse production logs. The two data sets together allowed better definition of stage performance at producing wells.Static models were built with fine resolution to duplicate reservoir heterogeneity. However, upscaling was necessary due to computing constraints. The upscaling procedure of Li and Beckner 2 was utilized to maintain substantial geologic heterogeneity. The upscaled model was calibrated to mimic fine scale well performance prior to history matching.Several sector upscale models were history matched using a statistical approach without compromising key aspects such as reservoir connectivity and proper mass withdrawal from each geologic sub layer. Hydraulic fractures in each stage were characterized through history matching. Given the geostatistical nature, an exact match on every frac stage and every pressure gauge located away from the producer should not be expected. Rather, a more statistical definition of a history match should be adapted to a level that still gives confidence in forecasting the value of future infill wells. The history-matched parameters were then statistically distributed to forecast more realistic future development wells.The availability of data including pressures at observation wells and production logs was critical in narrowing the range of uncertainty in the history-matched scenarios and reduced the degree of non-uniqueness in the model thus resulting in increased confidence in model forecasts. This paper describes the methods used to overcome many of the problems encountered in modeling heterogeneous tight gas sands, such as at the Pinedale Anticline.

The oil field is located 40 km offshore Sarawak, Malaysia in the southwestern part of the Baram Delta at a water depth of 250 feet. It is an anticline bounded by two (2) sealing faults and composed of multiple hydrocarbon bearing sand reservoirs separated by sealing shale layers. Oil has been produced since 1972 from more than 10 different reservoir units. Enhanced oil recovery (EOR) redevelopment project in the field will begin in 2018. The project will increase the crestal gas injection and initiate water injection at various locations in the water leg for two (2) major oil rim reservoirs. In a third relatively smaller reservoir water and immiscible gas will be injected in an immiscible Water-Alternating-Gas (iWAG) scheme. Required gas for the entire project will be supplied from five gas reservoirs, as well as by recycling the produced gas from the oil reservoirs. A Well, Reservoir and Facilities Management, or WRFM, plan was put together to prepare the reservoirs for the EOR project and to further optimise the development decisions. This paper outlines the objectives of the WRFM plan for the EOR redevelopment project. Key uncertainties that have an impact on the development plans are highlighted. A summary of surveillance activities required to manage the key uncertainties are given. At the end, focusing on the XE/XF reservoir group, reservoir surveillance required to monitor and manage a mature off-shore oil rim reservoir is discussed. XE/XF reservoir has a large gas cap and surrounded by an aquifer. The oil rim is dynamic in nature, which moved into the gas cap after the start of production due to the imbalance between the strong aquifer and gas cap expansion. For pressure maintenance purposes, as well as to prevent the rise of the oil rim, gas injection into the cap was started in 2001. Most recent saturation logs show that the current oil-water and gas-oil contacts in the field can no longer be regarded as even surfaces. The surveillance plan focuses on monitoring the saturation and pressure changes in the reservoir to locate the current gas-oil and oil-water contacts, and to understand the strength of the surrounding aquifer. The learnings will impact the number and locations of production and injection wells that are planned to be drilled as a part of the EOR project. In addition, the results will be used to update the existing dynamic reservoir model, which will be utilised for long term reservoir management.