Reservoir Simulation in a North Sea Reservoir Experiencing Significant Compaction Drive
- C.C. Cook (Amerada Hess Norge NS) | S. Jewell (Amerada Hess Ltd.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- February 1996
- Document Type
- Journal Paper
- 48 - 53
- 1996. Society of Petroleum Engineers
- 5.5.11 Formation Testing (e.g., Wireline, LWD), 1.14 Casing and Cementing, 5.4.1 Waterflooding, 4.5 Offshore Facilities and Subsea Systems, 4.1.5 Processing Equipment, 5.1.1 Exploration, Development, Structural Geology, 3.3.1 Production Logging, 1.6 Drilling Operations, 5.3.4 Integration of geomechanics in models, 1.6.9 Coring, Fishing, 5.1 Reservoir Characterisation, 5.8.7 Carbonate Reservoir, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.5 Reservoir Simulation, 5.6.5 Tracers, 5.1.5 Geologic Modeling, 4.6 Natural Gas, 5.1.2 Faults and Fracture Characterisation, 5.2 Reservoir Fluid Dynamics, 5.2.1 Phase Behavior and PVT Measurements, 5.6.1 Open hole/cased hole log analysis, 4.1.2 Separation and Treating, 4.2 Pipelines, Flowlines and Risers, 5.5.8 History Matching
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The Valhall field in the Norwegian North Sea is a high porosity chalk reservoir undergoing primary pressure depletion. Over the last ten years there have been a number of computer modelling studies of the field which have all assumed an original oil-in-place of approximately 2000 MMSTB (318.0x106m3). Despite this basic similarity, estimates of ultimate recoverable reserves have increased from an initial value of 200 MMSTB (31 .8x106m3) to the present estimate of 500 MMSTB U9.5x106m3). This increase is partly due to the addition of wells and the optimization of completion techniques. However, the single most important and unique feature influencing Valhall long term production performance is reservoir rock compaction.
Recent simulation studies indicate that over half of the oil produced from the Valhall reservoir is a direct result of the rock compaction recovery mechanism. In the reservoir crest area rock compressibilities can be as high as 150 x 10.6 psi-1 (21 .75x10-6 kPa-1) and it is estimated that compaction contributes over 70% of hydrocarbon recoveries.
This paper describes the mathematical model used to simulate reservoir performance in a compacting reservoir with specific discussion regarding the proportion of oil produced by each physical recovery process. An understanding of the recovery mechanisms and their relative importance is critical for the successful management of the field. This paper also presents an alternative method for evaluating the various recovery processes using a simple solution to the material balance equation. This is used to substantiate the magnitude of the various recovery mechanisms identified in the simulation model.
The Valhall Field is located in blocks 2/8 and 2/11 of the Norwegian North Sea (Figure 1). The field was discovered in 1975 with the drilling of well 2/8-6, and oil production began in 1982. The Field development consists of three bridge linked steel structures including a 30 slot drilling platform.
Oil and gas transportation is via two pipelines to the Ekofisk complex located 21 miles to the northwest.
Estimated oil in place is 1944 MMSTB of which approximately 500 MMSTB is deemed recoverable. Current field production is approximately 55,000 STB/D. Reservoir compaction was first identified in 1986 when subsidence of the surface facilities was detected, consistent with that experienced at a number of older neighbouring fields.
Geology. The Valhall Field is located within the North Sea Central Graben consisting of late Cretaceous age rock. The field structure is an asymmetrical dome with a relatively steep western flank resulting from basin inversion along a large regional fault system, known as the Lindesnes Fault. Figure 2 shows the top of the reservoir at 2400 meters SS depth with a free water level at 2630 meters SS. Although not shown here a structural closing contour of 2900 meters SS has been identified.
The reservoir consists of high porosity chalks in the Tor formation and chalk of lower porosity in the Hod formation. The chalks exhibit large variations in both porosity and permeability. This is partly the result of changing depositional environments, but may also be influenced by diagenetic processes in the form of early cementation and later fluid pressure effects.
In common with a number of North Sea reservoirs, the source rock for the oil is the late Jurassic Kimmeridge Clay. The reservoir cap rock is of Tertiary age, consisting of a series of shale / claystone sequences and these have been termed Lista formation. Although the cap rock provides excellent hydrocarbon liquids containment, there is evidence of gas leakage into the upper layers which complicates 3D seismic data interpretation.
Reservoir zones appear to result from both lithofacies control and diagenesis. Figure 3 illustrates a typical processed well log including reservoir zonation.
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