Fractured Reservoir Characterization Using Dynamic Data in a Carbonate Field, Oman
- Sait I. Ozkaya (Petroleum Development Oman) | Pascal D. Richard (Petroleum Development Oman)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- June 2006
- Document Type
- Journal Paper
- 227 - 238
- 2006. Society of Petroleum Engineers
- 3.3.1 Production Logging, 3.3.2 Borehole Imaging and Wellbore Seismic, 5.1.1 Exploration, Development, Structural Geology, 5.1.7 Seismic Processing and Interpretation, 6.5.2 Water use, produced water discharge and disposal, 5.1 Reservoir Characterisation, 5.1.5 Geologic Modeling, 5.4.1 Waterflooding, 1.6 Drilling Operations, 3 Production and Well Operations, 5.5.2 Core Analysis, 5.5.8 History Matching, 5.8.7 Carbonate Reservoir, 5.5.3 Scaling Methods, 4.1.5 Processing Equipment, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.1.2 Faults and Fracture Characterisation, 5.6.4 Drillstem/Well Testing, 1.14 Casing and Cementing, 4.3.4 Scale, 4.1.2 Separation and Treating, 5.5 Reservoir Simulation
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The main objective of this study was to extract fracture data from multiple sources and present it in a form suitable for reservoir simulation in a fractured carbonate field in Oman. Production is by water injection. A combination of borehole image (BHI) logs and openhole logs from horizontal wells revealed that water encroachment occurs mostly through fracture corridors and appears as sharp saturation spikes across fracture clusters. Dispersed background joints have little flow potential because of cementation, lack of connectivity, or small size. Image logs indicate that fracture corridors are oriented dominantly in the west/northwest direction. Most of the several injector/producer short cuts are also oriented in the west/northwest direction, supporting the view that fracture corridors are responsible for the short cuts.
Flowmeter logs from vertical injector or producer wells intersecting a fracture corridor show a step profile. A comparison of the injection or production history of wells with or without a step profile provided a means to calculate permeability enhancement by fracture corridors. The field has more than 300 vertical wells and nearly 20 horizontal wells, which allowed us to generate detailed fracture-permeability enhancement and fracture-corridor density maps based on injector and producer data, short cuts, mud losses, openhole logs, and BHI logs. We also were able to build stochastic 3D fracture-corridor models using corridor density from dynamic data and orientation from BHI logs and seismic data. Fracture-corridor length and width were tied to fracture-permeability enhancement using wells with both image logs and production data. The fracture-permeability enhancement maps were verified independently by waterflood-front maps. Notwithstanding the uncertainties, the fracture data were sufficiently accurate and detailed to generate both single- and dual-porosity simulation results with good field-scale history match.
The field was discovered in 1968 in Oman (Fig. 1). Production is from the Shua'iba and Kharaib reservoirs of the Lower Cretaceous age. The Kharaib is a poorly bedded stack of repetitive shoaling cycles. The Shua'iba reservoir consists of a deepening upward sequence. The thick-bedded massive Lower Shua'iba-B gives way to the well-layered Lower Shua'iba-A and Upper Shua'iba units. The Kharaib and the Lower Shua'iba are separated by a horizon of tight argillaceous limestone (Hawar or Kharaib-K1, Fig. 2). The Shua'iba reservoir is directly overlain unconformably by Paleocene Umr er Radhuma in this field.
The field consists of two low-relief eastern-A and western-B domes. Both the Kharaib and Shua'iba units are oil-bearing in the A and B fields. The A structure is subdivided into northern and southern fields. The southern field is located on a west/northwest fault zone through the southern flanks of the A field (Fig. 3). A major west/northwest graben connects the A south to B. Another major fault zone is located on the northern flanks of the A field.
Production from the field started in 1976. Waterflooding was started in 1986 following a series of pilot projects. The original development involved waterflooding by means of an inverted nine-spot vertical well. Soon after the initiation of the waterflooding program, early water breakthrough made it clear that the field was more faulted and fractured than originally anticipated. The drilling pattern was subsequently changed in 1994-95 to a vertical line drive oriented parallel to the dominant northwest/southeast-trending fault/fracture pattern, following an assessment of 3D seismic faults and fractures, fault cutouts, BHI logs, and early production data (Arnott and Van Wunnik 1996).
The fractures and faults of the field were studied repeatedly before and after the drilling pattern was converted from an inverted nine-spot pattern into a vertical line drive. Approximately 37 BHI logs were obtained from horizontal wells, which provided valuable information and paved the way toward a comprehensive understanding of fractures. The present study is the latest phase in the ongoing appraisal of fractures, which is aimed at approaching a more predictive fracture model by integrating previous findings with all available BHI logs and production and seismic data.
|File Size||3 MB||Number of Pages||12|
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