Application of Horizontal Wells to a Tight Gas Sandstone Reservoir: A Case History
- R.C.P. Guyatt (Ranger Oil (U.K.) Limited) | J.P. Allen (Ranger Oil (U.K.) Limited)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- August 1996
- Document Type
- Journal Paper
- 203 - 209
- 1996. Society of Petroleum Engineers
- 5.1.5 Geologic Modeling, 1.1 Well Planning, 5.1.2 Faults and Fracture Characterisation, 2.4.3 Sand/Solids Control, 5.6.2 Core Analysis, 4.5 Offshore Facilities and Subsea Systems, 1.6.7 Geosteering / Reservoir Navigation, 2.5.1 Fracture design and containment, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.8.1 Tight Gas, 1.6 Drilling Operations, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.2 Separation and Treating, 1.6.1 Drilling Operation Management, 5.6.4 Drillstem/Well Testing, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.5 Reservoir Simulation, 5.5.2 Core Analysis, 1.12.1 Measurement While Drilling, 1.10 Drilling Equipment, 1.6.6 Directional Drilling
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The Anglia gas field is located in the southern sector of the U.K. Continental Shelf (UKCS) in Blocks 48/18b and 48/19b. The reservoir is contained within the Permian Rotliegendes sandstone and is of small to medium size by U.K. southern North Sea standards. The field is divided into an east and west area with the gas initially in place distributed equally. Appraisal-drilling results indicated that the eastern portion of the field exhibited good productivity, whereas wells drilled into the western area produced at subeconomic rates. Development studies showed that to make the field development economically viable, well rates would have to be increased in the poorer western region. Conventional stimulation techniques were explored, particularly hydraulic fracturing; however, these proved unsuccessful owing to the proximity of the water leg. Attention, consequently, focused on the then emerging technique of horizontal drilling as a means of increasing well productivity. Development of a geologic model identified that the reservoir could be zoned into six reservoir units and that to maximize productivity, placement of the well into the predominantly aeolian zones was necessary. Reservoir simulation studies showed that a minimum 70-ft stand-off from the gas/water contact (OWC) was required to maximize ultimate recovery. This paper describes the analysis methods used and the results of applying horizontal wells in the field development and shows how, at a small cost premium, the method enabled a marginal field to be developed successfully.
The Anglia field was discovered in 1972 with Well 48/18b-1, but the follow-up appraisal well drilled on the flanks of the structure was dry. The perceived field size and depressed gas prices delayed further appraisal activity for 12 years until 1984. During the period 1984-89, seven additional appraisal wells were drilled, including a 3D-seismic survey, which essentially defined the current structural interpretation. This interpretation indicated that the gas-in-place was split equally between an eastern and western area.
Four of the appraisal wells were drilled in the west of the field, and their average stabilized deliverability, including the discovery well, was estimated to be 3 MMscf/D/well compared with the three eastern wells, which had an estimated 21 MMscf/D/well. It was therefore clear that to meet an economic threshold gas rate and to improve recovery from the western sector, where 50% of the potential reserves resided, well productivity would need to be substantially improved in the western sector.
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