Case History of Successfully Water Flooding a Fractured Sandstone
- R.W. Rausch | K.W. Beaver
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 1964
- Document Type
- Journal Paper
- 1,233 - 1,237
- 1964. Original copyright American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Copyright has expired.
- 1.6 Drilling Operations, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.4.3 Sand/Solids Control, 5.4.1 Waterflooding, 4.2.3 Materials and Corrosion, 1.2.3 Rock properties, 1.6.9 Coring, Fishing, 5.2.1 Phase Behavior and PVT Measurements, 5.6.4 Drillstem/Well Testing, 4.6 Natural Gas, 5.4.2 Gas Injection Methods, 4.3.4 Scale, 4.1.2 Separation and Treating, 5.1.2 Faults and Fracture Characterisation, 4.2 Pipelines, Flowlines and Risers
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By 1955, the First Wall Creek reservoir had reached the stripper stage. At that time a 20-acre double five-spot pilot was started to evaluate waterflood feasibility. Injected water was lost from the pilot area through natural fractures, and the five-spots were not encouraging. However, wells outside the five-spots showed production increases, so the pilot area was expanded to include about 100 acres. The expansion proved highly successful, and a full-scale program is now underway. Sand-oil fracture treatments have contributed to the success of the project.
The geology and history of the Salt Creek field, Salt Creek, Wyo., have been described previously. The First Wall Creek pool under consideration here was discovered in 1908 and is one of 11 productive zones found on the Salt Creek anticline. The pool is cut by numerous normal faults of small displacement. Fig. 1 is a field map. Many of the smaller faults have been omitted in this figure. There are surface indications which suggest that some of these faults may be sealed by secondary deposits of calcite. The First Wall Creek pay zone, found at an average depth of 900 ft, is a fine- to medium-grained sand with numerous thin shale partings. Porosity and permeability are locally erratic, and average 15 per cent and 80 md, respectively. Gross thickness of the section averages 120 ft, of which about two-thirds is net pay and the remainder is shale. Core analyses indicate local zones of high permeability, usually near the base of the section. Injectivity profiles from spinner surveys show that extensive natural fracturing is present in some areas, and as a result, matrix permeability does not necessarily determine points of fluid entry into the wellbore. The produced crude is paraffin base, 38 gravity, having an estimated original solution GOR of 550 cu ft/bbl. The northern two-thirds of the Salt Creek field, including all of the First Wall Creek pool, was unitized in 1939, with the Midwest Oil Corp. as unit operator. Pan American Petroleum Corp. conducts the field operations for the unit owners on a contract basis. Sixty-eight companies and individuals are working interest owners in the unit.
A gas-drive project was started in the Second Wall Creek pool, Salt Creek's largest reservoir, in 1926. This project was successfulit is still in operationso a similar program was attempted in the First Wall Creek starting in 1927. Maximum available surface injection pressure was only 350 psi, and most of the First Wall Creek wells would not take gas at economically significant rates with this injection pressure, so no measurable production benefit was obtained. Injections were nonetheless continued until 1949 to avoid flaring gas. A total of about 2 billion cu ft was injected in 22 years.
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