The Use of Special Coring and Logging Procedures for Defining Reservoir Residual Oil Saturations
- R.P. Murphy (Amoco Production Co.) | W.W. Owens (Amoco Production Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- July 1973
- Document Type
- Journal Paper
- 841 - 850
- 1973. Society of Petroleum Engineers
- 5.5.2 Core Analysis, 5.8.7 Carbonate Reservoir, 1.11 Drilling Fluids and Materials, 5.3.4 Reduction of Residual Oil Saturation, 4.1.5 Processing Equipment, 5.4.1 Waterflooding, 5.6.2 Core Analysis, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.2 Reservoir Fluid Dynamics, 2.4.3 Sand/Solids Control, 5.7.5 Economic Evaluations, 5.6.5 Tracers, 1.6.9 Coring, Fishing, 5.6.1 Open hole/cased hole log analysis, 1.10 Drilling Equipment, 5.7.1 Estimates of resource in place, 5.2.1 Phase Behavior and PVT Measurements, 6.5.2 Water use, produced water discharge and disposal, 4.1.2 Separation and Treating, 1.6 Drilling Operations
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The Use of Special Coring and Logging Procedures for Defining Reservoir Procedures for Defining Reservoir Residual Oil Saturations
Under certain conditions, data obtained from pressure cores, from core flow tests, and through log-inject-log procedures can yield reliable values for residual oil saturation at a given location within a waterflooded area. This is adequate for planning a pilot program. If a reliable reservoir-wide estimate is needed, however, several wells in different areas of the reservoir must be cored or logged.
During the producing life of a reservoir, it is not unusual to make estimates of oil in place and recoverable reserves for three different phases of production - primary, secondary, and tertiary. The production - primary, secondary, and tertiary. The economics of primary and secondary recovery programs is usually so attractive that considerable error in the estimates of recoverable reserves can be tolerated. However, a much greater degree of confidence is needed in the estimates of tertiary reserves. This is because most tertiary recovery processes cost more per barrel of oil recovered than do primary or per barrel of oil recovered than do primary or secondary. In addition, the total volume of tertiary oil recovery may be lower than that of either primary or secondary. In estimating the oil in place before a secondary or tertiary recovery program, both the volume of oil and its distribution within the reservoir are important. Several methods are currently being used to measure the reservoir oil saturation. For purposes of this discussion, we shall refer to these as "conventional methods of measurement" and discuss them briefly in the following section. Two less conventional and more recently developed methods, which are the primary subject of this paper, are discussed in a later primary subject of this paper, are discussed in a later section and are referred to as "specialized coring and logging procedures".
Conventional Methods of Measurement Material Balance
Probably the first method to be developed and the one Probably the first method to be developed and the one still most widely used for determining reservoir oil volume is based upon material balance concepts. With this approach, the volume of oil remaining in the reservoir at any stage of depletion is found by subtracting the volume of produced oil (accounting for shrinkage) from the original volume of oil in place. Since the volume of produced oil is usually known precisely, the accuracy of this approach depends precisely, the accuracy of this approach depends entirely upon the reliability of the original oil-in-place estimate. While this method of analysis may yield a reliable value for the total volume of oil remaining in the reservoir. it does not define the distribution of the oil. Knowledge of the oil saturation distribution, both laterally and vertically within the reservoir, can be a critical factor in the planning of a secondary or tertiary recovery program.
Interpretation of Standard Core Analysis
When a formation is cored conventionally with a water-filtrate type of mud, the oil and water saturations in the cores, when analyzed, may be of limited use in defining reservoir saturations. Invasion of filtrate into the cores during coring, and subsequent expulsion of fluids by gas expansion as the core travels to the surface can contribute to serious alterations in core oil and water saturations. There are conditions, however, under which the core saturations at the surface may be quite similar to those in the reservoir.
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