Productivity of Wells in Vertically Fractured, Damaged Formations
- L.R. Raymond (Esso Production Research Co.) | G.G. Binder Jr. (Esso Production Research Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- January 1967
- Document Type
- Journal Paper
- 120 - 130
- 1967. Society of Petroleum Engineers
- 1.8 Formation Damage, 5.6.4 Drillstem/Well Testing, 2.4.3 Sand/Solids Control, 2.5.2 Fracturing Materials (Fluids, Proppant), 3 Production and Well Operations, 1.2.3 Rock properties, 5.5.2 Core Analysis, 4.1.5 Processing Equipment, 2.5.1 Fracture design and containment, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.6.9 Coring, Fishing, 4.1.2 Separation and Treating, 5.3.4 Integration of geomechanics in models
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One primary purpose of hydraulic fracturing as a well stimulation technique is to overcome formation damage. The literature provides ways of designing fracture treatments and evaluating their results but not of incorporating formation damage in vertically fractured wells. Results of an investigation of this problem are presented in this paper. Prediction of stimulation ratios in vertically fractured, damaged wells is accomplished with a mathematical model relating stimulation ratio to relative conductivity of fractures whose lengths are not more than about half the drainage radius of the well. Comparison of results from the new model to results in published predictions verify its utility; these results also show that the range of stimulation ratios that can he predicted for undamaged wells is extended to include relative conductivities of less than 300. This extension is important when using fracturing to stimulate wells with high production rates and high native formation permeabilities. For example, large increases in daily oil production rate can be obtained with stimulation ratio increases as low as 1.25. The importance of complete fracture fill-up (uniform proppant packing) is shown through use of the mathematical model. If, at the mouth of a fracture, only a small fraction (1/2 percent) of the total fracture length is not packed with proppant, nearly all the potential stimulation increase is lost. Proppant crushing, compaction and embedment have been shown in laboratory studies to be responsible for low fracture conductivities in wells producing from highly stressed formations. Equipment and methods for testing the effect of stress (overburden) on conductivity of fractures in consolidated and unconsolidated sands are discussed in this paper. Laboratory tests with simulated fractures in cores from both types of formations showed that crushing, compaction and embedment seriously affect conductivity. Results indicate that similar laboratory tests should be made when accurate knowledge of fracture conductivity is needed to assure good stimulation results for important wells. The chief factor in stimulation ratio reduction was found to be overburden pressure, but the size and type of proppant and the hardness of the formation have significant effects. Fracture conductivity reductions of up to 50 percent were observed with sand propping fractures in consolidated cores; a reduction of 83 percent was measured for an unconsolidated core. The range of effective overburden pressures for which conductivities were measured was from 100 to 5,000 psi. An example fracture design and evaluation problem indicates the usefulness of considering formation damage in planning well stimulation jobs. When damage exists, but its extent and the degree of permeability reduction are not estimated from diagnostic tests, the formation permeability used in planning the job may lead to underdesigning. As the example shows, too low a target stimulation ratio can lead to much lower production rates (by half) than could be attained otherwise. Solutions of equations representing several special cases of the mathematical model are presented in graphical form and details of the derivations of the equations are given in the Appendix.
Since its inception in 1947, hydraulic fracturing has proven to be an effective and widely accepted stimulation technique. In the past 18 years the ability to execute a successful hydraulic fracturing treatment has been substantially increased. The development of design and evaluation procedures has been one of the major contributions to this increased skill. However, as the art of hydraulic fracturing has moved closer to a science, new problems concerning the design and evaluation of the optimal hydraulic fracturing treatment have arisen. Three questions are pertinent to these problems.
1. How is a fracturing job evaluated in a damaged well?
2. What is the effect on the stimulation ratio of not filling the fracture in the vicinity of the wellbore.
3. What is the effect of overburden pressure on fracture conductivity and, consequently, the stimulation ratio?
A primary objective of fracturing a well is to stimulate production by overcoming wellbore damage. Presently, however, there is no rational basis for designing or evaluating the optimal fracturing treatment in a damaged well. All present fracture design and evaluation techniques assume that proppants can be uniformly placed in fractures. This assumption may be in serious error, particularly for the portion of a fracture directly adjacent to the wellbore. In this area, turbulence of the injected fluid can cause the proppant to be swept farther into the fracture.
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