A previously published model describing pressure-buildup behavior of naturally flaetured reservoirs was combined }t'itha nonlinear, least-squares regression technique to analyze buildup data. The model adequately described the buildup response and was useful for obtaining effect ive formation permeability in the cases studied.
Field tests have shown that compass orientation and the length of hydraulic fractures can be determined by pulse testing in different directions from wells before and after fracturing. The method determines orientation by sampling a large portion of the reservoir, is applicable to cased holes, and provides an estimate of fracture length. Introduction It is often desirable to know the flow patterns created after a number of wells in a reservoir have been fractured. This requires a knowledge of the compass orientations, lengths, and conductivities of hydraulic fractures. Standard pressure interference testing has been used to determine the orientation of natural fractures and inflatable impression packers and television cameras have been used to locate hydraulic fractures in open-hole completions. None of these methods, however, determines both the compass orientation and the length of a hydraulic fracture, and only one method samples a large portion of the reservoir. This paper describes a way to use pulse testing to determine both the compass orientation and the length of such fractures. Results from two field tests are presented. presented. Theory Johnson et al. give a complete description of the procedure and technology of pulse testing. The method procedure and technology of pulse testing. The method involves changing the rate of flow at one well and measuring the pressure response at one or more offset wells. The response, or pressure pulse, is characterized by two parameters, the time lag and the pulse amplitude. These and other pulse-testing parameters are illustrated in Fig. 1. Pulse amplitude depends on flow rate, pulse interval, between-pulse interval, and, to some extent, on reservoir properties, transmissibility, and storage. Time lag properties, transmissibility, and storage. Time lag primarily depends on transmissibility and storage. It has primarily depends on transmissibility and storage. It has been shown that the presence of a high-transmissibility zone or of a zone of very low transmissibility (a barrier) can be detected by pulse testing. A fracture, of course, creams a zone of high transmissibility with an insignificant change in storage as compared with that of the unfractured matrix. Fig. 2 shows the relationship between transmissibility (for a fixed value of storage) and both time lag and response amplitude. Clearly, a change in time lag is sensitive to a change in transmissibility. Pulse amplitude, on the other hand, varies directly with Pulse amplitude, on the other hand, varies directly with changes in transmissibility over part of the range; but for greater than 3 x 10 md-ft/cp, the amplitude responds weakly to increases in transmissibility. For these reasons, changes in time lag should be most effective for determining the direction and length of a hydraulically induced fracture. To evaluate the feasibility of this procedure, a model of a reservoir (see Appendix) was constructed with one pulsing well in the center and several responding wells pulsing well in the center and several responding wells around the pulser. A pulse test was then simulated by producing and shutting in the pulsing well intermittently producing and shutting in the pulsing well intermittently for equal increments of time. The pressure response was computed for all responders and was then analyzed using the tangent method to determine the time lags. A hydraulic fracture was then simulated by narrow blocks with high but finite permeability extending an assumed length from the well. The same pulsing sequence was repeated and the results were analyzed for time lags after fracturing. The ratio of the time lag before fracturing to the time lag after fracturing was plotted as a function of direction (angle) around the pulser. JPT P. 1433
The results from pulse testing were used to predict waterflood performance in the Kelsey field. This prediction was verified by field waterflood performance. The tests showed the presence of an unmapped sealing performance. The tests showed the presence of an unmapped sealing discontinuity and the fact that all but one major fault were nonsealing. Introduction The pulse-testing technique described by Johnson et al. and later used in an extensive application in an oil-producing field has proven to be a useful tool for describing areal reservoir heterogeneities. This paper describes the use of pulse testing to predict the performance of a planned waterflood in Exxon Co., U.S.A.'s Kelsey field in South Texas, a producing oil field containing a number of mapped faults. The wells are completed in the Frio formation, which is a nonmarine, river point-bar, shaly-sand type formation. This flexuretype field is produced on the downthrown side, and the original production of the 38- to 42- degrees API gravity oil was by gas-cap expansion. Even though the main purpose of pulse testing was to determine reservoir connectivity, pulse testing was to determine reservoir connectivity, values for storage, transmissibility, and hydraulic diffusivity were obtained for some of the between-well reservoir properties. This paper also summarizes the history of a subsequent waterflood, performance of which verifies the pulse-test results, Pulse-test values of transmissibility, storage, and hydraulic diffusivity reported in this paper were within the range of single-well test, core, and fluid property data estimates of formation properties of this South Texas field. Results of feasibility studies, based on these data, helped in the design of the pulse-testing program described here. pulse-testing program described here. Pulse-Test Procedure and Pulse-Test Procedure and Evaluation of Results The pulse test requires two wells - a pulsing well and a responding well. The scheme is to create a sequence of rate changes in the flow at the pulsing well and measure the resulting pressure changes at an adjacent responding well with a very sensitive wellhead pressure gauge. The measuring sensitivity of the gauge used for these tests was 3 x 10 to the -4 to 12 x 10 to the -4 psi. The precision of the gauge is dependent on the surface wellhead pressure of the responding well, which, in most cases, was about 300 psi. For our tests, the pulsing wells were flowing, producing oil wells with rates of 175 to 880 RB/D of oil. Two exceptions, Wells 11 and 16, shown in Fig. 1, already had been converted to water injection. Therefore, we used them as pulsers with injection rates of 1,400 and 2,000 BWPD, respectively. The tubing in the responding wells was loaded with lease crude to provide a gas-free liquid with a positive pressure to the surface. Then the sensitive pressure gauge was connected to the well tubing and was allowed to equilibrate for 12 hours before pulsing was begun. A pulse was started and continued until a definite response could be observed, or for period of 12 hours or longer but not more than 1 day if period of 12 hours or longer but not more than 1 day if there seemed to be no response. Table 1 gives the well pairs tested, distance between them, pulse rate, pulse pairs tested, distance between them, pulse rate, pulse interval, and gauge sensitivity for each test. In general, these values are the same for both the response and no-response cases. However, the pulse intervals were longer in the no-response cases in an attempt to enhance the chances of detecting a response. An example of the data where a response was obtained between a well pair is shown in Fig. 2. Fig. 3 shows an example where no response was observed. JPT P. 914
Fracture stimulation characteristics were measured and studied for changing behavior over a 6 month period using pressure buildup tests conducted on a Prudhoe Bay well. The suite of pressure tests included a pre-frac buildup, and two post-frac buildups at six month intervals following the fracture stimulation treatment. Pre-frac analysis exhibited radial composite characteristics consistent with other Prudhoe Bay well test analysis. Post-frac analysis showed the fracture length and conductivity to decrease over a six month period. Corroborating the well test results, production from this well decreased more rapidly than expected. Numerical simulation confirmed the results. Data acquisition pertinent to a successful well test analysis is discussed. Methodology A composite model (two concentric rings) with permeability increasing radially outward was used in the pre-frac test. A vertical fracture was incorporated into the composite model in the post-frac tests. If a pre-frac buildup was not conducted, the post-frac analysis would be highly speculative, because the pre-frac results were not a homogenous response. Fracture length and conductivity decreased between the two post-frac tests. Additionally, the fracture face skin increased slightly. As result, a component to the rapid decrease in production rate could be explained by the deterioration of the fracture length and conductivity. Conclusions1. Pressure buildup technology through effective design, application, and analysis, proved a viable method of monitoring fracture stimulation performance. 2. Accurate rate history is equally as important as the pressure-time data most generally associated with buildup analysis. 3. Analytical representation of a vertical fracture in a composite system can be adequately modeled with pseudo-boundaries. 235
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