Oil recovery by polymer flooding is influenced by reservoir heterogeneity not only through its effects on crossflow, but also through the dependence of polymer retention, inaccessible pore volume, and polymer shear degradation on permeability. This paper describes a simulator that accounts for all these factors and includes experimental data, obtained using field and Berea cores, that demonstrate the permeability dependence of these factors.Use is made of a two~dimensional reservoir simulator with the added feature of point-tracking capability. For each of the different layers, one chain of points is identified with the front of the polymer bank and another chain with the rear 0 f the bank. Retention and inaccessible pore volume can be accounted for through a factor that is the ratio of the velocity of the moving points to the wettingphase velocity. Rheology and degradation are introduced by alterations in wetting -phase viscosities at the leading edge and at the trailing edge of the bank. Each layer can have a different resistance factor, retention, inaccessibl e pore volume, and shear degradation. The flow equations used in the simulator, as well as the method of exploitation of the point-tracking feature, are given in detail.A number of cases are presented in which the sensitivity of oil recovery to variations in polymer retention, degradation, inaccessible pore volume, and reservoir heterogeneity was studied. Results show that oil recovery is sensitive to these variables and that using less realistic assumptions can give significantly different results.

Johnson et al. have described a new well-testing technique that measures formation flow properties between wells.'The technique, called pulse-testing, requires a sequence of rate changes in the flow at one well and measurement of the resulting pressure changes at an adjacent well with a very sensitive differential pressure gauge.This paper describes an extensive application of the technique in a producing oil field. Pulse-tests on 28 of 45 possible well pairs in the field provided a picture of the areal distribution of reservoir hydraulic diffusi vi ty, transmissibility and storage. The primary objective in presenting these data is to demonstrate the potential of the method for reservoir description. A second objective is to show in three ways the qualitative and quantitative accuracy of reservoir parameters determined from pulse-tests: (1) pulsetest data show a nonuniformity in the field, closely correlating with the oil-water distribution as given by production data; (2) pulse-test values for permeability are comparable with core values; and (3) perhaps most important, the field responds to a conventional interference test in the manner in which pulse-test data predict it should.

Reservoir transmissibility and storage values can be obtained from pressure pulses induced in one well and measured at a second well. Such pulse-test values are generally calculated from pulse-test values are generally calculated from equations which assume the formation is homogeneous. This paper examines the effects of areally distributed heterogeneities on pulse-test values. An influence area is first developed for a pulse-tested well pair; only those heterogeneities pulse-tested well pair; only those heterogeneities within this area significantly affect pulse-test results. Next, for three limiting cases, the manner in which a pulse test averages heterogeneities within the influence area is described. These are the cases for which one of the three formation properties - hydraulic diffusivity, transmissibility properties - hydraulic diffusivity, transmissibility and storage - is constant throughout the influence area. Finally, a method called directional correction is developed that when applied to pulse-test values of transmissibility and storage restores some, if not most, of the true degree of heterogeneity to these values. Accuracy of the method depends upon the relative variability of the true values. Introduction The pulse-testing method of Johnson et al. uses a sequence of rate changes at one well to create a low-level pressure interference response at an adjacent well. This response is readily analyzed for reservoir properties if one assumes an infinite, homogeneous reservoir model. The field data of McKinley et al. show that, despite the use of a simple analytical model, pulse-test values are sensitive to between-well pulse-test values are sensitive to between-well formation properties. Calculated values for transmissibility and storage exhibit considerable variation with direction around a central pulsing well. These values cannot, however, reflect the exact degree of heterogeneity since flow about the pulsing well is usually nonradial. pulsing well is usually nonradial. This paper examines the effects of certain idealized types of areal heterogeneities on pulse-test values calculated from the simple model. In pulse-test values calculated from the simple model. In particular, an influence area for a pulse-tested well particular, an influence area for a pulse-tested well pair is first developed. This area is defined as that pair is first developed. This area is defined as that areal portion of the formation whose properties determine the numerical value, obtained from pulse testing the well pair. Its size depends on the length of the pulse and the hydraulic diffusivity of the formation. We then determine the type of average values yielded by a pulse test when heterogeneities are distributed randomly throughout the influence area. Results of these studies provide a simple correction scheme that restores some of the true degree of heterogeneity to pulse-test values of transmissibility and storage. Accuracy of the method depends on the relative variability of the latter two reservoir parameters. PULSE-TEST TERMINOLOGY AND ANALYSIS PULSE-TEST TERMINOLOGY AND ANALYSIS A typical rate-change sequence at the pulsing well appears at the bottom of Fig. 1. The pulse rate is q reservoir B/D and the pulse length is delta t minutes. The time between pulses is R delta t minutes. Each such pulse cycle induces at the responding well the pressure response (pulse) shown at the top of Fig. 1. According to the analysis method of Johnson et al., each pressure pulse is characterized by two quantities - a time lag, tL minutes, and a pulse amplitude, delta p psi. How these values are pulse amplitude, delta p psi. How these values are determined from the pressure response is apparent from Fig. 1. For an infinite, homogeneous formation, the time lag, tL, the R-value and the well spacing, rws, are sufficient to determine the hydraulic diffusivity, of the formation. These values, coupled with pulse amplitude, p, and pulse rate, q, determine formation transmissibility, =kh/ . Formation storage, = ch, is obtained from the ratio = / . Charts to facilitate this analysis are given by Brigham for R=1. SPEJ P. 181

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

A one-well field test of nitrogen WAG (water alternating gas) injectivity was conducted to detennine whether a reduction in water injectivity would occur after injection of nitrogen. A 40% reduction was observed immediately after nitrogen injection. Following three short WAG cycles, water injectivity increased to its pretest level with injection of a large volume of water. FEBRUARY 1982 Perforated interval, m (tt) Initial reservoir temperature, °C (OF) Cooled reservoir temperature, °C (OF) Reservoir pressure, Pa (pSi) Net thickness, m (tt) Average porosity, % Average core permeability, m 2 (md) Water injected before start