Interporosity Flow Parameter Research Articles

Theoretical Comparison of Test Performance of Different Pulse Decay Methods for Unconventional Cores

Various pulse decay methods are proposed to test tight cores. These methods can be divided into three types. This study compares the performance of these methods to test the permeability of unconventional cores in terms of homogeneous cores, dual-medium cores, and gas adsorption, including the pressure equilibrium time, possible errors caused by conventional analysis methods, and reflections on the characteristics of dual-media. Studies shows that the two test methods with an antisymmetric relationship in the boundary conditions have basically identical test performance. When testing homogeneous cores, regardless of whether the gas is adsorptive or not, the pressure equilibrium time of the first type of method is approximately half of that of the second type of method. The dual-medium parameters seriously affect the pressure equilibrium time of different methods, which may cause the difference of order of magnitude. For homogeneous cores, the permeability errors of the first and second types of methods caused by porosity errors are similar and larger than that of the third type of method. For dual media, the fracture permeability obtained by the third type of method using the conventional analysis method may differ from the actual value by tens of times. No method can significantly eliminate the sorption effect. When the core is a dual-medium, only the pressure curves of the upstream positive-pulse method, downstream negative-pulse method and one-chamber method can reflect the characteristics of dual media. The pressure derivative of the one-chamber method cannot reflect the characteristics of dual media at the early time. The pressure derivative of the second type and the upstream positive-pulse downstream negative-pulse method can reflect the complete characteristics of dual media, but their pressure derivative of the constant-slope segment is small, and the interporosity flow parameter may not be identified.

Transient Pressure Analysis of a Multiple Fractured Well in a Stress-Sensitive Coal Seam Gas Reservoir

This paper investigates the bottom-hole pressure (BHP) performance of a fractured well with multiple radial fracture wings in a coalbed methane (CBM) reservoir with consideration of stress sensitivity. The fluid flow in the matrix simultaneously considers adsorption–desorption and diffusion, whereas fluid flow in the natural fracture system and the induced fracture network obeys Darcy’s law. The continuous line-source function in the CBM reservoir associated with the discretization method is employed in the Laplace domain. With the aid of Stehfest numerical inversion technology and Gauss elimination, the transient BHP responses are determined and analyzed. It is found that the main flow regimes for the proposed model in the CBM reservoir are as follows: linear flow between adjacent radial fracture wings, pseudo-radial flow in the inner region or Stimulated Reservoir Volume (SRV), and radial flow in outer region (un-stimulated region). The effects of permeability modulus, radius of SRV, ratio of permeability in SRV to that in un-stimulated region, properties of radial fracture wings, storativity ratio of the un-stimulated region, inter-porosity flow parameter, and adsorption–desorption constant on the transient BHP responses are discussed. The results obtained in this study will be of great significance for the quantitative analyzing of the transient performances of the wells with multiple radial fractures in CBM reservoirs.

Interference test interpretation in naturally fractured reservoirs

The naturally fractured reservoir characterization is crucial because it can help to predict the flow pattern of fluids, and the storativity ratio of the fractures and to understand whether two or more wells have communication, among others. This paper presents a practical methodology for interpreting interference tests in naturally fractured reservoirs using characteristic points found on the pressure derivative curve. These kinds of tests describe a system that consists of a producing well and an observation well separated by a distance (r). Using characteristic points and features found on the pressure and pressure derivative log-log plot, Analytical expressions were developed from the characteristic points of the pressure and pressure derivative log-log plot to determine the interporosity flow parameter (λ) and the storativity ratio of the fractures (ω). Finally, examples are used to successfully verify the expressions developed so that the naturally-fractured parameters were reproduced with good accuracy.

Application of Decline Curve Analysis for Estimating Different Properties of Closed Fractured Reservoirs for Vertical Wells

In this paper, decline curve analysis is used for estimating different parameters of bounded naturally fractured reservoirs. This analysis technique is based on rate transient technique, and it is shown that if production rate is plotted against time on a semi-log graph, straight lines are obtained that can be used to determine important parameters of the closed fractured reservoirs. The equations are based on Warren and Root model. The comparison between the results of this technique and those of the conventional methods confirms its high proficiency in transient well testing. It should be noted that in conventional decline curve methods, parameters such as interporosity flow parameter and storage capacity ratio must be first obtained by previous methods like the build-up analysis, but in the proposed method all the main reservoir parameters can be calculated directly, which is one of the advantages of this method. This paper focuses on the interpretation of rate tests, and the starting points and slopes of straight lines are utilized with proper equations to solve directly for various properties. The main important aspect of the presented method is its accuracy since analytical solutions are used for calculating reservoir parameters.

Pressure transient analysis of a vertical well with multiple etched fractures in carbonate reservoirs

Acid fracturing has been widely used as an industry practice in explored and developed carbonate reservoirs. It is very important to understand responses of reservoirs and improve production performance of a well due to the presence of fracture networks by stimulation treatments. Pressure transient analysis is one of the most effective diagnostic techniques available to enhance our understanding of natural and artificial-etched fracture behavior. This work presented a novel mathematical model for unsteady state flow of naturally fractured porous medium into multiple etched fractures intersecting a vertical well, and three different geometric shapes of matrix blocks containing slabs, cylinders and spheres were considered. The new solution was derived by using the Laplace transformation and the point source function integral approach. The polar coordinate transformation was used to deal with the radial distribution of arbitrary fracture number and angle. Then the model was validated by comparison with three published cases. Finally, type curves were plotted to identify flow regimes: linear flow, transitional flow, pseudoradial flow, and boundary dominant flow if the closed or constant pressure boundary exists. Furthermore, sensitivity analysis was investigated. The results showed that the acid-etched fracture parameters containing fracture number, fracture distribution and conductivity had a significant impact on pressure behavior at early times. However, natural fracture storativity coefficient and interporosity flow parameter mainly affected the transitional flow at intermediate times. Moreover, the shape of matrix blocks had a little influence on transient responses at intermediate times. It is found that multiple etched fractures existing near the wellbore consume less pressure drop and increase the productivity of a well as a whole.

Estimating the properties of naturally fractured reservoirs using rate transient decline curve analysis

Transient rate decline curve analysis for constant pressure production is presented in this paper for a naturally fractured reservoir. This approach is based on exponential and constant bottom-hole pressure solution. Based on this method, when ln (flow rate) is plotted versus time, two straight lines are obtained which can be used for estimating different parameters of a naturally fractured reservoir. Parameters such as storage capacity ratio (ω), reservoir drainage area (A), reservoir shape factor (CA), fracture permeability (kf), interporosity flow parameter (λ) and the other parameters can be determined by this approach. The equations are based on a model originally presented by Warren and Root and extended by Da Prat et al. and Mavor and Cinco-Ley. The proposed method has been developed to be used for naturally fractured reservoirs with different geometries. This method does not involve the use of any chart and by using the pseudo steady state flow regime, the influence of wellbore storage on the value of the parameters obtained from this technique is negligible. In this technique, all the parameters can be obtained directly while in conventional approaches like type curve matching method, parameters such as ω and λ should be obtained by other methods like build-up test analysis and this is one of the most important advantages of this method that could save time during reservoir analyses. Different simulated and field examples were used for testing the proposed technique. Comparison between the obtained results by this approach and the results of type curve matching method shows a high performance of decline curves in well testing.

A comprehensive model combining Laplace-transform finite-difference and boundary-element method for the flow behavior of a two-zone system with discrete fracture network

This paper provides a comprehensive model for the flow behavior of a two-zone system with discrete fracture network. The discrete fracture network within the inner zone is represented explicitly by fracture segments. The Laplace-transform finite-difference method is used to numerically model discrete fracture network flow, with sufficient flexibility to consider arbitrary fracture geometries and conductivity distributions. Boundary-element method and line-source functions in the Laplace domain are employed to derive a semi-analytical flow solution for the two-zone system. By imposing the continuity of flux and pressure on discrete fracture surfaces, the semi-analytical two-zone system flow model and the numerical fracture flow model are coupled dynamically. The main advantage of the approach occurring in the Laplace domain is that simulation can be done with nodes only for discrete fractures and elements for boundaries and at predetermined, discrete times. Thus, stability and convergence problems caused by time discretization are avoided and the burden of gridding and computation is decreased without loss of important fracture characteristics. The model is validated by comparison with the results from an analytical solution and a fully numerical solution.Flow regime analysis shows that a two-zone system with discrete fracture network may develop six flow regimes: fracture linear flow, bilinear flow, inner zone linear flow, inner zone pseudosteady-state flow, outer zone pseudoradial flow and outer zone boundary-dominated flow. Especially, local solutions for the inner-zone linear flow have the same form with that of a finite conductivity planar fracture and can be correlated with the total length of discrete fractures and an intercept term. In the inner zone pseudosteady-state flow period, the discrete fractures, along with the boundary of the inner zone, will act as virtual closed boundaries, due to the pressure interference caused by fracture network and the mobility contrast of the two zones. The dimensionless fracture conductivity of the fracture network determines the characteristics of the bilinear flow and the inner zone linear flow. The mobility ratio, M, and storability ratio, Fs, primarily influence the flow behavior of the middle to later time. For a larger M, the ending time of the inner zone pseudosteady-state flow will be advanced and the beginning time of the outer-zone pseudoradial flow will be delayed. And the larger M also results in increasing of the values of the transient responses in these two periods. Duration of the outer-zone pseudoradial flow becomes longer, as Fs increases; the development of the outer-zone boundary-dominated flow is therefore postponed. Finally, idealization of dual-porosity model for the two zones will introduce two dips on the pressure derivatives on the log/log plot. Depending on the interporosity flow parameter, the time of the two dips varies. However, the dips are not very appreciable for the transient dual-porosity model, when the permeability of matrix system or fracture density is relatively high.

A semi-analytical model for the flow behavior of naturally fractured formations with multi-scale fracture networks

Summary This paper presents a semi-analytical model for the flow behavior of naturally fractured formations with multi-scale fracture networks. The model dynamically couples an analytical dual-porosity model with a numerical discrete fracture model. The small-scale fractures with the matrix are idealized as a dual-porosity continuum and an analytical flow solution is derived based on source functions in Laplace domain. The large-scale fractures are represented explicitly as the major fluid conduits and the flow is numerically modeled, also in Laplace domain. This approach allows us to include finer details of the fracture network characteristics while keeping the computational work manageable. For example, the large-scale fracture network may have complex geometry and varying conductivity, and the computations can be done at predetermined, discrete times, without any grids in the dual-porosity continuum. The validation of the semi-analytical model is demonstrated in comparison to the solution of ECLIPSE reservoir simulator. The simulation is fast, gridless and enables rapid model setup. On the basis of the model, we provide detailed analysis of the flow behavior of a horizontal production well in fractured reservoir with multi-scale fracture networks. The study has shown that the system may exhibit six flow regimes: large-scale fracture network linear flow, bilinear flow, small-scale fracture network linear flow, pseudosteady-state flow, interporosity flow and pseudoradial flow. During the first four flow periods, the large-scale fracture network behaves as if it only drains in the small-scale fracture network; that is, the effect of the matrix is negligibly small. The characteristics of the bilinear flow and the small-scale fracture network linear flow are predominantly determined by the dimensionless large-scale fracture conductivity. And low dimensionless fracture conductivity will generate large pressure drops in the large-scale fractures surrounding the wellbore. With the increasing of the interporosity flow parameter, flow exchange between the matrix and the small-scale fracture network will be advanced and may mask the pseudosteady-state flow period. The duration of flow exchange increases and the dip caused by the interporosity flow gets deeper with the decreasing of the storability ratio. Finally, an appropriate choice of the pseudosteady or transient dual-porosity model to idealize the small-scale fracture networks with the matrix depends entirely on a better understanding of the geological evidence supporting either model.

Pressure and pressure derivative analysis for non-newtonian pseudoplastic fluids in double-porosity formations

Non-Newtonian fluids are often used during various drilling, workover and enhanced oil recovery processes. Most of the fracturing fluids injected into reservoir-bearing formations possess non-Newtonian nature and these fluids are often approximated by Newtonian fluid flow models. In the field of well testing, several analytical and numerical models taking into account Bingham, pseudoplastic and dilatant non-Newtonian behavior have been introduced in the literature to study their transient nature in porous media for a better reservoir characterization. Most of them deal with fracture wells and homogeneous formations and well test interpretation is conducted via the straight-line conventional analysis or type-curve matching. Only a few studies consider the pressure derivative analysis. However, there exists a need of a more practical and accurate way of characterizing such systems. So far, it does not exist any methodology to characterize heterogeneous formation bearing non-Newtonian fluids through of well test analysis. In this study, an interpretation methodology using the pressure and pressure derivative log-log plot is presented for non-Newtonian fluids in naturally fractured formations, so the dimensionless fracture storativity ratio, ω, and interporosity flow parameter, λ, are obtained from characteristics points found on such plot. The developed equations and correlations are successfully verified by their application only to synthetic well test data since no actual field data are available. A good match is found between the results provided by the proposed technique and the values used to generate the simulated data.

The Application of Boundary Element on Pressure Transient of Carbonat Reservoir

ABSTACT: The effect of the shape of reservoir boundaries on the well-bore pressure response is evident. The conventional analytical methods can only be used to calculate well-bore pressure response in regularly shaped reservoirs. A mathematical model for well test interpretation of arbitrary shaped triple porosity reservoir was established and transformed to modified Helmholtz equation in this paper. By using the boundary element method and Duhamel principle, well-bore pressure with effects of skins and well-bore storage is obtained. The type curves are plotted and analyzed considering effects of the dimension fracture storage parameter, the inter-porosity flow parameter, arbitrary shape and impermeable barries. At last, the boundary element method is verified against the analytical solution and is applicable to transient pressure analysis of arbitary shaped reservoir. KETWORDS: carbonate reservoir, triple porosity, boundary element method, transient pressure, type curve

A study on transient fluid flow of horizontal wells in dual-permeability media

To adopt horizontal wells in dual media reservoirs, a good understanding of the related fluid flows is necessary. Most of the recent studies focus on dual porosity media instead of dual permeability media. In this article, through both integral transformation and sink-source superposition, a new Laplace-domain solution is obtained for the slightly-compressible fluid flow in the 3-D dual-permeability media in which the horizontal well is operating in a constant rate of production. Major asymptotic characteristics of diagnosis curves of dimensionless downhole pressure are analyzed by the limited analysis. Effects of parameters of dual-permeability media including mobility ratio κ, storativity ratio ω and inter-porosity flow parameter κ on the downhole pressure are studied by using the Laplace numerical inversion. The new solution obtained in this article includes and improves the previous results and then can be used as a basis for either pressure transient analysis or formation behavior evaluation for the typical reservoir with horizontal wells.

CONVENTIONAL PRESSURE ANALYSIS FOR NATURALLY FRACTURED RESERVOIRS WITH TRANSITION PERIOD BEFORE AND AFTER THE RADIAL FLOW REGIME

It is expected for naturally occurring formations that the transition period of flow from fissures to matrix takes place during the radial flow regime. However, depending upon the value of the interporosity flow parameter, this transition period can show up before or after the radial flow regime. First, in a heterogeneous formation which has been subjected to a hydraulic fracturing treatment, the transition period can interrupt either the bilinear or linear flow regime. Once the fluid inside the hydraulic fracture has been depleted, the natural fracture network will provide the necessary flux to the hydraulic fracture. Second, in an elongated formation, for interporosity flow parameters approximated lower than 1x10-6, the transition period takes place during the formation linear flow period. It is desirable, not only to appropriately identify these types of systems but also to complement the conventional analysis with the adequate expressions, to characterize such formations for a more comprehensive reservoir/well management. So far, the conventional methodology does not account for the equations for interpretation of pressure tests under the above two mentioned conditions. Currently, an interpretation study can only be achieved by non-linear regression analysis (simulation) which is obviously related to non-unique solutions especially when estimating reservoir limits and the naturally fractured parameters. Therefore, in this paper, we provide and verify the necessary mathematical expressions for interpretation of a vertical well test in both a hydraulically-fractured naturally fractured formation or an elongated closed heterogeneous reservoir. The equations presented in this paper could provide good initial guesses for the parameters to be used in a general nonlinear regression analysis procedure so that the non-uniqueness problem associated with nonlinear regression may be improved.

Aplication of the TDS technique for determining the average reservoir pressure for vertical wells in naturally fractured reservoirs

Average reservoir pressure is used for characterizing a reservoir, computing oil in place, performing reservoir monitoring by material balance, estimating productivity indexes and predicting future reservoir behavior and ultimate recovery. It is truly important to understand much reservoir behavior in any stage of the reservoir life: primary recovery, secondary recovery and pressure maintenance projects. The average reservoir pressure plays a critical role in field appraisal, well sizing, and surface facilities sizing. Almost every well intervention job requires the knowledge of this parameter. No significant research was conducted during the last three decades on the determination of the average reservoir pressure. The majority of the existing methods for determining average reservoir pressure are based on conventional analysis and some of them use correction plots for specific reservoir shapes which made them of low practicity. A new methodology based on the Tiab Direct Synthesis (TDS) technique uses the pressure derivative for determination of the average reservoir pressure was introduced very recently for vertical and horizontal wells in homogeneous reservoirs. This technique has been extended to naturally fractured formations using information from the second straight line of the semilog plot. By default, all reservoirs are naturally fractured; estimating the average reservoir pressure for homogeneous reservoirs should be a specific case of naturally fractured reservoirs. Currently, the inverse procedure is performed. Therefore, in this article a new, easy and practical methodology is presented for the first time, estimating average reservoir pressure for naturally fractured reservoirs (heterogeneous systems) during pseudosteady-state flow period for vertical wells located inside closed drainage regions. This technique employs a new analytical equation which uses a single pressure point and the value of the pressure derivative corresponding to the late time pseudosteady state period eliminating the use of correction charts and type-curve matching. We verified the proposed technique with simulated cases for values of the interporosity flow parameter, Λ, of 1 and the storativity coefficient, , of 0 (homogeneous reservoir) and successfully compared to traditional techniques and by the application to one field case. This technique (Tiab, 1995) is accurate since it uses an exact analytical solution and matches very well the results from conventional analysis. It is also more practical and much easier to use than conventional analysis.

DEVELOPMENT AND APPLICATION OF INTERFERENCE TESTING DATA ANALYSIS MODEL FOR DUAL-POROSITY SYSTEM USING BOUNDARY ELEMENT METHOD

The main purpose of this paper is to develop a boundary element model in order to analyze the data from naturally fractured reservoirs with complex-shaped boundary. The model employs a boundary element method with free-space Green's function as a weighting function that makes it possible to handle multi-well system with geometrically complex boundary. The developed model has been validated by using the published actual field data for naturally fractured reservoir. The result shows that the model is capable of describing the transient pressure behavior representing the characteristics of naturally fractured reservoirs. The calculated permeability agrees well with the published result. In case of multi-well homogeneous reservoir system with complex geometry, both the transient state data and the data including boundary effect have been analyzed. The calculated permeabilities in each case were computed identically. This represents that the model can be effectively used for the analysis of data with boundary effect. In order to investigate the field applicability of the model, the actual field interference testing data performed in the Maljamar reservoir, New Mexico, USA were used. The relative fracture storage capacity and inter-porosity flow parameter were computed as 1.0 and 0.0, respectively. This implies that porosity and permeability of matrix are extremely low compared with those of fracture, and the flow occurs only through the secondary porosity system such as fracture network.

Analysis of pressure and pressure derivative without type-curve matching, 5. Horizontal well tests in naturally fractured reservoirs

Pressure transient analysis of horizontal wells penetrating naturally fractured reservoirs is a complicated and arduous task. That is, results from type-curve matching frequently suffer from nonuniqueness. Specialized plots (semilog or square root) are accurate but require individual plots for each identifiable flow regime. Subsequently, a new approach, known as direct synthesis, is proposed to overcome these problems. This method couples the characteristic points and lines from a log-log plot of pressure and pressure derivative data with the exact, analytical solution, resulting in simple equations to solve for the desired reservoir parameters. Two key naturally fractured parameters, storage coefficient (ω) and interporosity flow parameter (λ) are sought from the technique. Parametric analysis in dimensionless space illustrates the behavior of ω and λ and provides the basis for newly developed expressions relating these parameters to field data. Investigations show the timing of the transition period with respect to horizontal well flow regimes to be critical in the determination of the naturally fractured parameters. Several alternatives are illustrated along with the associated procedures for analysis. As a result of this work, direct synthesis simplifies evaluation of pressure tests in horizontal wells penetrating naturally fractured reservoirs, eliminates the trial-and-error approach of type-curve matching and has the advantages of being easily verifiable and applicable to incomplete pressure data. Examples are given to demonstrate the technique and accuracy.

Transient 2D Flow in Layered Reservoirs With Crossflow

Summary Analytical solutions of transient 2D flow through double-permeability media are presented. The pressure response of a vertically fractured well intercepting a layered reservoir with crossflow is described through the methods of integral transform and variable separation. The influences that parameters of a double-permeability model such as the permeability ratio, Fk interporosity flow parameter, λ, and storativity ratio, ω, have on the pressure response of a fractured well are calculated and analyzed by numerical inversion. Log-log diagnosis graphs of fractured well pressure are given and analyzed here.

The transient two-dimensional flow through double porous media

This paper presents the analytical solutions in Laplace domain for two-dimensional nonsteady flow of slightly compressible liquid in porous media with double porosity by using the methods of integral transforms and variables separation. The effects of the ratio of storativities ω, interporosity flow parameter λ on the pressure behaviors for a vertically fractured well with infinite conductivity are investigated by using the method of numerical inversion. The new log-log diagnosis graph of the pressures is given and analysed.

A Method for Estimating the Interporosity Flow Parameter in Naturally Fractured Reservoirs

Abstract For naturally fractured reservoirs of the double-porosity type, Warren and Root defined two parameters characterizing such systems, F ft, and epsilon. While F ft may be obtained easily from the straight lines of the buildup or drawdown plot, no explicit method for estimating epsilon was plot, no explicit method for estimating epsilon was suggested in the original paper.This paper presents a method whereby the coordinates of the inflection point on a buildup or drawdown plot may be used to estimate epsilon. We show that for pressure drawdown tests, epsilon can be estimated under certain conditions, while for pressure buildup tests, only the ratio of the interporosity flow parameter to the total system porosity/compressibility parameter to the total system porosity/compressibility product, epsilon/[(phi ct)f + (phi Ct)ma], is obtained. product, epsilon/[(phi ct)f + (phi Ct)ma], is obtained. By using the concept of inflection points, an equation is derived where F ft may be obtained from a pressure buildup or drawdown test when no early- or late-time data are available. Introduction Warren and Root presented a solution to the problem of radial flow of a slightly compressible problem of radial flow of a slightly compressible fluid in a naturally fractured reservoir. They assumed that flow occurs only in the fractures and that the matrix blocks, assembled as a uniformly distributed source, deliver the fluid to the fracture system. They characterized such a system by two parameters related to the properties of the reservoir. One of these parameters, the fluid capacitance coefficient, F ft, parameters, the fluid capacitance coefficient, F ft, is used to represent the ratio of the porosity/ compressibility product for the fractures to that for the entire system: (phi ct)f/[(phi ct)f + (phi ct)ma]. The second parameter, epsilon, is defined as the interporosity flow parameter, which indicates the degree of interporosity flow between the matrix blocks and the fracture system. As shown by Kazemi, the fluid capacitance coefficient may be obtained from the following equation: F ft = antilog (-delta p/m)...................(1) where, delta p = vertical separation of the two straight lines on a buildup or drawdown test plot, psi (kPa); and m = slope of the straight lines on a buildup or drawdown test plot, psi/cycle (kPa/cycle). While the computation of F ft from this equation is straight-forward, no clear method of finding epsilon has yet been proposed. In the original paper, Warren and Root did not elaborate on a suitable method for the determination of epsilon. Kazemi discussed the use of interference test data to find the total system porosity/compressibility product, (phi ct) f + (phi ct)ma. Using this information, a trial-and-error procedure may be applied to the pressure buildup equation procedure may be applied to the pressure buildup equation to obtain a satisfactory answer for epsilon. The optimum epsilon was defined as the value resulting in the best curve fit of the theoretical equations to the field data. SPEJ p. 324

The Interpretation of Interference Tests in Naturally Fractured Reservoirs with Uniform Fracture Distribution

Abstract The double-porosity model of Warren and Root for examining pressure drawdown and buildup phenomena in naturally fractured reservoirs has been extended to interpret interference test results. Both analytical and numerical solutions are presented. The practicality of some of the assumptions in the Warren-Root model was also investigated. The standard procedure for interpreting interference tests in naturally fractured reservoirs heretofore employed an equivalent homogeneous reservoir model. A comparison of our results with the equivalent homogeneous model indicates the latter is inadequate for early time responses. For late time responses, however, the simpler equivalent homogeneous model yields favorable results. Finally, the effects of well spacing and the magnitude of the interporosity flow parameter are briefly cited. Introduction Interference tests can be used to provide reservoir information not obtainable from conventional pressure drawdown and buildup tests. The technique involves measuring the response in one or more wells arising from a pressure perturbation introduced into another well. It has been successfully applied to single-layer, homogeneous, unfractured, isotropic and anisotropic formations to arrive at values of well storage capacity and a measure of directional permeability.