Data Acquisition and Interpretation of Horizontal Well Pressure-Transient Tests
Authors: Lichtenberger Gunter J. 
Published: December 2007

Summary
Using the concept of flow regimes and drawing on analogies with vertical wells, this paper reviews the pressure-transient behavior of horizontal wells. Practical guidelines are given for planning, executing, and interpreting horizontal well tests. The application of various interpretation techniques is illustrated with field examples.

Introduction
For both vertical and horizontal wells, pressure-transient testing is a powerful tool for evaluating in-situ reservoir and wellbore parameters that describe the production characteristics of a well. Although many operators use horizontal well technology, many engineers consider pressure-transient testing of horizontal wells impractical and too complex. Experience has shown, however, that with adequate test planning, based on the concept of flow regimes and focused on optimizing test conditions, horizontal well testing can be as successful as vertical well testing. The objective of this paper is to provide the practicing engineer with guidelines for planning and executing horizontal well tests and to illustrate interpretation techniques with some field examples.

Flow Regimes in Horizontal Wells
Theoretical solutions to the horizontal well problem published in the literature1–4 show that transient pressure data from horizontal wells may display dominant flow regimes, such as radial or linear flow, that resemble those observed in vertical wells. This is not surprising because the physics of the early-time flow behavior of a horizontal well is similar to that of a vertical well between two parallel boundaries. At later times, a vertical well with a vertical fracture is a good analogy. Theory also shows that these flow regimes can be expected to develop within specific time windows with dimensions determined by the reservoir and fluid parameters.
Flow regimes can be identified with a diagnostic plot of the field data, where the observed pressure change, ?p, and the logarithmic derivative, p'=dp/d(ln t), are plotted vs. the elapsed time, t, on a common log-log coordinate grid.
Consider a large homogeneous reservoir with permeabilities kH and kV, filled with a slightly compressible single-phase fluid. Let the horizontal well be located within a productive interval of net thickness, h, bounded by upper and lower no-flow boundaries, where the wellbore and the bedding planes are truly horizontal (Fig. 1). Assume that the well is put on production at time t=0 at a constant rate, q, and fluid entry occurs uniformly over an effective wellbore length, Lw, where Lwh. Furthermore, assume that the pressure drop in the wellbore is negligible. Fig. 2 shows the sequence of flow regimes that may be observed during the early phases of production. Familiarity with these flow regimes is the foundation of test planning and interpretation.

Wellbore Storage.
If we ignore influx near the ends of the wellbore, fluid withdrawal will initially produce radial flow for kH=kV (or elliptical flow for kH kV) in the reservoir. Because the wellbore is not shut in at the sandface, the initial pressure response may be distorted or dominated by wellbore storage effects and therefore may not show the early-time radial flow characteristics discussed below.
For a constant wellbore storage coefficient, C, wellbore-storage-dominated flow is identified on the diagnostic plot by a collinear graph of ?p and p' with unit slope. During this period, conventional interpretation methods will yield no information about the reservoir or completion parameters. The end of the unit slope and the start of interpretable data, tEus, can be estimated from Eq. 1 in Table 1 (see Table 1 for all equations), which is derived from Agarwal et al.'s5 correlation and the traditional "rule of 50."*
The wellbore storage coefficient, C, for a wellbore filled with a single-phase fluid is calculated from Eq. 2. Eq. 3 is for a liquid with a free gas/liquid interface in a wellbore of volume per unit length, Vu, making an angle, with the vertical, ?.
The most reliable value for C is obtained from data points on the unit slope of the diagnostic plot (see Eq. 4). Although C can be much larger for horizontal wells than for vertical wells in the same formation, tEus for horizontal wells is usually not much larger because the higher value of C in Eq. 1 is offset by Lw.

Early-Time Radial Flow.
On the diagnostic plot, the signature of fully developed radial (or elliptical) flow is a constant derivative, p'. A plot of p vs. log(t) will be a straight line with slope m, which yields kHkV from Eq. 5.
The mechanical skin factor, sm, which is a measure of the completion quality,7 can be calculated from Eq. 6.
Note that kV is a macroscopic average over the depth of investigation in the vertical direction. In the presence of thin shale layers, kV may be considerably less than values reported by core analysis. As for vertical wells, the transition period between wellbore storage and fully developed radial flow can be analyzed with conventional type-curve matching techniques. Early-time radial flow will end either when the radius of investigation reaches the nearest boundary, as given by Eq. 7, or when production from near the ends of the wellbore becomes important, as calculated from Eq. 8.4
Horizontal wells can also display hemiradial and pseudoradial flow periods where p' is constant. With the possibility that wellbore storage may mask early-time flow signatures, the appropriate time-window equations or simulation should be used to verify the flow period assignments. In a nonisotropic reservoir, at least one subsequent flow regime must be observed to resolve kH and kV.

Wellbore Storage.
If we ignore influx near the ends of the wellbore, fluid withdrawal will initially produce radial flow for kH=kV (or elliptical flow for kH kV) in the reservoir. Because the wellbore is not shut in at the sandface, the initial pressure response may be distorted or dominated by wellbore storage effects and therefore may not show the early-time radial flow characteristics discussed below.
For a constant wellbore storage coefficient, C, wellbore-storage-dominated flow is identified on the diagnostic plot by a collinear graph of ?p and p' with unit slope. During this period, conventional interpretation methods will yield no information about the reservoir or completion parameters. The end of the unit slope and the start of interpretable data, tEus, can be estimated from Eq. 1 in Table 1 (see Table 1 for all equations), which is derived from Agarwal et al.'s5 correlation and the traditional "rule of 50."*
The wellbore storage coefficient, C, for a wellbore filled with a single-phase fluid is calculated from Eq. 2. Eq. 3 is for a liquid with a free gas/liquid interface in a wellbore of volume per unit length, Vu, making an angle, with the vertical, ?.
The most reliable value for C is obtained from data points on the unit slope of the diagnostic plot (see Eq. 4). Although C can be much larger for horizontal wells than for vertical wells in the same formation, tEus for horizontal wells is usually not much larger because the higher value of C in Eq. 1 is offset by Lw.

Early-Time Radial Flow.
On the diagnostic plot, the signature of fully developed radial (or elliptical) flow is a constant derivative, p'. A plot of p vs. log(t) will be a straight line with slope m, which yields kHkV from Eq. 5.
The mechanical skin factor, sm, which is a measure of the completion quality,7 can be calculated from Eq. 6.
Note that kV is a macroscopic average over the depth of investigation in the vertical direction. In the presence of thin shale layers, kV may be considerably less than values reported by core analysis. As for vertical wells, the transition period between wellbore storage and fully developed radial flow can be analyzed with conventional type-curve matching techniques. Early-time radial flow will end either when the radius of investigation reaches the nearest boundary, as given by Eq. 7, or when production from near the ends of the wellbore becomes important, as calculated from Eq. 8.4
Horizontal wells can also display hemiradial and pseudoradial flow periods where p' is constant. With the possibility that wellbore storage may mask early-time flow signatures, the appropriate time-window equations or simulation should be used to verify the flow period assignments. In a nonisotropic reservoir, at least one subsequent flow regime must be observed to resolve kH and kV.