All transient test interpretation methods rely on or utilize diagnostic plots for the identification of wellbore or fracture storage distortion, flow regimes, and other parameters (e.g., minimum horizontal stress). Although all "test" interpretations of interest are transient test data (i.e., those involving an "event"), the associated diagnostic plots are not interchangeable between such tests. The objective of this work is to clearly define the appropriate diagnostic plot(s) for each type of transient test. The work applies the appropriate transient test theory to demonstrate the applicability of each diagnostic plot along with clearly defining the characteristic features that make a given plot "diagnostic." For pressure transient testing, the material is largely a review, but for rate transient tests and diagnostic fracture-injection/falloff tests, new ideas are introduced and documented to justify appropriate diagnostic plots. Data examples are provided for illustration and application. In general, pressure transient test diagnostic plots are not misused, but the same cannot be said for diagnostic fracture-injection/falloff tests (or DFITs) where it is common to ascribe flow regimes and/or draw other erroneous conclusions based on observations from an inappropriately constructed or interpretated diagnostic plot. The examples provided illustrate both the correct diagnostic plot and interpretations, but also illustrate how data can be easily misinterpreted in common practice.

Abstract Unconventional reservoirs, including shale formations and many tight-gas sands, contain natural fractures, fissures, faults, and microfractures that contribute to the rock flow capacity. In most cases, core-measured permeability, and especially crushed-core permeability measurements, may not be representative of the true reservoir rock flow capacity. Evaluating the in-situ rock permeability, and simulating production, requires sampling not only the matrix, but also the fractures and fissures that contribute to the unconventional rock system permeability. A properly designed well test in an unconventional reservoir will sample a volume of reservoir rock that is representative of the whole. In other words, a well test should sample a representative elementary volume, which is the smallest volume of rock with properties characteristic of the whole. Diagnostic fracture-injection/falloff tests (DFIT) have been routinely implemented since the late 1990s to understand leakoff mechanisms, identify fracture closure stress, estimate initial reservoir pressure, and determine permeability-thickness in unconventional reservoirs. In almost every unconventional well completed, a DFIT is the only well test that will be completed during the well lifecycle, but historically, the tests have been designed empirically based on analog formations and without considering the volume of rock investigated. We demonstrate a new method for calculating the volume of rock investigated by a DFIT, and we show how a DFIT design can allow for sampling a representative elementary volume of the reservoir.

Abstract Unconventional reservoirs, including shale formations and many tight-gas sands, contain natural fractures, fissures, faults, and microfractures that contribute to the rock flow capacity; thus, core-measured permeability, and especially crushed-core permeability measurements, may not be representative of the true reservoir rock flow capacity. Evaluating the in-situ rock permeability, and simulating production, requires sampling not only the matrix, but also the fractures and fissures that contribute to the unconventional rock system permeability. A properly designed well test in an unconventional reservoir will sample a volume of reservoir rock that is representative of the whole. In other words, a well test should sample a representative elementary volume, which is the smallest volume of rock with properties characteristic of the whole. Diagnostic fracture-injection/falloff tests (DFIT) have been routinely implemented since the late 1990s to understand leakoff mechanisms, identify fracture closure stress, estimate initial reservoir pressure, and determine permeability-thickness in unconventional reservoirs. In almost every unconventional well completed, a DFIT is the only well test that will be completed during the well lifecycle, but historically, the tests have been designed empirically based on analog formations and without considering the volume of rock investigated. We demonstrate a new method for calculating the volume of rock investigated by a DFIT, and we show how a DFIT design can allow for sampling a representative elementary volume of the reservoir.

Abstract Prefrac pressure diagnostics, including fracture-injection/falloff sequences, have been used for several years to estimate initial reservoir pressure and transmissibility in unconventional reservoirs. Prior to performing pressure diagnostics, initial or average reservoir pressure is almost always unknown, and many times the purpose of a pressure diagnostic is to determine initial reservoir pressure. As shown by several authors, when a pressure diagnostic falloff exhibits bilinear, linear, or radial flow, the initial or average reservoir pressure can be determined from special plots using straight-line analysis methods. However, correctly identifying the flow regimes during a pressure falloff is often very difficult, and the tendency is to incorrectly apply straight-line analysis methods to data on a specialized plot that often does not correspond to a bilinear, linear, or radial flow regime. In many cases, bilinear, linear, or radial flow will not be observed in any of the falloff data, and valid estimates of initial reservoir pressure and transmissibility cannot be determined using straight-line methods. This paper presents a new type curve analysis method that removes the limitations of conventional after-closure straight- line analysis of pressure diagnostics. Like conventional well test analysis, the new method fits observed pressure data to analytical type curves, and type curve match points are used to determine initial reservoir pressure, transmissibility, fracture half-length, fracture conductivity, and fracture damage. Type curve analysis has proved especially useful for post-frac evaluation of stimulation effectiveness, and has also proved useful in shale reservoirs where it is often difficult to determine if a dilated fracture or fracture network close completely, with no conductivity or retained residual width. Understanding dilation/contraction properties of a shale fracture network can provide important guidance for fracture treatment design and optimization. Type curve analysis has also reduced the amount of shut-in time required to obtain a quantitative estimate of reservoir and fracture properties albeit with increasing uncertainty as shut-in time decreases.

Abstract Since the discovery of the Jonah field in 1977, many styles of hydraulic fracturing treatments have been employed to stimulate the Lance formation. Commercial production was not established in the field until the early 1990s, and technological improvements have permitted increased production since that time. Further trials of fracturing techniques, including slickwater fracs, induced stress diversion, and flow-through composite fracture plugs, continued over time. Since March 2010, channel fracturing treatments have been employed in the Lance formation in conjunction with more traditional, conventional fracturing treatments. For the purpose of this paper, conventional fracturing treatments consist of either crosslinked gel or slickwater fracturing treatments. The proppant is added in a continuous manner with an increasing proppant concentration. For crosslinked gel treatments, the typical proppant is 20/40 -mesh white sand added up to a maximum of 6 lbm/gal. For the slickwater treatments, the typical proppant is 40/70- or 30/50- mesh white sand added up to a maximum of 3 lbm/gal. The channel fracturing treatments use a pulsed method of adding the proppant to the fluid. Instead of adding the proppant continuously, the proppant is turned on and off in approximately 15-second time intervals. This concept is intended to provide high-conductivity, unpropped open flow paths through hydraulic fractures held open by the proppant pillars. To assess the effectiveness of the channel fracturing method in the Jonah field compared to conventional fracturing treatments, a spatial sampling technique was used. Spatial sampling is a documented method for comparing large groups of wells with their direct offsets. The original intent of the spatial sampling method was to identify underperforming wells; however, the method has also been employed as a way to compare various completion or stimulation techniques. In this case, spatial sampling was applied in an attempt to evaluate the effectiveness of the channel fracturing technique compared to conventional fracturing techniques using continuous proppant addition during the treatment. Five discrete areas of the Jonah field were included in the study. Only wells completed in the same time frame as the channel fractured wells were included. The treatment and production data for all wells were obtained from public sources. There might also be differences in production among the conventionally fractured wells, depending on whether a crosslinked or slickwater treatment was used; however, the effect of slickwater treatments, as opposed to crosslinked treatments, was not considered in this study.

Abstract Multidirectional linear trends are commonly observed in maps of microseismic events recorded during fracture stimulation. Since Fisher drew lines through an animated map of microseismic events (Fisher et al. 2002), the industry has recognized that complex-fracture patterns can develop during hydraulic fracturing. Consequently, several new complex-fracture propagation models have been introduced to "match" the stimulated reservoir volume observed in maps of microseismic events recorded during hydraulic fracturing. Every complex-fracture propagation model requires geometric input, including a pattern of discontinuities in the rock that can dilate or propagate during hydraulic fracturing; however, defining a pattern of discontinuities is a challenging task in a subsurface rock formation that cannot be observed directly. We present a new method for defining a geometric model for input into a complex-fracture model using microseismic events recorded during fracturing. Events are animated and planar trends are identified to define natural fracture orientation, trace length, dip angle, and natural fracture density within the stimulated reservoir volume. Statistical analysis of the natural fracture properties allows probability distributions to be defined for each fracture property, which are then used to generate stochastic natural fracture patterns for input into a complex-fracture model.

Summary Since the introduction of the G-function derivative analysis, prefrac diagnostic injection tests have become a valuable and commonly used technique. Unfortunately, the technique is frequently misapplied or misinterpreted, leading to confusion and misdiagnosis of fracturing parameters. This paper presents a consistent method of analysis of the G-function, its derivatives, and its relationship to other diagnostic techniques including square-root(time) and log(∆pwf)-log(∆t) plots and their appropriate diagnostic derivatives. Four field test examples are given for the most common diagnostic curve signatures. These show how multiple analysis methods can be applied to consistently interpret closure pressure and time, as well as pre- and post-closure flow regimes and reservoir properties from the test data. The cases include normal constant-area and constant permeability leakoff, pressure dependent fissure leakoff, fracture tip extension, and variable fracture storage. In some cases conventionally accepted analysis methods, such as the Sqrt(time) plot, can lead to misleading interpretations. A single consistent approach to analysis is described for each case. The example cases can be used to build a foundation for consistent and less ambiguous analysis of any complex fracture injection/falloff test.

Abstract In an effort to examine well and reservoir connectivity for wells drilled through multiple low-permeability stacked lenticular reservoirs, we present case histories from the Piceance basin of Western Colorado. We review the completion and subsequent abandonment of an air-drilled high-angle slant hole through the Williams Fork sandstones in Grand Valley field as well as a high-angle slant hole drilled through and completed in two Williams Fork Mesaverde sandstones. We also review a case history describing single-entry-point fracture treatments in vertical wells designed to "frac into" sandstones near the entry point, and we describe a post-frac evaluation of propped fracture communication with sandstones adjacent to the single entry point. Lastly, we present a case history showing the results of a refracture-candidate evaluation and isolated-layer restimulation pilot program in the Piceance Basin where it is known that between 10% and 30% of the Meseverde layers targeted for fracturing are ineffectively stimulated or inadvertently bypassed during primary fracturing operations. The refracture-candidate pilot program provided the following. An evaluation of production logs as a refracture-candidate diagnostic. An evaluation of short-term pressure buildup tests as a refracture-candidate diagnostic. An evaluation of fracture-injection/falloff tests as a refracture-candidate diagnostic. Four discrete Mesaverde sandstones were tested as part of the refracture-candidate pilot program. Of the four layers selected for testing, numerous microseismic events were mapped during the initial fracture treatments in two, and no events were recorded in the other two. The refracture-candidate pilot program included recording a new production log and completing short-term pressure buildup and nitrogen fracture-injection/falloff tests in each isolated layer. The nitrogen fracture-injection/falloff tests confirmed the microseismic mapping during the original completion, that is, layers without microseismic events did not have a conductive hydraulic fracture based on the nitrogen-injection/falloff analysis. Consequently, bypassed or ineffectively stimulated layers can be identified with refracture-candidate diagnostics.

Abstract Since the introduction of the G-function derivative analysis, pre-frac diagnostic injection tests have become a valuable and commonly used technique. Unfortunately, the technique is frequently misapplied or misinterpreted leading to confusion and misdiagnosis of fracturing parameters. This paper presents a consistent method of analysis of the G-function, its derivatives, and its relationship to other diagnostic techniques including square-root(time) and log(Δpwf)-log(Δt) plots and their appropriate diagnostic derivatives. Actual field test examples are given for the most common diagnostic curve signatures.

A new fracture-injection/falloff type-curve analysis method is presented for reservoirs containing slightly compressible and compressible fluids. Type-curve analysis augments conventional before- and after-closure methods, which are also reformulated in terms of adjusted pseudopressure and adjusted pseudotime to account for compressible reservoir fluids. Unlike before- and after-closure methods which only apply to specific (i.e., small) portions of the falloff data, the new type-curve method allows for analyzing all falloff data from the end of the injection through fracture closure, pseudolinear flow, and pseudoradial flow. Similar to conventional well test analysis, a satisfactory interpretation requires comparable and consistent results between the special analysis methods, before- and after-closure, and type-curve analysis.

A new analytical pressure transient solution (constant rate) for a well containing multiple arbitrarily-oriented uniform-flux, infinite-conductivity, or finite-conductivity fractures in an infinite-slab reservoir is presented. The multiple-fracture solution is derived using a new uniform-flux solution for a single arbitrarily-oriented fracture in an anisotropic reservoir. The variables in this solution are: fracture half-length, fracture conductivity, and fracture angle of rotation for each fracture relative to the primary fracture. Example constant-rate type curves are provided for two intersecting fractures – cruciform or oblique – and three intersecting fractures – trifracture.

Summary The permeability, pore pressure, and leakoff type interpreted from more than 1,200 diagnostic fracture-injection/falloff tests were collected in a database and statistically evaluated for four Rocky Mountain basins. The statistical analysis includes the range of observed permeability and pore pressure and the fracture leakoff type distribution. The analysis reveals that pressure-dependent leakoff, fracture-tip extension during shut-in, and fracture-height recession during shut-in are the most common leakoff types. Overall, pressure-dependent leakoff, which can be indicative of highly productive fractured reservoirs, is the most common leakoff type in all Rocky Mountain basins. The analysis also shows orders-of-magnitude variation in gas permeability within all basins, with observed gas permeability ranging from less than 0.001 to greater than 0.10 md.

A new refracture-candidate diagnostic test is presented that requires a brief injection at a pressure exceeding the fracture initiation and propagation pressure followed by an extended shut-in period with the pressure falloff recorded. Provided the time of injection is short relative to the reservoir response, the pressure falloff can be analyzed as a slug test by transforming and plotting the falloff data on a variable-storage, constant-rate drawdown type curve for a well producing from single or multiple finite- or infinite-conductivity vertical fractures in an infinite-acting reservoir. Characteristic variable storage behavior is used to diagnose a pre-existing fracture retaining residual width and to determine if a pre-existing fracture is damaged. Using the proposed model and analysis methodology, a quantitative type-curve/model match can be used to estimate reservoir properties. In addidtion to the new fracture diagnostic solution, a new single-phase fracture-injection/falloff dimensionless pressure solution is also provided along with new pressure-transient solutions for a well producing from multiple arbitrarily-oriented finite- or infinite-conductivity fractures.

Abstract A minifrac test is usually performed before a fracture stimulation treatment to calculate formation and fracture properties. Recently the analysis techniques were extended to the after-closure period. The after-closure data are analyzed to calculate formation permeability and reservoir pressure. Technology developers have hypothesized the existence of either pseudo-radial or linear flow behavior during the after-closure region. Identifying the presence of the flowing regime is an awkward process at best. The roots of the linear flow equations are different from those of the pseudo-radial flow equations. Many tests do not follow either flow regime. In this paper, we have created a general approach for analysis of after-closure pressure decline data. Because the determination of the flow regime and type of fracture depends only on time and monitored pressure, the analysis may even be performed in real time. The technique determines whether sufficient data have been obtained to perform a reliable analysis. The calculated parameters would be used to update the fracture design and, in turn, for performing the fracture treatment. The new technique is simpler and more generalized than what currently exists. The technique initially determines whether analyzable data exist. It shows that three flow regimes may dominate the after-closure region, depending on the reservoir properties and residual fracture conductivity. The technique presented not only determines the type of regime, and consequently, the type of residual fracture, it also determines the formation permeability and reservoir pressure. There is no reason to restrict the application of this test to minifrac test analysis. We believe the approach is also applicable to analysis of data after performing a fracture stimulation treatment. A numerical simulator was used to model the pumping and closure process and to validate the new approach. The paper also presents a detailed discussion and analysis of several field cases, demonstrating the various flow regimes and, ultimately, the validity of the developed technique.