Diagnostic Fracture Injection Tests Research Articles

A Simple Unified Pressure-Transient-Analysis Method for Fractured Waterflood Injectors and Minifractures in Hydraulic-Fracture Stimulation

Summary Pressure-transient analysis (PTA) is commonly used in the industry to estimate parameters such as dimensions (length, height) and skin of induced (hydraulic) fractures, and reservoir permeability. PTA-interpretation methods are well-established for the limiting cases of low leakoff [mini-fracture analysis (MFA) and diagnostic-fracture-injection tests (DFITs) of stimulation hydraulic fractures] and high leakoff [injection-falloff (IFO) analysis of waterflood-induced fractures]. However, traditional methodologies used for these two limiting cases differ fundamentally and there exists no established approach for intermediate leakoff, in spite of many efforts to date. We present detailed numerical simulations of fracture closure as a result of shut-in and after-closure reservoir flow following hydraulic-fracture propagation at arbitrary rate and for arbitrary leakoff (from very low to very high). By use of the trends resulting from these simulations, we propose a novel, very-simple analytical PTA method for estimating fracture dimensions, skin, leakoff coefficient, and reservoir permeability. This method is applicable to fractured waterflood injectors and to mini-fractures in hydraulic-fracture stimulation. It presents a consistent approach to before-closure analysis (BCA) and after-closure analysis (ACA). We compared the numerical simulations with our novel analytical PTA method with more conventional MFA and IFO approaches, such as g-functions and other existing BCA and ACA methods. For all these cases, it is demonstrated that the currently existing approaches present limiting cases for either low leakoff (MFA) or high leakoff (IFO) of our proposed PTA method, and that our novel methodology provides superior results to the existing approaches, particularly in the intermediate-leakoff range. We also use our numerical methodology to demonstrate that more recently proposed analysis methods by use of generalized versions of the Agarwal/Bourdet et al. (1989) derivative do not necessarily result in a “correct” interpretation, in particular with respect to identifying the point of fracture closure. With respect to the latter, we also demonstrate that in many cases, unique identification of fracture closure from PTA will be very difficult. Finally, we apply our PTA method to a few field cases, thereby demonstrating its simplicity of usage.

A new methodology for estimating field horizontal stress from microseismic focal mechanisms

The full stress state in a formation is characterized by the directions and magnitudes of the three principal stresses. It is common practice to take the vertical stress, ϭv, and the minimum and maximum horizontal stresses, ϭhmin and ϭHmax, as the principal stresses in unconventional reservoirs. Considering the relatively high depth of most unconventional reservoirs, which results in a very high vertical stress magnitude, this assumption holds true in most cases unless a geological feature such as a fault or fold changes the stresses locally. The magnitude of vertical stress can easily be determined by integrating the density of overburden rocks from density logs. A good estimate of ϭhmin magnitude can be obtained from well test results such as a mini-frac test or a diagnostic fracture injection test. The magnitude of ϭHmax, however, remains the most challenging stress component to determine.

The Fracture-Compliance Method for Picking Closure Pressure From Diagnostic Fracture-Injection Tests

SummaryIn this paper, we present the fracture-compliance method, a technique for estimating the closure pressure from diagnostic fracture-injection tests (DFITs). The method is based on the observation that fractures retain a finite aperture after asperities come into contact (mechanical closure). An empirical, nonlinear joint-closure law is used to relate the after-closure fracture aperture and stiffness (the reciprocal of compliance) to effective normal stress. Fracture closure increases fracture stiffness, which, in low-permeability formations, causes an increase in the pressure derivative. On the basis of these insights, we propose the fracture-compliance method, which consists of picking closure at the first point of deviation from linearity on a plot of pressure or G×dP/dG vs. G-time (after the end of the very-early-time transient associated with wellbore and near-wellbore friction and fracture tip-extension). The contribution of this paper is to provide theoretical justification for why closure is best picked with the fracture-compliance method, and not with other widely used methods. We provide a series of numerical DFIT simulations to demonstrate the sensitivity of the pressure transient to input parameters. Governing equations are derived and used to demonstrate the effect of changing fracture aperture after closure. A field DFIT data set is analyzed with the new method. Finally, a field example is presented in which downhole tiltmeter measurements provide an independent estimate of the minimum principal stress.

Re-examining interpretations of non-ideal behavior during diagnostic fracture injection tests

Diagnostic fracture injection tests (DFITs) are performed in low permeability formations to estimate the minimum principal stress, formation pressure, permeability, and other parameters. G-function derivative plots are used for diagnosing fracture closure and “non-ideal” reservoir processes. In this study, we use a discrete fracture network hydraulic fracturing simulator to investigate non-ideal DFIT mechanisms. The simulator fully couples fluid flow with the stresses induced by fracture deformation. DFITs are simulated for six different scenarios: a single hydraulic fracture, multiple fracture strands, opening of transverse fractures, near-wellbore complexity, far-field complexity, and height recession. The results indicate that pressure transient behavior commonly ascribed to “fracture height recession,” “closure of transverse fractures,” and “fracture tip extension” are likely to be misinterpreted by conventional techniques. In previous studies, we found that a curving upward G×dP/dG plot is caused by changing fracture stiffness after closure and that the closure pressure is best picked when G×dP/dG begins to deviate upward. In contrast, the commonly used “tangent” method can significantly underestimate the minimum principal stress. The results of this study confirm those prior results. The results suggest that in most cases, it should be possible to use pump-in/flowback tests to confirm estimates of the minimum principal stress. However, if a flow bottleneck occurs at the wellbore due to near-wellbore complexity, the pump-in/flowback test may be uninterpretable.

Probing diagnostic fracture injection tests in unconventional reservoirs

Abstract Diagnostic fracture injection tests (DFIT) are commonly used to characterize stress and reservoir properties in unconventional reservoirs. Although simple in concept, interpreting DFIT results can be difficult because several factors can cause results to deviate from ideal DFIT behavior. Some examples of non-ideal DFIT behavior include steep pressure declines after shut-in, absence of pseudo-linear and pseudo-radial flow, and excessive storage indications. Such deviations from ideal DFIT behavior challenge our ability to estimate formation properties reliably. Potential drivers of non-ideal behavior include heterogeneous rock properties, complex rock/fluid interaction, multiphase effects, and natural fractures. The objective of this study is to investigate how these factors can impact DFIT results and interpretations. A comprehensive approach was taken using a combination of pressure transient analysis, frac modeling, analytical leak-off modeling, and detailed numerical simulation of DFIT behavior. The application was for a horizontal well, completed in a shale gas reservoir, which included an actual field DFIT. Detailed modeling included full wellbore transients and storage, hydraulic behavior through induced fractures, as well as complex interactions between rock, fluids, and natural fractures. It was determined that the actual DFIT showed indications of a complex network created by the pump-in. Closure pressure estimates were found to be reliable, between the simulation cases and DFIT analysis. However, a consistency check on initial reservoir pressure had to be used to obtain reasonable estimates compared to the simulation input. Finally, estimates of reservoir conductivity were highly uncertain compared to the actual simulation inputs. Furthermore, the actual DFIT estimates of reservoir pressure and conductivity were found to be overoptimistic. In fact, the estimated ultimate recovery using DFIT-based permeability-thickness product turned out to be more than twice the estimated ultimate recovery using the integrated core, log, and a pressure-buildup test.

Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.

Understanding Unusual Diagnostic-Fracture-Injection-Test Results in Tight Gas Fields

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 172956, “Understanding Unusual Diagnostic-Fracture-Injection-Test Results in Tight Gas Fields: A Holistic Approach To Resolving the Data,” by R.N. Naidu, E.A. Guevara, A.J. Twynam, J. Rueda, W. Dawson, E. Moses, and M. Rylance, BP, prepared for the 2015 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 26–28 January. The paper has not been peer reviewed. In hydraulic fracturing, the use of diagnostic-fracture-injection tests (DFITs) can provide valuable information. When the measured pressures in such tests are outside the expected range for a given formation, however, a number of possibilities and questions can arise. A recently completed project faced just such a challenge, initially resulting in poor hydraulic-fracturing efficiency and a need to understand the root cause. To this end, a thorough analysis involving a multidisciplinary review team from several technical areas was undertaken, which is described in the complete paper. Introduction Block A lies adjacent to other existing hydrocarbon-producing fields, residing within a large recognized basin. Five vertical exploration and appraisal wells were drilled in Block A to a depth of approximately 2400 m. Initially, these appraisal wells were designed for conventional reservoirs. A brief description of the lithology, rock characteristics, and drilling history is provided in the complete paper. The First DFIT Challenges: Well 1, Stage 1 From the historical regional fracturing-pressure data available, the breakdown and fracturing pressures that would be experienced at the wellhead were predicted to be less than 7,500 psi. During the first DFIT injection operation, the maximum allowable surface pressure was reached without any clear indication of breakdown being achieved in the formation. Several attempts were made to inject into the formation, but there was no effective breakdown and a very low decline rate was subsequently observed. The high treating pressure observed was initially considered to be potentially a result of plugging of the perforation tunnels or of formation damage. Subsequently, an acid cleanup and an injectivity test were performed with coiled tubing (CT); however, there was no significant positive formation response to this intervention. The wellhead-pressure-limitation setting was increased to allow a new maximum pressure of 9,500 psi, and the DFIT was attempted once again. A breakdown was finally achieved at a wellhead pressure (WHP) of 8,500 psi, equivalent to a bottomhole pressure (BHP) of 12,341 psi while pumping at 1 bbl/min; a maximum rate of 2 bbl/min was achieved during this DFIT attempt. A 35-lbm linear-gel system was subsequently injected into the formation to determine if the surface pressures would allow execution of the planned main fracture treatment, but results indicated otherwise. A decision was made to isolate Stage 1 with a sand plug and to proceed to Stage 2 immediately. Hydraulic-Fracturing and Cleanup Experiences CT nitrogen lifting was chosen for unloading the wells. The operational details of the fracturing treatments, including minifracture injection, and the well performance during cleanup are described in this summary for Stage 2 and Stage 3 in Well 1. Stage 1 and Stage 2 in Well 2 are described in the complete paper.

Modeling Transient Wellbore Temperature During Diagnostic Fracture Injection Tests

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166120, ’Modeling Wellbore Transient Fluid Temperature and Pressure During Diagnostic Fracture Injection Testing in Unconventional Reservoirs,’ by B. Nojabaei, SPE, The Pennsylvania State University, A.R. Hasan, SPE, Texas A&M University, and C.S. Kabir, SPE, Hess, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. Diagnostic fracture injection tests (DFITs) have gained widespread usage in the evaluation of unconventional reservoirs. In typical field operations, pressure is measured at the wellhead, not at the bottom of the hole. The bottomhole pressure (BHP) is obtained by adding a constant hydrostatic head of the water column to the wellhead pressure (WHP) at each timestep. One can question the soundness of this practice because of significant changes in temperature that occur in the wellbore, leading to changes in density and compressibility throughout the fluid column. This paper offers an analytical model for estimating the transient temperature at a given depth and timestep, for computing the BHP. Temperature Model During Pressure-Falloff Test After a well is shut in at the surface, afterflow at the sandface is negligible because of low formation permeability. Upon cessation of injection, the cold injection water begins to gain heat from the surroundings. Heat transfer during flowing and shut-in conditions has been modeled with an energy-balance equation, accounting for various resistances to heat transfer. The resulting differential equations are solved numerically. However, with robust assumptions, an analytical expression can be developed for transient fluid temperature during falloff. The heat flow from the formation into the wellbore raises the internal energy of the fluid and of the composite tubing/casing/ cement material. Please see the complete paper for the quantitative expression. Field Example Modeling Temperature Transient During Falloff Test. The pressure-computation algorithm entails two steps. First, the temperature is evaluated as a function of time at various depths throughout the wellbore. As expected, the temperature at well bottom will exhibit the largest excursion. Second, the fluid properties of density and compressibility are evaluated at each depth step corresponding to the temperature profile, leading to the BHP estimation at a given timestep.

Tactics for Use of Diagnostic Fracture Injection Tests in Unconventional Reservoirs

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 163863, ’Diagnostic-Fracture-Injection-Testing Tactics in Unconventional Reservoirs,’ by D.D. Cramer, SPE, and D.H. Nguyen, SPE, ConocoPhillips, prepared for the 2013 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4-6 February. The paper has not been peer reviewed. To achieve optimal production from unconventional reservoirs, it is useful to determine the permeability, pore pressure, and state of stress of rock strata. An effective way to derive this information is to conduct in-situ pressure-transient tests. Because injecting fluid into or withdrawing fluid from the pore network of tight rock is difficult, diagnostic fracture injection tests (DFITs) have been used to create an analyzable pressure-decline response and to derive the minimum horizontal stress through fracture-closure identification. Introduction Well testing is the technique of establishing fluid flow in the reservoir by either producing from or injecting into a well and then changing or terminating the flow rate to create a transient event, usually by shutting in the well at the surface. The resulting wellbore-pressure response is then evaluated to derive reservoir properties, such as transmissibility and initial reservoir pressure. Creating a hydraulic fracture bypasses wellbore damage and near-wellbore stress concentrations and connects the wellbore to a significant portion of the reservoir-layer thickness, enabling a representative investigation of reservoir properties. A typical DFIT sequence is shown in Fig. 1. Initially, the well is filled with water, with care taken to purge the fluid column of entrained air and gas.

Diagnostic Fracture Injection Tests: Common Mistakes, Misfires, and Misdiagnoses

SummaryOver the last 20 years, diagnostic fracture injection tests (DFITs) have evolved into commonly used techniques that can provide valuable information about the reservoir, as well as hydraulic-fracture-treatment parameters. Thousands of tests are pumped every year in both conventional and unconventional reservoirs. Unfortunately, many tests that are pumped provide poor or no results because of either problematic data acquisition or incorrect analysis of the acquired data.This paper discusses common issues and mistakes made while acquiring DFIT data. Guidelines on how to avoid these errors and secure the best possible data are provided, including data resolution, pump rates, test duration, and fluid selection. Strategies are provided to estimate the time required to reach fracture closure and establish stable reservoir transients for analysis.The last part of the paper addresses potential (and commonly observed) problems in the analysis of the DFIT. These issues can be magnified in tight-gas and shale reservoirs because of the long data-acquisition times and the subtle pressure transients that can occur. Specific issues that are discussed include poor instantaneous-shut-in-pressure data from perforation restriction, loss of hydrostatic head, gas entry and the resulting phase segregation, the use of gelled fluids, and errors in after-closure analysis.

Economic Optimization of Horizontal-Well Completions in Unconventional Reservoirs

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 168612, ’Economic Optimization of Horizontal-Well Completions in Unconventional Reservoirs,’ by R.D. Barree, SPE, Barree & Associates; S.A. Cox, SPE, PetroEdge Energy III; J.L. Miskimins, SPE, and J.V. Gilbert, SPE, Barree & Associates; and M.W. Conway, SPE, Core Laboratories, prepared for the 2014 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4-6 February. The paper has not been peer reviewed. This paper presents methods for production forecasting that give reasonable post-treatment predictions that have been found to be useful for economic planning. The proposed methodology provides an economically viable plan for optimizing lateral length, fracture spacing, and treatment design. The methodology focuses on the post-simulation effective reservoir volume. Results show that increasing apparent fracture length rarely affects long-term recovery. Likewise, adding more fractures within the same reservoir volume may increase early-time production rate and decline rate without contacting more reservoir volume or adding to long-term recovery. Introduction Industrywide, there appear to be several basic assumptions that govern expectations about recovery generated through horizontal-well stimulation in unconventional reservoirs. Depending on the basic belief system applied, dramatically different, even diametrically opposed, recommendations result. The first belief is that core-derived permeability values, usually from crushed samples, represent overall reservoir flow capacity accurately. This assumption frequently controls post-treatment expectations regarding treatment size, spacing of perforation clusters (fracture-initiation points), or number of treatment stages and most significant aspects of completion design. However, core permeabilities do not represent the overall reservoir flow capacities, something that diagnostic fracture injection tests (DFITs) or production analysis does achieve by measuring the integrated-system permeability, including any secondary fracture enhancement, including existing natural fractures and shear and extensional fracture enhancement developed during the stimulation process. The assumption that crushed-core-derived matrix permeability describes the system flow capacity is generally accompanied by the industry’s second belief, that created or seismically imaged fracture length represents the effective flowing length of the hydraulic fractures. The combination of these two beliefs is used by the industry to explain the observed production behavior in many models. In other words, belief in one requires belief in the other. However, field observations and many years of laboratory work strongly support the conclusion that effective fracture length is much smaller than the created or imaged length and that fracture cleanup is driven by the reservoir flow capacity. In very-low-permeability and low-pressure systems, the effective fracture length is limited by cleanup (flowing length) rather than by conductivity.

Common Mistakes Associated With Diagnostic Fracture Injection Tests

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 169539, ’Diagnostic Fracture Injection Tests: Common Mistakes, Misfires, and Misdiagnoses,’ by R.D. Barree, SPE, J.L. Miskimins, SPE, and J.V. Gilbert, SPE, Barree & Associates, prepared for the 2014 SPE Western North American and Rocky Mountain Joint Regional Meeting, Denver, 16-18 April. The paper has not been peer reviewed. During the last 20 years, diagnostic fracture injection tests (DFITs) have evolved into commonly used techniques that can provide valuable information about reservoirs and hydraulic-fracture-treatment parameters. Thousands of tests are run every year in both conventional and unconventional reservoirs. However, many factors associated with data collection and analysis can result in poor or incorrect results. This paper attempts to describe some of the common problems and to help prevent some common errors often observed in DFIT execution and analysis. Introduction DFITs are small pump-in treatments performed to gather data to help design follow-up hydraulic-fracturing treatments and characterize a reservoir. A generic DFIT is shown in Fig. 1. The wellbore is first filled at a low to moderate rate until a positive surface pressure response is observed. With low- to- moderate wellbore compressibility, the pressure should rise quickly until initial breakdown occurs. Breakdown will be indicated either by a sharp drop in pressure as a new fracture initiates (as at Number 1 in Fig. 1) or by a plateau in pressure as existing fractures are opened and extended. Once a breakdown event is observed, the injection rate should be increased to the maximum rate allowed by available horsepower or to 75% of the planned treatment rate of the main fracture treatment, whichever is achievable. A constant rate is then held for 3–5 minutes (Number 2 in Fig. 1), after which a rapid step-down can be conducted. The step-down test is separate from the actual DFIT but is commonly run at the end of the pump-in to determine perforation and near-wellbore frictional pressure losses. The rate is then immediately reduced to zero to obtain the instantaneous shut-in pressure (ISIP), shown as Number 4, and the falloff pressure is monitored for as long as possible or as long as necessary to acquire the desired data. Even when high friction is not expected, the step-down is recommended to make identification of ISIP easier.

Technology Focus: Reservoir Performance and Monitoring (September 2014)

Technology Focus “If you have one watch, you know the time. If you have two, you will never be sure.” This was a quote that my professor in reservoir engineering, T.D. van Golf-Racht, once stated when he tried to make us students reflect upon the availability and the quality of the data given for a specific exercise. This was in the late 1980s, and the amount of data was rather limited compared with today’s vast amount of data available. The cost of new data is increasing; most operators are cutting cost, and the cost/ benefit exercise is getting more and more challenging. Actionable information is even more important, and payback time is the crucial number to know. When you have obtained the necessary funding for acquiring data, make sure that you spend it wisely by collecting the data the right way and understanding the data you have gathered. Paper SPE 169539, related to diagnostic fracture injection tests, highlights the pitfalls when acquiring data to prepare for a hydraulic-fracture treatment. Understanding well and reservoir performance is the ultimate goal of data gathering, and this gives the necessary foundation for making decisions. Regardless of the amount of data available and supercomputers at hand, analytical methods still play an important role in today’s analysis of reservoir performance. Another featured paper describes the use of modern analytical tools in an excellent way. Data are of particular importance when you try to establish fundamental knowledge, whether it is drainage strategy for a new discovery or (even more fundamental) recovery processes for new types of hydrocarbons such as hydrates, described in paper OTC 25328. We, the engineers, need to prepare for tougher times ahead. We need to make sure that key data are collected and be prepared to skip the rest. We need to make sure that more time is spent understanding the data than gathering them. We need to make sure that we perform cost/benefit analysis both before and after data acquisition. JPT

Modelling Wellbore Transient Fluid Temperature and Pressure During Diagnostic Fracture-Injection Testing in Unconventional Reservoirs

Summary Diagnostic fracture-injection testing (DFIT) has gained widespread usage in the evaluation of unconventional reservoirs. DFIT entails injection of water above the formation-parting pressure, followed by a long-duration pressure-falloff test. This test is a pragmatic method of gaining critical reservoir information (e.g., the formation-parting pressure, fracture-closure pressure, and initial- reservoir pressure), leading to fracture-completion design and reservoir-engineering calculations. In typical field operations, pressure is measured at the wellhead, not at the bottom of the hole, because of cost considerations. The bottomhole pressure (BHP) is obtained by simply adding a constant hydrostatic head of the water column to the wellhead pressure (WHP) at each timestep. Questions arise whether this practice is sound because of significant changes in temperature that occur in the wellbore, leading to changes in density and compressibility throughout the fluid column. This paper explores this question and offers an analytical model for estimating the transient temperature at a given depth and timestep for computing the BHP. Furthermore, on the basis of the premise of a line-source well, we have shown that the early-time data can be represented by the square-root of time formulation, leading to the new modified Hall relation for the injection period.

Diagnostic fracture-injection tests with complex fracture networks

Diagnostic fracture-injection tests (DFIT) are small-volume fracturing tests used to estimate the minimum principal stress and other formation properties. Conventional DFIT interpretation techniques assume that injection forms a single, planar fracture perpendicular to the minimum principal stress. However, abundant evidence exists that hydraulic fracturing causes the generation of complex networks, especially in shale. A computational simulation of a DFIT test in a “complex” fracture network that includes both new and preexisting fractures was performed with a discrete fracture-network (DFN) algorithm that fully couples fluid flow with the stresses induced by fracture deformation and propagation. Results show that with fracture network complexity, standard DFIT interpretation methods might give erroneous results. More broadly, results suggest that hydraulic-fracture models and interpretation techniques need to be updated to include the effects of fracture-network complexity. The results are preliminary because of several simplifying assumptions made by the simulator. In future work, those assumptions will be relaxed, the simulator will be used to develop applied interpretation techniques, and the techniques will be applied to field data.

Integrated Well-Test Strategy in Unconventional Tight Gas Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16950, ’Integrated Well-Test Strategy in Unconventional Tight Gas Reservoirs: Learning and Experiences From an Actual Field Project,’ by Minquan Jin, SPE, Shell Exploration & Production; Wenxia Zhang, SPE, Shell China Exploration and Production; and Hongli Zhang, PetroChina Southwest, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission. Tight gas reservoirs and shale gas reservoirs are economically viable hydrocarbon prospects that have proved to be successful in North America. In such reservoirs, established methods of well testing and data analysis are often impractical. This paper presents an integrated well-test program developed for a tight gas reservoir in southwestern China. The program, designed and modified from conventional methods to meet the project-delivery timeline and cost constraints, makes use of a combination of various formation-evaluation techniques. Introduction The northwestern and central areas of the Sichuan basin have been identified as having basin-centered gas potential. In particular, there are several blocky sand intervals in the Late Triassic Xujiahe formation that contain a relatively immature, continuous gas accumulation. The tight-gas-reservoir project described in this paper is located in the central uplift area of this basin and is operated by Shell and PetroChina as a joint venture. In this tight gas block, the Xujiahe formation has a gross thickness of greater than 500 m and is found at 3000- to 4000-m drilling depth. The hydrocarbon system in the block is an overpressured section of tight gas sands that are sourced by imbedded and surrounding shales and coals. Gas and condensate can be produced from this objective section through massive multistage hydraulic-fracturing treatments. As with the exploration and development of any tight gas reservoir, the economic delivery of this project requires the integration of various well-testing methodologies to identify the economic feasibility of the reservoir. Well tests are normally conducted during various stages of the well life (Fig. 1). The objectives of well tests include the following: Identifying the hydrocarbon-bearing horizon Characterizing reservoir parameters Obtaining initial reservoir pressure Characterizing well damage and the extent of the damage Determining well deliverability and drainage area Evaluating well-completion efficiency Evaluating reservoir heterogeneities Estimating recoverable reserves Unlike conventional hydrocarbon prospects, however, the formation permeability in a tight gas reservoir is extremely low, and commercial production generally requires stimulation through extensive hydraulic fracturing. The mature and well-defined methods of well testing and data analysis, although applicable, are often impractical because of excessive test duration. Therefore, the true potential in tight gas reservoirs can be established only when well tests are combined with a well-hydraulic-fracturing program. We present an integrated well-test program developed and implemented for reservoir characterization and formation evaluation of this particular tight gas reservoir. The program makes use of a combination of various formation-evaluation techniques that include diagnostic fracture- injection tests (DFITs), perforation-inflow tests (PITs), pressure-buildup (PBU) tests, rate-transient analysis, and production logging.

DFIT 자료 해석을 통한 저류층의 투과도 및 초기압력 추정

Abstract Well testing in unconventional reservoirs, such as tight or shale gas formations, presents considerable challenges. It is difficult to estimate the reservoir properties in ultra-low permeability formation because of poor inflow prior to stimulation and excessive test duration. Moreover, radial flow may not develop in hydraulically fractured horizontal wells. For these reasons, the cost of test is high and the accuracy is relatively low. Accordingly, industry is turning to an alternate testing method, diagnostic fracture injection test (DFIT), which is conducted prior to the main hydraulic fracture treatments. Nowadays, DFIT are regarded as the most practical way to obtain good estimates of reservoir properties in unconventional reservoirs. Various methods may be used for interpreting DFIT data. This paper gives an explanation of those methods in detail and examines three actual field data. These show how various analysis methods can be applied to consistently interpret fracture closure pressure and time, as well as before and after closure flow regimes and reservoir properties from field data.

A Method To Perform Multiple Diagnostic Fracture Injection Tests Simultaneously in a Single Wellbore

Summary This paper presents a unique process for deriving reservoir properties (i.e., minimum horizontal stress, kh/u, and reservoir pressure) in isolated reservoir layers intersected by the same vertical wellbore. It is based on simultaneously performing multiple diagnostic fracture-injection tests (DFIT) with extended multiday shut-in periods using downhole shut-in tools and bottomhole memory gauges. A case study of 58 vertical wells completed in the Mesaverde and Dakota sandstones of the San Juan basin is used to describe and assess the above application. These intervals are gas productive, slightly to significantly subpressured, and possess a very low permeability pore network enhanced by natural fracture networks. As many as seven individual intervals per well were tested using the simultaneous process in an area spanning the entire San Juan basin. Large-scale, multistage hydraulic fracturing is necessary to establish commercial production from these intervals. The diagnostic tests were done before the large-scale fracture treatments, yet did not impede the subsequent implementation of the treatments. In the Dakota interval, the diagnostic testing results agreed well with the kh derived from post-fracture production analysis and led to a process of treatment design optimization. In the Mesaverde interval, less agreement was found between diagnostic-test and production-analysis results. Despite the lack of validation, fluid leakoff rates measured during the diagnostic testing provided insight into fracture half-length differences documented in a previous study of microseismic mapping. As part of the case study, procedural guidelines and best practices developed in the process of performing over 200 tests will be discussed.

Establishing Key Reservoir Parameters with Diagnostic Fracture Injection Testing

Summary Diagnostic fracture injection testing (DFIT) is an invaluable tool for evaluating reservoir properties in unconventional formations. The test comprises injection of water over a short time, starting a fracture at the end of a well's horizontal section, followed by a long shut-in period. Analysis of the falloff data with the G-function plot reveals the fracture-closure pressure, and the fracture pseudolinear-flow period. In most tests, wellhead-pressure (WHP) measurements are used because of cost considerations. A wellbore-heat-transfer model is used to allow conversion of WHP to bottomhole pressure (BHP) by accounting for changing fluid density and compressibility along the wellbore. This model, in turn, allowed us to assess the quality of solutions generated with the WHP data. For DFIT analysis, we adapted the modified-Hall plot for the injection period, whereas both the pressure-derivative and G-function plots were used for the analysis of falloff data. The derivative signature of the modified-Hall plot allows unambiguous estimation of the fracture breakdown pressure (pf,) during the injection period. As expected, the pf, always turns out to be higher than the fracture-closure pressure (pfc), estimated with the two methods during pressure falloff, thereby instilling confidence in the solutions obtained. A statistical design of experiments with coupled geomechanical/fluid-flow simulation capabilities showed that the formation permeability is by far the most important variable controlling the fracture-closure time. Mechanical rock properties, such as Young's modulus of elasticity and the Poisson's ratio, play minor roles. In microdarcy formations, a longitudinal fracture takes much longer to close than a transverse fracture.

Testing unconventional formations

Testing unconventional reservoirs, particularly hydrocarbon-bearing shale formations, presents considerable challenges. This paper reviews those challenges and their effects on testing. Conventional testing methods, although applicable, are often impractical because of excessive test duration. Diagnostic fracture injection test (DFIT) has become the preferred option for unconventional formations. Several methods may be used for interpreting DFIT data. We examine those methods in detail and explore their relative strengths while interpreting field data.