Fracture Injection Research Articles

Don’t forget your keys when trying to unlock the productivity of low-permeability coals

Low-permeability coal seam gas (CSG) wells have been the subject of laboratory research and modelling studies over the past decade, particularly focusing on the pressure-dependent permeability (PDP) behaviour of coals. These research efforts have progressed diagnostic methods to identify and quantify PDP and provide practical technologies to counter these effects. Firstly, machine learning methods based on drilling and historical well-test data can provide insight into the range of coal permeability during drilling. Next, the process of history-matching the after-closure pressures from a diagnostic fracture injection test (DFIT), using reservoir simulators, can determine best-fit values for fracture compressibility, a key parameter for reservoir models. Finally, these data, along with DFIT reservoir pressure and permeability data, can inform the decision-making process regarding the most applicable completion strategy and aid developmental planning. For areas where vertical or surface-to-inseam (SIS) wells have been unsuccessful, new hydraulic fracturing technologies have been developed to enhance the stimulated reservoir volume (SRV) in coals, using horizontal wells with multi-stage hydraulic fracturing in excess of 20 stages. Recent laboratory and modelling of micro-proppants has extended prior laboratory and modelling studies and provided insight into proppant transport, embedment, and screen-out behaviour. These well stimulation technologies can be co-applied in new or existing CSG fields and are suitable for areas where overlapping tenements limit conventional, steel-based completion strategies. In conclusion, this paper will bring the key findings of these studies together in a cohesive framework and provide the workflows to implement these technologies for better productivity in low-permeability coals.

Flowback Rates for Pump-In/Flowback Test

Summary The pump-in/flowback test (PIFT), often referred to as the diagnostic fracture injection test (DFIT) with flowback, offers notable advantages in terms of time efficiency and accuracy, particularly in the context of low-permeability formations. The key to the success of this test lies in the careful selection of an optimal flowback rate to yield meaningful results. The fundamental assumption underlying the pressure analysis of these tests is the uniform closure of fractures during the flowback phase, which is considered the default fracture closure mode in current analyses. In this study, we present evidence that challenges the validity of this assumption, highlighting instances where unsuitable flowback rates can lead to nonuniform fracture closure and result in abnormal pressure data. To address this challenge, we identify different closure modes through the signature of fracture closure in the excessive bottomhole pressure decline curve. Subsequently, we propose an optimal range of flowback rates using a scaling analysis approach to obtain a uniform closure mode in an extended openhole section of a vertical well. Our method has been rigorously validated through 3D numerical simulations and field studies, enhancing its reliability and applicability. This approach helps operators to conduct effective tests in complex situations, overcoming a barrier to widespread test application.

Torsion Improvement of Reinforced Self-Compacting Concrete Beams Using Epoxy Injection and CFRP

Few researchers have investigated the internal torsional reinforcement of box timbers, so little research has been conducted on this particular fortification method. The primary objective is to find out the possibility of adding a certain percentage of RCA to the NC mixtures, as well as verifying the success achieved in repairing the cracks that occurred as a result of torsion with CFRP or injecting with epoxy, which has not been addressed in previous research and literature reviews. This study reinforces reinforced SCC box columns subjected to complete torsion with CFRP sheets and epoxy resin injections. Four reinforced SCC specimens (the first beam with 0%, the second beam with 33.3%, the third beam with 67.7%, and the fourth beam with 100% RCA by weight) were subjected to pure torsion until failure. The dimensions and reinforcement of every specimen are identical. In addition, the applied torque-twist angle relationship at the midspan and end span was investigated. Bending experiments were performed to establish load-deflection curves and assess failure modes. After structural rehabilitation, all beams exhibited increased rigidity values, according to the results. Epoxy resin and CFRP sheet contributed to the specimens' increased ultimate load. The ultimate strength of RCA beams strengthened with CFRP and injected with epoxy increased. The specimens' flexural strength was considerably enhanced by the combination of surface roughness and fracture injection, and the effectiveness of using RCA was very good; it could be replaced with NCA in concrete mixtures, according to the ratio and need. Doi: 10.28991/CEJ-2023-09-11-05 Full Text: PDF

Development of fracture diagnostic methods for fluid distribution based on quantitative interpretation of distributed acoustic sensing and distributed temperature sensing

Multistage hydraulic fracturing design on horizontal wells has significantly evolved with larger fluid volume, more fracturing stages, and tighter perforation cluster spacing to efficiently stimulate unconventional reservoirs. From the published field observations, the recent fracturing design results in complex fracture networks or swarm of fractures. Fracture treatment evaluation is extremely challenging in such a case because of the large amount of variables in well completion and stimulation design. Combined measurements from different technologies can help in fracture diagnosis. Fluid distribution, either during fracture injection or during production, directly relates to the stimulation efficiency at the cluster level and at the stage level. Because it is unlikely in the real world to distribute the injected fluid uniformly among all the clusters, we need diagnostic techniques to generate the flow profile along a lateral. Fiber-optic measurements, such as distributed acoustic sensing (DAS) and distributed temperature sensing (DTS), are currently used to diagnose downhole flow conditions. This technology allows us to qualitatively confirm the fluid flow profile and other issues occurring downhole during fracturing such as leakage through plugs. For optimizing a fracturing design, we also need to understand how the design parameters are correlated with the stimulation efficiency. In this study, we combine two sets of models of DAS and DTS data interpretation for injected fluid volume distribution. The DAS is interpreted based on an empirical correlation between fluid flow rates and frequency band energy from the acoustic signals. The DTS is interpreted by performing temperature history match-based thermal energy conservation. Because of the completely different physics behind the interpretations, the confirmation of two interpretations provides confidence in fluid distribution.

The Effects of Intraoperative Local Pain Cocktail Injections on Early Function and Patient Reported Outcomes: A Randomized Controlled Trial.

To determine if a peri-operative pain cocktail injection improves post-operative pain, ambulation distance and long-term outcomes in hip fracture patients. Prospective, single-blinded, randomized controlled trial. Academic Medical Center. Patients with OTA/AO 31A1-3 and 31B1-3 fractures undergoing operative fixation, excluding arthroplasty. Multimodal local injection of bupivacaine (Marcaine), morphine sulfate (Duramorph), ketorolac (Toradol) given at the fracture site at the time of hip fracture surgery (Hip Fracture Injection, HiFI). Patient-reported pain, American Pain Society Patient Outcome Questionnaire (APS-POQ), narcotic usage, length of stay, post-operative ambulation, Short Musculoskeletal Function Assessment (SMFA). 75 patients were in the treatment group and 109 in the control group. Patients in the HiFI group had a significant reduction in pain and narcotic usage compared to the control group on post-operative day (POD) 0 (p<0.01). Based on the APS-POQ, patients in the control group had a significantly harder time falling asleep, staying asleep, and experienced increased drowsiness on POD 1 (p<0.01). Patient ambulation distance was greater on POD 2 (p<0.01) and POD 3 (p<0.05) in the HiFI group. The control group experienced more major complications (p<0.05). At six-weeks post-op, patients in the treatment group reported significantly less pain, better ambulatory function, less insomnia, less depression, and better satisfaction than the control group as measured by the APS-POQ. The SMFA bothersome index was also significantly lower for patients in the HiFI group, p<0.05. Intraoperative HiFI not only improved early pain management and increased ambulation in patients undergoing hip fracture surgery while in the hospital, it was also associated with early improved health related quality of life following discharge. Therapeutic Level I. See Instructions for Authors for a complete description of levels of evidence.

Estimation of the Fracturing Parameters and Reservoir Permeability Using Diagnostic Fracturing Injection Test

The term "tight reservoir" is commonly used to refer to reservoirs with low permeability. Tight oil reservoirs have caused worry owing to its considerable influence upon oil output throughout the petroleum sector. As a result of its low permeability, producing from tight reservoirs presents numerous challenges. Because of their low permeability, producing from tight reservoirs is faced with a variety of difficulties. The research aim is to performing hydraulic fracturing treatment in single vertical well in order to study the possibility of fracking in the Saady reservoir. Iraq's Halfaya oil field's Saady B reservoir is the most important tight reservoir. The diagnostic fracture injection test is determined for HF55using GOHFER software. Models for petrophysics and geology were calibrated using the diagnostic fracture injection test results after the petrophysical and geomechanical parameters of the rock have been determined. The HF55 vertical well, which penetrates the Saady reservoir, has well logs that have been used to evaluate the petrophysical and geomechanical parameters. These estimates have been supported by findings from the diagnostic fracture injection test through the utilization of standard equations and correlations. The findings of the diagnostic fracture injection test, often known as the diagnostic fracture injection test, are very compatible with the findings of the well logs. The diagnostic fracture injection test pre-falloff test event was examined to determine the instantaneous shut-in pressure and fracture gradient. In the meantime, Closure pressure, process zone stress, fracturing fluid efficiency, closure gradient, critical fissure opening pressure, storage correction factor, permeability, and pressure-dependent leak-off coefficient were all determined using the G function on plot. With the help of a specific software, the petrophysical and geomechanical properties of a single vertical well [HF55] was found. Saady B reservoir's upper and lower sections, along with it are therefore predicted to have the full range of petrophysical and geomechanical features. With the use of DFIT analysis, these features serve as the foundation for developing fracturing models.

Study on migration law of multiscale temporary plugging agent in rough fractures of shale oil reservoirs

For unconventional oil and gas reservoirs and deep carbonate reservoirs, temporary plugging fracturing is an important technology to improve oil and gas production. At present, the research of temporary plugging fracturing is mainly focused on the development of high-performance temporary plugging agent, the simulation of fracture growth morphology and the test of plugging ability of temporary plugging agent. There is limited research on the migration law of temporary plugging agents in fractures, which affects the optimization of temporary plugging processes and parameters. Through a crack sealing experimental device, taking into account the influence of rough cracks and crack width, a temporary plugging agent sealing pressure test was conducted. The sealing pressure and the thickness of the dense layer formed by the temporary plugging agent were used to quantitatively characterize the migration law of the temporary plugging agent. This article elucidates the influence of different types, combinations, and concentrations of temporary plugging agents on the sealing pressure. The research results show that the granular temporary plugging agent has better plugging ability than fiber, and it is easier to plug the fractures with small width. Increasing the concentration of temporary plugging agent is beneficial to plugging fractures, and high concentration of temporary plugging agent can achieve higher plugging pressure compared with low concentration of temporary plugging agent. At the same concentration, the plugging pressure of the temporary plugging agent combined with fiber and small particles is lower than that of the temporary plugging agent combined with fiber, small particles and large particles. Increasing the fiber concentration in the composite temporary plugging agent can effectively increase the temporary plugging pressure and shorten the pressure starting time. Compared to smooth fractures, temporary plugging agents are more likely to accumulate and seal in rough fractures. Temporary plugging fracturing technology has been widely used in unconventional fields such as tight gas and shale oil in the Sichuan Basin. The analysis of fracturing injection pressure data shows that fractures will turn several times in the formation after the temporary plugging agent is added to the fracturing fluid, thus increasing the stimulation range.

Hydraulic Fracture Propagation and Proppant Transport Mechanism in Interlayered Reservoir

Hydraulic fracture is crucial for assuring well production from unconventional reservoirs. For the optimization of hydraulic fracture geometry and the ensuing production of an interlayered reservoir, vertical hydraulic fracture propagation path has been analyzed. However, an effective fluid channel cannot be formed if the proppant is unable to reach the area where the fracture propagates. This paper presents a numerical model using the lattice-based method to investigate the hydraulic fracture propagation and proppant transport mechanism in interlayered reservoirs. The hydraulic fracture propagation model was simulated under different geological and fracturing engineering factors. The results indicate that interlayer Young’s modulus and horizontal stress anisotropy are positively correlated with longitudinal propagation and proppant carrying ability in interlayered formations. The fracturing injection rate has an optimal solution for fracture propagation and proppant carrying since a too low injection rate is unfavorable for fracture penetration of the interlayer, while a too high injection rate increases fracture width instead of further fracture penetration. In conclusion, attention is drawn to fine particle size proppants used in multi-layer reservoirs for fracturing fluid to carry proppants as far as possible to obtain maximum propped area.

Stage-by-Stage Hydraulic Fracture and Reservoir Characterization through Integration of Post-Fracture Pressure Decay Analysis and the Flowback Diagnostic Fracture Injection Test Method

Summary The post-fracture pressure decay (PFPD) technique is a low-cost method allowing for stage-by-stage hydraulic fracture characterization. The analysis of the PFPD data is complex, with data affected by both hydraulic fracture and reservoir properties. Available analysis methods in the literature are oversimplified; reservoir or fracture properties are often assumed to be constant along the horizontal well, and therefore changes in the trend of pressure decay data are attributed to hydraulic fracture or reservoir properties only. Moreover, methods analogous to those applied to the analysis of conventional diagnostic fracture injection tests (DFITs) are often used and ignore critical mechanisms involved in main-stage hydraulic fracture stimulation. A conceptual numerical simulation study was first conducted herein to understand the key mechanisms involved in main-stage hydraulic fracturing. An analytical model was then developed to account for the dynamic behavior of the hydraulic fracture, leakoff, proppant distribution, multiple fractures, and propped- and unpropped-closure events. The analytical model is cast in the form of a new straightline analysis (SLA) method that provides stage-by-stage estimates of the ratio of unpropped fracture surface area to total fracture surface area. The SLA method was validated against numerical simulation results. Moreover, to account for the variation of reservoir properties along the horizontal well, the PFPD model is integrated with DFIT-flowback (DFIT-FBA) tests, performed at some points along the lateral, to obtain a reliable stage-by-stage hydraulic fracture and reservoir characterization approach. The practical application of the proposed integrated approach was demonstrated using PFPD and DFIT-FBA data from a horizontal well completed in 22 stages in the Montney Formation. The numerical simulation study demonstrated that the use of proppant and injection into multiple clusters (creating multiple fractures) results in multiple closure events. The closure process may start early after the pump-in period at a pressure significantly higher than the minimum in-situ stress. Using DFIT-based analytical models, which ignore the presence of proppant, causes significant errors in hydraulic fracture and reservoir property estimation. The PFPD field data examined herein exhibited a similar pressure trend to the numerical simulation cases. The ratio of unpropped fracture surface area to total fracture surface area was determined stage by stage using the PFPD SLA method, constrained by DFIT-FBA data. Engineers can use this information to optimize the hydraulic fracture stimulation design in real time, optimize the well spacing, and forecast the production. The cost and time advantages of this diagnostic method make this approach very attractive.

Numerical simulation of fracturing and imbibition in shale oil horizontal wells

The shale oil reservoir is characterized by tight lithology and ultra-low permeability, and its efficient exploitation requires the technology of multi-stage and multi-cluster hydraulic fracturing in horizontal wells and shut-in imbibition. After multi-stage and multi-cluster hydraulic fracturing, a complex fracture network is formed, and a large volume of frac fluid is stored within the fracture network. During shut-in, imbibition and exchange between oil and water occurs under the action of the capillary force and osmotic pressure, and the formation pressure builds up in the shale reservoir. On basis of the characteristics of shale oil reservoir, we establish a model of imbibition during fracturing injection and shut-in by coupling oil–water two-phase flow and saline ion diffusion in the hydraulic fractures (HFs) network, natural fractures (NFs) and matrix system under the action of capillary force and osmotic pressure. The DFN method and the multiple continuum method are introduced to characterize fluid flow between the HF and the NF and that between the NF and the matrix respectively, which avoids the problem of a large amount of computation of seepage within the complex fracture. Then, the discrete fracture network (DFN) model and the multiple continuum model are solved with the finite element method, and it is verified in flow field, saturation field and concentration field that the models are accurate and reliable. We propose the imbibition exchange volume for quantitative evaluation of the imbibition degree and a method of calculating the imbibition exchange volume. Simulation of oil and water flow in the fracturing and shut-in stages is performed based on these models. It is found that imbibition in the shale reservoir is driven by mechanisms of pressure difference, capillary force and osmotic pressure. The osmotic pressure and capillary force only cause an increase in the imbibition rate and a reduction in the imbibition equilibrium time and do not lead to variation in the peak of imbibition exchange volume. The imbibition equilibrium time under the action of the capillary force and osmotic pressure is reduced from 150 to 45 d compared with that under the action of the pressure difference. If imbibition equilibrium is reached, low initial water saturation, strong rock compressibility, high formation water salinity and high matrix permeability enhance imbibition and exchange of oil and water in the reservoir. The leakoff volume of frac fluid is generally larger than the imbibition exchanged volume. Leakoff equilibrium occurs slightly earlier than imbibition equilibrium. The imbibition equilibrium time is mainly affected by reservoir permeability and NF density. The number of interconnected fractures mainly affects the frac fluid volume within the hydraulic fracture in the fracturing process. The stimulated reservoir volume (SRV) mainly affects frac fluid imbibition exchange in the shut-in process.

Uniquely determine fracture dimension and formation permeability from diagnostic fracture injection test

Estimating formation permeability is crucial for production estimation, hydraulic fracturing design optimization and rate transient analysis. Laboratory experiments can be used to measure the permeability of rock samples, but the results may not be representative at a field scale because of reservoir heterogeneity and pre-existing natural fracture systems. Diagnostic Fracture Injection Tests (DFIT) have now become standard practice to estimate formation pore pressure and formation permeability. However, in low permeability reservoirs, after-closure radial flow is often absent, which can cast significant uncertainties in interpreting DFIT data. Without knowing the fracture dimension prior, open fracture stiffness/compliance can't be determined, which is required for formation permeability estimation. Previous work has to assume a fracture radius or fracture height in order to estimate formation permeability, thus dent the confidence in the interpretation results. In the study, we present a new approach to determine fracture dimension, leak-off coefficient and formation permeability uniquely based on material balance and basic fracture mechanics, using data from shut-in to after-closure linear flow. Field examples are also presented to demonstrate the simplicity and effectiveness of this new approach.

Discrete Measurements of the Least Horizontal Principal Stress from Core Data: An Application of Viscoelastic Stress Relaxation

Summary The emerging Paradox Oil Play in southeastern Utah is among the most significant unconventional plays in the western USA. The mean total undiscovered oil resources within just the Pennsylvanian Cane Creek interval of the Paradox Basin are believed to exceed 215 million barrels. However, to date, less than 5% (~9 million barrels) of the total Cane Creek resource has been produced from fewer than 40 wells, and only approximately one-half of those are horizontal wells. More than 95% of production is from the central Cane Creek Unit (CCU). Natural fractures are a key feature of many production wells, but stimulation by induced hydraulic fractures is not consistently successful. We hypothesize that more effective production in this play will rely on better fundamental characterization, especially on better quantification of the state of stress. Approximately 110 ft of core, well logs, and a diagnostic fracture injection test (DFIT) were acquired from the State 16-2 well within the CCU. With these data, we applied two methods to constrain and clarify the state of stress. The first technique, the Simpson’s coefficient method, provides lower bounds on the two horizontal principal stresses and relies on only limited data. Alternatively, the viscoelastic stress relaxation (VSR) method is used to estimate the least horizontal principal stress, building on observations that principal stresses become more isotropic as the viscous behavior of a rock is more pronounced. Results of these two methods support the hypothesis that the state of stress in the CCU of the Paradox Basin is nearly lithostatic and isotropic. Other factors consistent with this hypothesis include high formation pore pressure, which tends to reduce the possible stress states by changing the frictional failure equilibrium; lack of induced fractures in the core, which should be present in the case of stress anisotropy; and interbedded halite layers, which given their high degree of ductility, probably lead to greater VSR for the entire sedimentary package.

Validation of Estimating Stress from Fracture Injection Tests Using Continuous Wavelet Transform with Experimental Data

The article discusses the new technique for fracture closure pressure detection using continuous wavelet transform (CWT). The study focuses on calibrating the CWT technique and comparing it with different techniques for closure detection. According to the article, traditional methods for identifying the closure of hydraulic fracturing operations are based on assumptions that can conflict with one another, resulting in greatly varying approximations of closure pressure and duration. To address this issue, the article employs a set of diagnostic fracture injection tests that utilize the Step-Rate Injection Method for Fracture In-Situ Properties tool (SIMFIP). By directly observing wellbore deformation, the SIMFIP tool determines the minimum principal stress, while strain gauges monitor the opening and closing of fractures during multiple tests. The publicly accessible data are used to evaluate the accuracy of the new closure detection technique using CWT. The findings indicate that the CWT method aligns with measurements of deformation and can identify the impact of intricate closure events and pre-existing natural fractures. In conclusion, the article suggests that the CWT technique shows great potential as an alternative to traditional approaches for detecting closure pressure.

New Pump-In Flowback Model Verification with In-Situ Strain Measurements and Numerical Simulation

This study presents an analytical model for estimating minimum horizontal stress in hydraulic fracturing stimulations. The conventional Diagnostic Fracture Injection Test (DFIT) is not practical in ultra-tight formations, leading to the need for pump-in/flowback tests. However, ambiguities in the results of these tests have limited their application. The proposed model is based on the linear diffusivity equation and material balance, which is analytically solved and verified using a commercially available numerical simulator. The model generates a linear graph in which the pressure drop and its derivative are plotted versus the developed solution time function. The closure pressure is determined when the slope of the derivative deviates from linearity. The model was applied to several cycles of field flowback tests and found to eliminate the ambiguity associated with identifying the fracture closure. Furthermore, the minimum In-situ stresses estimated using this approach are verified via downhole strain measurement and synthetic data from a fully 3D commercial fracturing simulator. The proposed technique outperformed other conventional methods in analyzing challenging injection/shut-in tests, showing improved results and reducing uncertainty in estimated fracture parameters. This model is expected to scale down the need for multiple field trials and provide a reliable estimation of minimum stress.

Injection-Induced Aseismic Slip in Tight Fractured Rocks

We investigate the problem of fluid injection at constant pressure in a 2D Discrete Fracture Network (DFN) with randomly oriented and uniformly distributed frictionally-stable fractures. We show that this problem shares similarities with the simpler scenario of injection in a single planar shear fracture, investigated by Bhattacharya and Viesca (2019); Viesca (2021) and whose results are here extended to include closed form solutions for aseismic moment as function of injected volume V_mathrm{{inj}}. Notably, we demonstrate that the hydro-mechanical response of the fractured rock mass is at first order governed by a single dimensionless parameter mathcal {T} associated with favourably oriented fractures: low values of mathcal {T} (critically stressed conditions) lead to fast migration of aseismic slip from injection point due to elastic stress transfer on critically stressed fractures. In this case, therefore, there is no effect of the DFN percolation number on the spatio-temporal evolution of aseismic slip. On the other hand, in marginally pressurized conditions (mathcal {T} gtrsim 1), the slipping patch lags behind the pressurized region and hence the percolation number affects to a first order the response of the medium. Furthermore, we show that the aseismic moment scales propto V_mathrm{{inj}}^2 in both limiting conditions, similarly to the case of a single planar fracture subjected to the same injection condition. The factor of proportionality, however, depends on the DFN characteristics in marginally pressurized conditions, while it appears to be only mildly dependent on the DFN properties in critically stressed conditions.

Precision in Defining Diagnostic Plots Optimizes Well-Test Results

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206108, “Diagnostic Plots of Pressure-Transient, Rate-Transient, and Diagnostic Fracture Injection/Falloff Tests,” by David Craig, SPE, Occidental, and Thomas Blasingame, SPE, Texas A&amp;M University. The paper has not been peer reviewed. _ All transient-test interpretation methods use diagnostic plots for the identification of wellbore or fracture storage distortion, flow regimes, and other parameters. The associated diagnostic plots are not interchangeable between such tests. The objective of this work is to clearly define the appropriate diagnostic plots for each type of transient test. Introduction In the complete paper, the authors review constant-rate drawdown solutions for a few specific cases of interest and the plotting function used to match buildup data to the drawdown solutions. They extend their review to the cases of buildup or falloff analysis following short flow periods and illustrate the differences between analysis of buildup or falloffs following short and long flow periods. After covering pressure-transient testing, they discuss rate-transient diagnostic plots and the ambiguity observed during analysis of multifractured horizontal well diagnostic plots and the uncertainty of analyst straight lines. Finally, they discuss and demonstrate the correct plotting functions and flow-regime interpretation for diagnostic fracture injection and falloff tests. Multiple examples from the literature are included as part of the discussion. Pressure-Transient Diagnostic Plots Pressure-transient-testing diagnostic plots evolved from the solutions to constant-rate drawdown problems. The authors’ intent is to review infinite-acting solutions for radial flow with wellbore storage and skin and flow through an infinite-conductivity fracture. On a log-log plot, the characteristic slopes, detailed in the complete paper, are unit slope, ½ slope, and zero slope. Many authors have proposed plotting functions for overlaying the observed pressure response from transient tests other than a constant-rate drawdown on the drawdown solutions. In many cases, the slopes identifying storage distortion and flow regimes from drawdown solutions will match and can be used to identify storage and flow regimes from pressure-buildup tests. A situation in which pressure-buildup or falloff test plotting functions fail to match the drawdown solution is when the flow period before shut-in is short. Short-flow transient tests have been reviewed by multiple authors. In lower-permeability reservoirs, pressure-transient tests with short flow periods are very common, and, in unconventional reservoirs, short-flow transient tests are the most-common transient test. Diagnostic plots constructed based on the characteristic shapes of the dimensionless pressure and the dimensionless pressure derivative with respect to the natural logarithm of dimensionless time for constant-rate drawdown solutions cannot be applied in the same manner for short-flow transient tests. With short-flow transient tests, the observed derivative of pressure difference with respect to the natural logarithm of time matches the negative product of dimensionless time and the second derivative of dimensionless pressure with respect to dimensionless time. Additionally, the commonly known impulse derivative, which is defined as the product of time and the derivative of pressure difference with respect to the natural logarithm of time, will match the negative product of dimensionless time squared and the second derivative of dimensionless pressure with respect to dimensionless time.

Fault Identification for the Purposes of Evaluating the Risk of Induced Seismicity: A Novel Application of the Flowback DFIT

Summary The existence of faults, pre-existing hydraulic fractures, and depleted areas can negatively impact the development of unconventional reservoirs using multifractured horizontal wells (MFHWs). For example, the triggering of fault slippage through hydraulic fracturing can create the environmental hazard known as induced seismicity (earthquakes caused by hydraulic fracturing). A premium has therefore been placed on the development of technologies that can be used to identify the locations of fault systems (particularly if they are subseismic) as well as pre-existing hydraulic fractures and depleted areas. The objective of this study is to develop a diagnostic tool to identify these conditions using DFIT-FBA, a modified diagnostic fracture injection test (DFIT) with flowback analysis (FBA). The time and cost efficiencies of the DFIT-FBA method in reservoir characterization provides an opportunity to conduct multiple field tests at a single point or along the lateral section of a horizontal well. An analytical model that considers critical processes and mechanisms occurring during DFIT-FBA was first developed herein. The results of analytical modeling demonstrate that reservoir heterogeneities (i.e., faults) can be identified either by implementing multiple cycles of the DFIT-FBA method at a single point or by applying multiple DFIT-FBAs at different points along the lateral section of a horizontal well or at different wells. The analytical model is then verified using a fully coupled hydraulic fracture, reservoir, and wellbore simulator, and flowing pressure responses in the presence of a fault are illustrated. The practical application of the proposed method is demonstrated using DFIT-FBA field examples performed in a tight reservoir. Analysis of the field examples leads to the conclusion that a fault likely occurs near the toe of the horizontal lateral. This finding was confirmed by other field information and provides the opportunity to modify the main-stage hydraulic fracturing design to avoid induced seismicity events.

Anisortopic Modeling of Hydraulic Fractures Height Growth in the Anadarko Basin

Correct estimation of hydraulic fracture height growth is a critical step in the design of Hydraulic Fracturing (HF) treatment, as it maximizes the reservoir stimulation and returns on investment. The height of the fractures is governed by several in situ conditions, especially stress variation with depth. The common workflow to estimate stress is by building the mechanical earth model (MEM) and calibrating it using the Diagnostic Fracture Injection Test (DFIT). However, DFIT interpretation is a complex task, and depending on the method used, different results may be obtained that will consequently affect the predicted hydraulic fracture height. This work used the tangent and compliance methods for DFIT interpretation, along with isotropic and anisotropic stress profiles, to estimate the HF height growth using numerical modeling in a 3D planar HF simulator. Data from two wells in the Anadarko Basin were used in this study. The predicted height was compared with microseismic data. The results showed that even though the tangent method fits better to the isotropic stress profile, HF did not match with the microseismic data. On the contrary, the anisotropic stress profile showed a good match between the compliance DFIT model and the microseismic events. Based on the discussions presented in this study, the validity of the DFIT interpretation is debatable, and when the formations are anisotropic, the isotropic model fails to correctly estimate the minimum stress profile, which is the main input for the estimation of the fracture height. This is in addition to the fact that some researchers have questioned the use of the tangent method in low-permeability formations.

A New Technique for Estimating Stress from Fracture Injection Tests Using Continuous Wavelet Transform

The diagnostic fracture injection test (DFIT) is widely used to obtain the fracture closure pressure, reservoir permeability, and reservoir pressure. Conventional methods for analyzing DFIT are based on the assumption that a vertical well is drilled in ultra-low permeability reservoirs with potential multiple closures but fails to consider horizontal wells. There is still significant debate about the rigorousness and validity of these techniques due to the complexity of the hydraulic fracture opening and closure process and assumptions of conventional fracture detection methods. The paper introduces a new method for detecting fracture closure pressure using the continuous wavelet transform (CWT). The new method aims to decompose the pressure fall-off signal into multiple levels with different frequencies using the CWT. This “short wavy” function is stretched or compressed and placed at many positions along the signal to be analyzed. The wavelet then convoluted the signal yielding a wavelet coefficient value. The signal energy is observed during the fracture closure process (pressure fall-off) and the fracture closure event is identified when the signal energy stabilizes to a minimum level. A predefined simple commercial fracture simulation case with known fracture closure, flow regime modeling, and actual field cases was used to validate the new methodology.

Diagnostic Fracture Injection Tests Analysis and Numerical Simulation in Montney Shale Formation

Unconventional oil and gas formations are abundant, have become an increasingly important part of the global energy supply, and are attracting increasing attention from the industry. Predicting key reservoir properties plays a significant role in both geological science and subsurface engineering workflows. With the advent of horizontal well drilling and multiple-stage hydraulic fracturing, the Montney Shale formation is one of the most promising and productive shale plays in Canada. However, very few academic papers discuss its in situ stress, reservoir pressure, and permeability, which are essential for the development of the Montney Shale. The objective of this study is to analyze the geo-stress, the pore pressure, and several key reservoir properties by using diagnostic fracture injection test (DFIT) data from the Montney Shale. One horizontal well from the Wapiti field has been analyzed with a set of DFIT data, and its results show that the general pressure and Gdp/dG responses from Well-A indicate a signature of height recession/transverse storage. In the study, the Tangent Line method, the Compliance method, and the Variable Compliance method have been applied to estimate the key reservoir properties. As a result, the Well-A DFIT analysis estimates that the closure pressure is ranging from 34.367 to 39.344 MPa, contributing to the stress gradient from 14.09 to 16.13 KPa/m for the formation. The pore pressure is ranging from 20.82 to 24.58 MPa, contributing to the pore pressure gradient from 8.54 to 10.07 KPa/m for the formation. The porosity is ranging from 3% to 6%. These reservoir properties are contoured cross the Montney Shale formation. Using the DFIT’s numerical simulation and history matching, the reservoir permeability is 0.024 md, fracture length is 13.44 m, and fracture geometries are analyzed by different models. Moreover, the physics behind the DFIT are analyzed and discussed in detail. For the first time, three different analysis methods have been applied to estimate a series of key reservoir properties for the case wells in the Montney Shale formation. This approach can not only reduce the potential prediction error caused by a single method application but also increase the persuasiveness of the assessment and save time, ensuring the efficient implementation of engineering operations. Given the significance of quantifying in situ stress and reservoir pore pressure in unconventional hydrocarbon exploration and development, this study could help the operator to quickly understand the stress regimes, the fracture geometry, and the formation properties of the Montney Shale formation in the Wapiti field. Furthermore, the interpreted results demonstrated in this paper are adding substantial business value to the asset, especially in terms of improving the hydraulic fracturing design and, thus, accelerating the cashflow from production.