Multi-stage Fracture Treatments Research Articles

Evaluation of Fluid Distribution and Perforation Erosion in Multistage Fracture Treatment

Summary Fracture monitoring and diagnosis by fiber-optic sensing technology provides invaluable information about stimulation efficiency. This technology becomes more critical for multistage fracturing over long horizontal wells. The combined analysis of distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) measurements has been used to map the fluid distribution during hydraulic fracturing, and fracture volume at the cluster level and at the stage level can be estimated from the analysis. In this paper, based on the interpretation of models for DTS and DAS, we extend the application to fluid containment and stage isolation evaluation. In plug and perforation hydraulic fracturing, when a stage is finished pumping, the stage is isolated by a plug, and the next stage is perforated and then fractured. If the plug is not functioning correctly, fracture fluid enters the previous stage, causing an uneven fluid distribution, and possibly more severe perforation erosion. Both DAS and DTS monitoring can record this phenomenon when it happens. Interpretation models are built to quantify the fluid distribution with the effect of plug leakage included. From DTS measurements, cooling below the stage being completed is counted as the fluid from the current stage. Given this information, the reservoir thermal model can estimate the volume of leakage. From the DAS measurement, we interpret the volume distribution based on frequency band energy to compare with the DTS interpretation. Perforation erosion measurements from a downhole camera are used to confirm the estimation. With this approach, we assess the fluid distribution, plug performance, and the importance of stage isolation on perforation erosion during a multistage fracture treatment. The information can then be used to analyze and optimize completion and fracture treatment design. Field examples are presented in the paper to support the discussion, findings, and conclusions. Based on the results of the fluid distribution estimated, we observed that higher injection rate and larger fluid volumes may create more uniformly distributed fluid between clusters in a stage. When considering communication between stages, the DTS and downhole camera show that there is a correlation between fluid distribution and perforation eroded area. An inconsistency of eroded area and fluid received is observed at toe-side clusters from DTS, DAS, and downhole images. This could be caused by a short erosion time at the toe-side clusters. In the completion design, only a few parameters show a strong impact on fluid distribution and perforation erosion.

Analysis of Ultimate Gas Recovery in Shale Reservoirs

Abstract Horizontal wells with multistage fracture treatments enabled economic gas production from shale gas reservoirs. Recovery from a typical shale reservoir is usually quite low as numerous factors can affect the ultimate recovery. However, recovery factors inside and outside the stimulated reservoir volume (SRV), especially the variations spatially and temporally, are not yet fully understood as the numerical simulation of shale gas production is still challenging. In this study, a dual-porosity, dual-permeability model was built to investigate ultimate gas recovery and its spatial variations throughout the production period. Parametric studies were conducted to evaluate the effect of matrix permeability, fracture conductivity, fracture half length, and operating conditions on recovery factors. Systematic and comprehensive numerical experiments were carried out to generate a probability distribution of ultimate recovery factors. The results presented in this article provide insight into the impact that key parameters have on these recovery factors in and outside the SRV and the range of recovery factors one can expect from shale gas reservoirs. Fracture conductivity has the most impact on recovery in the SRV while matrix permeability can affect the recovery outside the SRV significantly. The expected recovery in the SRV is 24% in shale reservoirs. The methodology in this study provides a foundation to develop more reliable models in accurately forecasting ultimate gas recoveries spatially for shale gas reservoirs. The new understanding can be applied to optimize field development, well spacing, and infill drilling to increase economic recovery.

Multi-stage and multi-well fracturing and induced stress evaluation: An experiment study

Multi-stage and multi-well fracturing of horizontal wells are indispensable techniques in developing shale oil and gas. Increasing the stimulated reservoir volume (SRV) is of vital importance for production. However, further research is still required due to the uncertainty of fracture propagation mechanism and the evolution of induced stress. To date, there are few true triaxial hydraulic fracturing physical simulations of large-natural shale samples. By using 13 cubic shale samples (30 × 30 × 30 cm), we investigated the effect of in-situ stress, treatment parameters, and different patterns of multi-well fracturing (staggered or tip-to-tip) on fracture propagation. The pumping pressure data is collected, and the evolution data of the induced stress is measured by a strain gauge which is glued on the rock surface. The fracture geometry is analyzed based on post-fracturing reconstruction, the fracturing data, and the induced stress evolution data. Finally, the suggestions for improving multi-stage and multi-well fracturing treatment are proposed. The results show that: A low overburden stress makes the bedding plane easier to be opened, and it also stops the main hydraulic fracture propagating to the deep reservoir. A high injection rate generates higher net pressure in fracture, and the hydraulic fracture can propagate and cross the bedding plane easily. While using a low injection rate, the liquid can only leak along the bedding plane near the wellbore, leading to a simple fracture geometry. The more fracturing stages, the more complex the fracture network is, and the induced stress data shows an obvious increase. The addition of temporary plugging agent causes a significant increase in pumping pressure and induced stress curves, and the fracture geometry is more complex. Compared with the experiment that has no temporary plugging agent, the induced stress has an increase of 0.7 MPa. In multi-well fracturing experiments, the type of multi-well fracturing (staggered or tip-to-tip) plays an important role on fracture propagation: The fracture complexity in tip-to-tip pattern is significantly lower than that in fracturing staggered pattern because of the “frac-hit”. The longer time interval between treating two wells, the lower the induced stress and the more regular fracture geometry. Further, the fractures that generated in the first well will be reopened by the fluid from the second well when the “frac-connection” occurs between the two wells, causing the induced stress to rise again. The results may provide a reference for the multi-stage and multi-well fracturing design.

Automatic Optimization of Multi-Well Multi-Stage Fracturing Treatments Combining Geomechanical Simulation, Reservoir Simulation and Intelligent Algorithm

Shale reserves have become an ever-increasing component of the world’s energy map. The optimal design of multi-well multi-stage fracturing (MMF) treatments is essential to the economic development of such resources. However, optimizing MMF treatments is a complex process. It requires geomechanical simulation, reservoir simulation, and automatic optimization. In this work, an integrated workflow is proposed to optimize MMF treatments in an unconventional reservoir, and the net present value (NPV) of reserves was treated as the objective function. The forward model consists of two submodels: a hydraulic fracturing model and a reservoir simulation model. The stochastic simplex approximation gradient (StoSAG) is used with the steepest ascent algorithm to maximize the NPV function. The computational results show that optimizing the fracture design can achieve a 20% higher NPV than that obtained with the field reference case. The drainage area of the optimal design is larger than that of the initial design. The maximum gas production rate increases from 23.75 MMSCF/day to 34.43 MMSCF/day and the maximum oil production rate increases from 497 STB/day to 692 STB/day. Therefore, new optimization paths can accelerate fracture design and help increase well production. This paper innovatively proposes a coupled workflow that can reduce the waste of manpower and improve the optimization results.

The role of natural fracture activation in hydraulic fracturing for deep unconventional geo-energy reservoir stimulation

The presence of sealed or semi-sealed, multiscale natural fracture systems appears to be crucial for the successful stimulation of deep reservoirs. To explore the reaction of such systems to reservoir stimulation, a new numerical simulation approach for hydraulic stimulation has been developed, trying to establish a realistic model of the physics involved. Our new model successfully reproduces dynamic fracture activation, network generation, and overall reservoir permeability enhancement. Its outputs indicate that natural fractures facilitate stimulation far beyond the near-wellbore area, and can significantly improve the hydraulic conductivity of unconventional geo-energy reservoirs. According to our model, the fracture activation patterns are jointly determined by the occurrence of natural fractures and the in situ stress. High-density natural fractures, high-fluid pressure, and low effective stress environments promote the formation of complex fracture networks during stimulation. Multistage or multicluster fracturing treatments with an appropriate spacing also increase the stimulated reservoir area (SRA). The simulation scheme demonstrated in this work offers the possibility to elucidate the complex multiphysical couplings seen in the field through detailed site-specific modeling.

Guest Editorial: Four Real-World Challenges in Hydraulic-Fracture Modeling

The development of theoretical hydraulic-fracturing models started several decades ago, setting a basis for hydraulic-fracture design, optimization, and diagnostics. As a reservoir stimulation technique, the problem of hydraulic fracturing in essence is the prediction of the geometric shape and dimensions (length, width, and height) of the growing fracture as a function of time. This mathematically translates to a set of nonlinear, integro-differential equations with moving boundaries, solved numerically over a number of time-steps (SPE 168600). When it comes to multistage fracture treatments (Fig. 1), where many fractures are being “pumped” simultaneously within each stage, the problem’s complexity increases exponentially. The old adage of four inputs being necessary for optimal fracture design (reservoir permeabilities, in-situ stress distributions, a sound geological model, and a fluid-loss model in naturally fractured rocks) is no longer the case as multiple-fracture (multi-frac) interactions and interference (intra-stage, intra-well, and inter-well) should also be incorporated (SPE 1210-0034-JPT). Classic treatment-design software, although convenient to use, struggle to predict multi-frac growth geometries with sufficient certainty, leading to significant disparities between simulations and field observations. Four real-world challenges associated with multi-frac modeling from horizontal well operations are described below. Although each formation presents its own set of challenges rendering it necessary for operators to learn from experience, the development of computational techniques to facilitate the simulation of these common occurrences will yield more-realistic models. 1. Nonsimultaneous fracture initiation within a stage Fracture-propagation pressures are significantly smaller than fracture-initiation pressures (approximated by the recorded “formation-breakdown” pressures) in the same rock. Hence, earlier fracture initiation from one perforation provides a low-energy pathway for the fracturing fluid, which would “prefer” to enter an existing fracture and propagate it rather than initiating new fractures from nearby perforations. 2. Dominant (or “runaway”) fracture creation Dominant (or runaway) fractures are those whose growth is significantly larger compared to that of the other fractures. Laboratory-scale experiments where more than one fracture was pumped from a single fluid source displayed dominant fracture creation as a consistent observation (Michael). This observation qualitatively agrees with acoustic sensing data from the field-scale operations (Fig. 2). Dominant fractures end up receiving the entire fracturing fluid by the end of a stage (SPE 194334), while the remaining fractures cease propagating. The contribution of these few dominant fractures in the post-stimulation well productivity could be major. 3. Inactive perforation clusters Fracturing fluid can bypass entire perforation clusters, initiating fractures from perforation clusters further downstream along the horizontal lateral (SPE 194334). This occurs both by inactive perforation clusters located between active clusters and by inactive perforation clusters located adjacent (upstream or downstream) of active clusters (Michael). There are many possible causes of a perforation cluster failing to generate fractures, including nonsimultaneous fracture initiation and dominant fracture creation. Limited-entry techniques accomplished by varying perforation numbers and diameters (SPE-530-PA), later proposed for mitigating interference between simultaneously growing fractures from horizontal wells (“stress-shadowing”), can potentially be effective in eliminating inactive perforation clusters if specific patterns are detected.

Fracture management in polytrauma

The management of polytrauma patients is acomplex multidisciplinary and dynamic task. The early and comprehensive assessment of the clinical condition is of great importance with respect to the timing and the individual decision-making on surgical fracture treatment. Stable patients benefit from early definitive fracture treatment, whereas for unstable patients, the concept of multistage fracture treatment with temporary minimally invasive stabilization has gained wide acceptance. These concepts, known as early total care (ETC) and damage control orthopedics (DCO), have been extended in recent decades by dynamic and injury-adapted treatment protocols, such as early appropriate care (EAC) or safe definitive orthopedic surgery (SDS): Therefore, patients in an initially unclear condition (borderline patients) can now also be treated with an individually adapted care concept as soon as possible.

Fracture Hits and Hydraulic-Fracture Geometry Characterization Using Low-Frequency Distributed Acoustic Sensing Strain Data

The propagation process and geometry of hydraulic fractures depend on complex interactions among the induced fractures and the pre-existing rock fabric, the heterogeneous rock properties, and the stress state. Accurate characterization of the resulting complex hydraulic-fracture geometry remains challenging. Fiber-optic-based distributed acoustic sensing (DAS) measurements have been used for monitoring hydraulic fracturing in adjacent treatment wells. DAS requires an optical fiber attached to the wellbore to transmit the laser energy into the reservoir. Each section of the fiber scatters a small portion of the laser energy back to a surface sensing unit, which uses interferometry techniques to determine strain changes along with the fiber. DAS data in offset wells fall in the low-frequency bands, which has been proven to be a powerful attribute for the characterization of the geometry of hydraulic fractures. Numerous recently published field examples demonstrate the potential of low-frequency DAS (LF-DAS) data for the detailed characterization of the hydraulic fracture geometry. Understanding the fracture-induced rock deformation associated with LF-DAS signals would be beneficial for the better interpretation of real-time data. However, interpretation of LF-DAS measurement is challenging due to the complexity of the subsurface conditions, in addition to potential unanticipated completion issues such as perforation failure, stage isolation failure, etc. All current research efforts focus on the qualitative interpretation of field data.In this study, we quantified the hydraulic fracture propagation process and described the fracture geometry by developing a geomechanical forward model and a Green’s function-based inversion model for the LF-DAS data interpretation, substantially enhancing the value of the LF-DAS data in the process. The work has a significant transformative potential, involving a tool package with developed forward and inversion models that can provide crucial insights for the optimization of hydraulic-fracturing treatments and reservoir development. Methodology The tool package can be used directly in the field to interpret LF-DAS data and monitor hydraulic fracture propagation. Raw data from the field measurement can be automatically processed. The geomechanics forward model we developed can quantify and analyze the strain-rate response from the LF-DAS measurements based on the 3D displacement discontinuity method. Fracture hits are detected by calculating three 1D features along the channel (location) axis, i.e., the maximum strain rate, the summation of strain rates, and the summation of strain-rate amplitudes. Channels with fracture hits usually exhibit significant peak values of these three features. We proposed general guide-lines for fracture-hit detection based on the quantitative analysis of strain/strain-rate responses during the multistage fracturing treatment. The details of the forward model can be found in Liu et al. (SPE 202482, 204457, AMRA-2020-1426). Additionally, we developed a novel Green’s function-based inversion model to qualify fracture width and height based on the determined fracture hits. The strain field that is estimated from the integration of the strain rates measured by the LF-DAS data along the offset monitoring well is related to the fracture widths through a geomechanics Green’s function. The resulting linear system of equations is solved by the least-square method. Details can be found in Liu et al. (SPE 204158, 205379, 204225).

Completion Effects on Diagnosing Multistage Facture Treatments with Distributed Temperature Sensing

Summary Distributed temperature sensing (DTS) is a valuable tool to diagnose multistage hydraulic fracture treatments. When a stage interval is shut in, the clusters that take more fluid during pumping warm up more slowly. Therefore, the fluid volume injected into each cluster can be quantitatively interpreted by numerical inversion of the warm-back temperature behavior. This general concept assumes that the different warm-back behavior is controlled by only the injected fluid volume; however, recent observations of DTS data indicate that completion configurations significantly influence the warm-back behavior. This paper investigates the completion effects on the DTS interpretation. In ideal conditions, when a stage is fractured, the upstream stage intervals should show an almost uniform temperature that is close to the injected fluid temperature. This is due to the high fluid velocity of injected fluid in the wellbore, and the upstream intervals have not been perforated (noncommunicating intervals), so the only heat transfer is heat conduction between the wellbore fluid and the surrounding reservoir. But the field DTS data show considerably irregular variations in temperature along the upstream stage intervals. These variations are caused by the completion effects. The nonuniform temperature profile is caused by different heat transfer behavior induced by completion hardware along the production casing string, such as joints, clamps, and blast protectors, and by the sensing cable location in the cement, as well as the cement quality. Because the varying heat transfer behavior impacts the warm-back behavior as well as the temperature profile, the completion effects need to be considered in DTS interpretation. A method of DTS interpretation considering the completion effects to diagnose multistage fracture treatments was developed. Because the heat transfer between a wellbore and a reservoir depends on the overall heat transfer coefficient describing heat conduction through the completion in a forward model, this parameter needs to be tuned all along the wellbore. To calibrate the completion effect, the temperature inversion is conducted using the temperature measured at a stage interval that is upstream of a stage interval currently being treated. Because the interpreted stage interval is not perforated at that time, the thermal behavior at the noncommunicating interval is governed by only the heat conduction through the completion environment. Once the effective values of the overall heat transfer coefficient are estimated along the interpreted stage interval, they can be assumed to be constant physical parameters. Then, the fluid volume distribution is interpreted by using the effective overall heat transfer coefficient profile along each interval. This study provides a field application of the developed interpretation method. The new interpretation method provides more accurate diagnosis of fracture treatments by DTS interpretation.

Diagnosing Multistage Fracture Treatments with Distributed Fiber-Optic Sensors

Summary Distributed acoustic-sensing technology is a diagnostic method that has been implemented in the oil and gas industry for flow monitoring during injection or production. One of the applications is to estimate fluid distribution during hydraulic fracturing treatment. This is an invaluable diagnostic tool for multistage fracture treatments because of the large number of parameters and high uncertainty involved in these fracture treatments. Distributed acoustic sensor (DAS) measurements are based on data extracted from a fiber-optic cable installed in a wellbore. Fiber-optic cable strain is sensitive to temperature and acoustic variations induced by fluid flow with different fluid properties and fracture geometries. These parameters are evaluated from the backscattered laser pulse through the fiber using coherent Rayleigh backscattering for DAS and Raman backscattering for distributed temperature sensing (DTS). The DAS interrogation system acquires strain response to acoustic variations along the measured depth of the wellbore for all periods of time. This study presents a method of interpretation of flow-rate distribution from acoustic signals from DAS measurements. Raw acoustic measurements are transformed into energy-attribute distribution for all necessary depth locations and time frame. It allows calculating energy for each perforation cluster location. This calculation demands proper depth-interval consideration for each perforation cluster. A depth-windowing procedure allowing location of intervals where DAS channel measurements must be integrated for each timestep is applied to all stages. Based on previous experimental and computational fluid-dynamic investigations, the correlation between acoustic signal and flow rate is applied to interpret the measured DAS data to flow distribution. In this paper, the system of equations that connects acoustic energy response with clusters flow-rate distribution during the injection period using these correlations is introduced. The solution of this system allows calculating cumulative volume for each perforation cluster on each timestep and at the end of fracture treatment. As additional verification of flow-rate distribution, the results of DAS interpretation were compared with the interpretation results of DTS. A field example is used to illustrate the interpretation procedure. From this work, it is concluded that, besides qualitative analysis, the DAS interpretation method provides a quantitative estimation of flow distribution. Based on current assumptions, the interpretation results from DAS and DTS are comparable with a satisfactory agreement. The combined DAS and DTS interpretations help in understanding cluster efficiency in multistage fracture treatments.

Simulation of the interactions between multiple hydraulic fractures and natural fracture network based on Discrete Element Method numerical modeling

AbstractObtaining the most Stimulated Reservoir Volume (SRV) by forming a complex fracture network is the prerequisite for shale gas hydraulic fracturing. In this paper, a coupled DFN–DEM model is presented based on a realistic discrete fracture network from fracturing treatment, to simulate the complex interactions between a created hydraulic fracture and a natural fracture system in shale. The sensitivity analysis of numerical simulation was performed to investigate the effects of hydraulic fracture length, multi‐fracture spacing, and internal friction angle on the stimulation reservoir area. The simulation results revealed that regardless of the DFN distribution and the length of hydraulic fracture, shear failure always tracked on the existing natural fracture plane. The amount and depth of the natural fracture shear into formation increased as the hydraulic fracture grew in length. Moreover, the actual dynamic morphology of fracture network was the radial or dendritic. A drastic change of permeability along the distance from injection may stimulate the fracture networks especially near the wellbore. For the multi‐fracture, the opening of the second fracture was able to stabilize the sheared fractures at the tip of the initial fracture. The shear failure area around the second fracture tended to increase with the growth of the length of the second fracture. Fracture network connectivity in the system is better for the optimal fracture spacing, and then fluid penetration during injection will influence the permeability evolution during stimulation. The stimulation reservoir area of the fracture network and the natural fracture friction angle had a quadratic relationship. Finally, the results by the data from field measurement in Sichuan, China verified that the proposed coupled DFN–DEM model had an accuracy up to 91.7%. The research results provide a reference for predicting the development of fracture network far away for multistage fracturing treatment.

Optimizing Fracturing Design and Well Spacing with Complex-Fracture and Reservoir Simulations: A Permian Basin Case Study

Summary Proper lateral and vertical well spacing is critical to efficiently develop unconventional reservoirs. Much research has focused on lateral well spacing, but little on vertical spacing, which is important and challenging for stacked-bench plays such as the Permian Basin. Following the previous single-well study (Xiong et al. 2018), we performed a seven-well case study to optimize completion design and 3D well spacings, by integrating the latest complex-fracture-modeling and reservoir-simulation technologies. Those seven wells are located at the same section but also are vertically placed in four different zones in the Wolfcamp Formation in the southern Midland Basin. With the latest modeling technologies, we first built a 3D geological and geomechanical model, and full wellbore fracture-propagation model for these seven wells, and then calibrated the model with multistage-fracturing pumping history of each well. The resulting model was then converted to an unstructured-grid-based reservoir-simulation model, which was then calibrated with production history. On the basis of the local geomechanical characterization, as well as confidence in the capacity of the models from our previous study, we conducted experiments in fracturing modeling to study the impact of different completion design parameters on fracture propagation, including cluster spacing, fracturing-fluid viscosity, pumping rate, and fluid and proppant intensities. With the statistical distributions of fracture length and height from different completion designs, we then optimized the completion design, and studied lateral and vertical well spacings. The results show the following. The resulting fracture length and height from multistage fracturing treatments are in log-normal distribution, which provides great insights on the probability of well interference/fracture hits and drained/undrained reservoir volumes. Both fracture hits/well interference and drainage volume depend on the well spacings and corresponding well completion designs The hydraulic-fracture length, height, and network complexity mainly depend on in-situ stress, cluster spacing, cluster number per stage, and fluid and proppant intensity. For the Wolfcamp Formation in the southern Midland Basin, tighter cluster spacing with fewer perforation clusters per stage and high fluid and proppant intensity, might create larger fracture surface area, which will increase the initial production rate and the ultimate recovery. Therefore, we can reasonably model complicated fracture propagation and well performance with the latest modeling technologies, and optimize both lateral and vertical well spacings, and the corresponding completion design. The application of those technologies could help operators save significant time and costs on well-completion and -spacing pilot projects and, thus, speed up field-development decisions. In addition, we will demonstrate a novel workflow to perform this job.

The effect of heterogeneity on multiple fracture interaction and on the effect of a non-uniform perforation cluster distribution

Multistage hydraulic fracturing is essential for the exploitation of unconventional petroleum resources and to realize new energy sources, such as enhanced geothermal systems (EGS). Multistage fracturing is normally done by increasing the pressure in a well with multiple perforation clusters, with the aim of forcing significant fractures from all perforations. Various methods have been proposed to optimize multistage fracturing treatments, including creating a non-uniform distribution of clusters along the well. Many of these optimization methods have, however, been tested in numerical models assuming homogeneous reservoirs and symmetric growth from the wellbore. An important question is then how heterogeneity affects the multistage fracturing optimization methods. This paper presents a numerical investigation using the modified discrete element method showing how the effect of a non-uniform cluster distribution is affected by the heterogeneity. It is shown that a non-uniform cluster distribution can, in some cases, promote more even contributions from all clusters, but it is sensitive to the reservoir heterogeneity. This indicates that the heterogeneity and fracture complexity have to be accounted for when investigating multistage optimization designs. The focus of this work is the general fracture behaviour during multistage fracturing in heterogeneous rock, aimed at optimizing fracturing designs for EGS and shale gas operations.

Inversion of Downhole Temperature Measurements in Multistage-Fracturing Stimulation of Horizontal Wells in Unconventional Reservoirs

Summary There are still many challenges involved with the quantitative interpretation of downhole distributed-temperature measurements for diagnosing multistage-fracturing treatments in horizontal wells. These challenges include handling enormous amounts of data measured by the sensors in a continuous time and space domain, a ready-to-use fast and robust forward model to simulate temperature behavior, and an efficient algorithm to invert the parameters that are of interest. Because multistage fracturing involves many uncertain parameters (ranging from reservoir properties to treatment design, to fracture geometries and conductivity), the problem becomes extremely complicated when the measured temperature is inverted to a downhole flow profile. In this study we present an approach for combining forward and inverse models to interpret downhole temperature data. Our goal was to improve computational efficiency. Field data from a gas well in the Marcellus Shale were used to illustrate the feasibility of quantitative interpretation of temperature measurement for fracture diagnosis. The forward model used the fast-marching method (FMM). The forward simulation was an order of magnitude faster than the semianalytical model, which is the essential contribution for successfully applying the method in the field case. The improved inversion procedure increased the efficiency of the interpretation. The inversion procedure began with a sensitivity study to select the inversion parameters among various other parameters, such as fracture half-length and the fracture conductivity, and to determine the impact of their uncertainty on inversion. The inversion model used the initial analysis of the temperature gradient to identify the fracture locations with significant temperature changes for interpretation and eliminated the rest of the fracture locations from interpretation. Thus, we obtained a prior estimation of the selected inversion parameters, which was used as an initial estimate for the inversion process. This prior estimation saved significant computation. The inversion was performed fracture by fracture using either parallel computing or sequential computing on the basis of the sensor locations. We began with a synthetic example containing multiple fractures to illustrate the approach and test the procedure accuracy and computation speed. The primary inversion parameter was flow rate, though we also interpreted either fracture length or fracture conductivity when assuming all the other parameters as additional constraints. With an adequate initial estimate, the inverted parameters matched the reference “true value” properly. The inversion process converged with reasonable iterations for each fracture (2–3 iterations). The operation time highlights the advantages of the inversion approach presented in this paper. The guided initial estimation ensured that the gradient inversion approach converged and avoided local minimization. Finally, a field application for interpreting the DTS measurement for the flow profile of the multistage-fractured horizontal well was performed using this inversion method, and it showed encouraging results. The results of our investigation illustrate the procedure feasibility for using temperature data to diagnose a multistage-fracturing treatment. Our proposed inversion model was fast and reliable and provided a promising tool that can be used to quantitatively interpret downhole temperature data.

A Laboratory Study of Multiple Fracture Initiation from Perforation Clusters by Cyclic Pumping

Hydraulic fracturing using cyclic pumping is a potential method for effective stimulation of unconventional oil and gas reservoirs. In our study, the laboratory-scale hydraulic fracturing experiments using cyclic pumping were conducted using cuboid concrete specimens with multiple perforation clusters. The results showed that by cyclic pumping more fractures were created from perforation clusters when compared to non-cyclic monotonic pumping. This trend was shown to increase when using high-viscosity fracturing fluids. In our cyclic pumping experiments, the maximum pressure in the first pumping cycle reached the breakdown pressure and at each subsequent cycle the maximum pressure increased. The increased maximum pressure likely acted to generate more fractures initiating from the given perforation clusters even under greater fracture height to spacing ratios and more acoustic emission (AE) events were generated by cyclic pumping compared with those by monotonic pumping. Well compliance was examined and showed a negligible change in the system compressibility among cycles. This suggests that the fractures formed by previous injection cycles were isolated from the wellbore at the start of this cycle and at least their near-well portions are closed. There are a few possibilities contributing to the difficulty in reopening the existing hydraulic fractures in subsequent injection cycles. Detailed discussion is provided based on the varying features of injection pressure. This cyclic injection method could deliver an alternative for multi-stage fracturing treatments in field applications.

Geomechanical optimization of hydraulic fracturing in unconventional reservoirs: a semi-analytical approach

Unconventional drilling and completion architecture includes drilling multilateral horizontal wells in the direction of minimum horizontal stress and simultaneous multistage fracturing treatments perpendicular to the wellbore. This drilling and stimulation strategy is utilized in order to raise the connectivity of the reservoir to the wellbore, thereby remedying the low permeability problem, increasing reserve per well, enhancing well productivity, and improving project economics in this type of reservoir. However, in order to have the highest production with the least cost, an optimization technique should be used for the fracturing treatment. According to the fact that aperture, propagation direction, and propagation potential of hydraulic fractures are of paramount importance in optimization of the fracking treatment, in this research paper, these three major factors are studied in detail, the control variables on these three factors are examined, and the effect of each factor is quantified by proposing a complete set of equations. Using the proposed set of equations, one can make a good estimate about the fracture aperture (directly controlling the fracture conductivity), the stress shadow size (directly controlling the fracture path), and the change of stress intensity factor (directly controlling the fracture propagation potential). A geomechanical optimization procedure is then presented for toughness-dominated and viscosity-dominated regimes based on the proposed equations that can be used for estimation of different optimal fracturing patterns. The most efficient fracturing pattern can be determined afterward via considering the cumulative production using a reservoir simulator e.g. ECLIPSE, Schlumberger. This procedure is likely to offer an optimal simultaneous multistage hydraulic fracture treatment without deviation or collapse, with no fracture trapping, with the highest possible propagation potential in the hydrocarbon producing shale layer, and a predicted aperture for proppant type/size decision and conductivity of the fractures.

Comprehensive Modeling of Downhole Temperature in a Horizontal Well With Multiple Fractures

Summary Downhole temperature data obtained by either temperature logging or fiber-optic cables have been used to evaluate stimulation treatments and post-stimulation performance of horizontal wells with multiple fractures. Field cases qualitatively show capabilities of detecting creation of transverse fractures, poor zonal isolation, and inflow locations, although downhole temperature behavior in those wells is not fully understood from the theoretical modeling perspective. In this study, we present comprehensive numerical flow and thermal models for a horizontal well with multiple fractures. The well experiences single-phase water flow during injection and shut-in, and gas/water two-phase flow during production. These models are formulated for reservoir and wellbore domains with consideration of their coupling. The reservoir models are formulated in 3D space using mass conservation of each component and thermal energy conservation with Darcy's law in transient conditions. The wellbore models are also transient, and formulated for 1D space using mass conservation of each component, conservation of combined-phase momentum, and total energy conservation. The wellbore- and sandface-temperature profiles are obtained as solutions of these models. These models enable us to simulate field operations in multistage-fracturing treatment; injection and shut-in occur alternately for each stage from toe to heel with zonal isolation. After the stimulation treatments, these models are used to simulate temperature behavior during production in gas/water two-phase flow. We show an example of a single fracture in which the developed model simulates temperature behavior during injection, shut-in, and production to show capabilities of the developed model. This study shows that injected fluid makes the fluid temperature in the fracture lower than the geothermal temperature even after 1 month of shut-in. This affects the temperature interpretation during production because the initial temperature is different from the geothermal temperature assumed as the initial temperature by most studies published previously. A synthetic case with five fractures demonstrates capabilities of detection of created-fracture locations from the shut-in temperature profile. In addition, we apply the model to a field case of distributed-temperature-sensor (DTS) temperature profiles during warmback after multistage hydraulic fracturing, and 30 days after the start of the production in this well. The good match obtained between this model and the DTS data from this well indicates how this modeling approach can be used to estimate the production from individual perforation clusters. The case studies illustrate qualitative interpretations in situations occurring in fields, such as warm-up behavior with multiple clusters during the shut-in period. This paper provides insights from the theoretical modeling perspective for downhole temperature interpretation qualitatively performed at the current time. It also discusses the validity of the assumptions made in previous studies and precautions relevant to those assumptions.

X-FEM Modeling of Multizone Hydraulic Fracturing Treatments Within Saturated Porous Media

In this paper, a fully coupled hydro-mechanical model is presented for the study of multizone hydraulic fracturing. The momentum balance equation of the bulk together with the mass balance and momentum balance equation of the fluid phase are employed in order to derive the hydro-mechanical coupled system of governing equations of the porous media known as the $$({\mathbf{u}} - p)$$ formulation. The hydro-fracture inflow is modeled based on the Darcy law, where the fracture permeability is determined by using the cubic law. Provisions are made for the plausible closure as well as the frictional resistance of the fracture edges in the solid phase by means of Kuhn–Tucker inequalities embedded in an X-FEM penalty method. In addition, for the fluid phase, the zero leak-off constrain is imposed through the application of the large time increment-based contact algorithm in the case of crack closure. The cohesive crack model is employed to account for the nonlinear fracturing process at the hydro-fracture tips. Multiple crack growth patterns are determined by means of energy based cohesive stress functions. Based on the X-FEM, the strong discontinuities in the displacement field due to fracture opening as well as the weak discontinuities within the pressure field due to leak-off flow are incorporated by using the Heaviside and modified level-set enrichment functions, respectively. A consistent computational algorithm is proposed for the determination of the fracturing fluid flow distribution across the existing perforations. Finally, several numerical examples are presented to demonstrate the robustness of the proposed X-FEM framework in the study of multizone hydraulic fracturing treatments through saturated porous media. The results appear to accord with the field observations reporting numerous failed attempts of multistage multizone fracturing treatments, which provide a great insight into the complexities encountered in practice.

The performance evaluation and design optimisation of multiple fractured horizontal wells in tight reservoirs

Multiple fractured horizontal wells (MFHWs) are recognised as the most efficient stimulation technique to improve recovery from unconventional gas assets. Although multistage fracture treatment has been very successful in stimulating these reservoirs, very little work has been done on multi-stage design optimisation.In most of the published works, the improved MFHWs design is recommended to be determined by sensitivity analysis of one variable while keeping all the other variables fixed. Several researches suggested that this optimisation should be typically performed based on economic objectives such as Net Present Value (NPV).This paper initially describes the results of an exercise that uses statistical algorithms coupled with numerical reservoir simulations to evaluate the simultaneous impacts of important pertinent parameters on the performances of different MFHW designs at various production periods. It is shown that the impact of the individual parameter, quantified by Spearman's rank correlation coefficients technique, on different objective functions e.g. total gas production during the production period, varies depending on the governing flow regimes. For example, it is demonstrated that the impact of fracture length on the performance of MFHWs decreases over the production time while the number of fractures exhibits almost a fixed effect. It was also shown that the general trend of the importance of parameters on productivity index (PI) is similar to those observed for some of other objective functions including total gas production and NPV.In addition, these results confirm the applicability of available well productivity models developed for the early, middle and boundary dominated flow conditions to optimise the design of MFHWs in tight reservoirs. The result of the study confirms provided maximising a desired objective in the long term (longer than the time to reaching the compound linear flow) is targeted; the pseudo-steady state productivity indices models are appropriate to be used for the design optimisation of MFHWs. Otherwise, if a shorter-term objective is targeted, this optimisation could be performed based on appropriate productivity index models available for the early or middle production periods. These results are also confirmed by performing reservoir simulation-based optimisation of the MFHWs design using the genetic algorithm approach for various cases.This work provides a general, fit for purpose set of guidelines, suitable for an improved well design of MFHWs in tight reservoirs. In addition, a new and easily to use workflow based on the productivity index equations is developed to optimise MFHWs design in tight gas reservoirs for a chosen targeted time while considering the practical limits and economics.

Temperature Behavior During Multistage Fracture Treatments in Horizontal Wells

Summary Downhole temperature measured by distributed-temperature sensors (DTSs) shows distinct response to injection and shut-in during multistage fracture treatments in horizontal wells. A thermal model predicting temperature distribution along the wellbore is essential to use the DTS technology to quantitatively diagnose fracture treatments. With inversion, the model can be used to translate downhole-temperature measurement to downhole flow distribution, and therefore to estimate fracture efficiency. In this paper, we present a thermal/flow model that predicts temperature distribution in a system that contains reservoir, wellbore, and fractures during fracture propagation and after well shut-in. We coupled a wellbore-flow model with a simple fracture-propagation model to predict fracture half-length and fluid distribution. For a single-stage fracture treatment, a transient wellbore thermal model is coupled with the fracture and formation thermal models, which are derived from the energy-conservation equations. A sequential simulation method is then applied for multistage fracture treatments by considering the treatment schedule. The full model has three modes: no fracture, fracture propagation, and warm back for shut-in. The full model is used to simulate the stage that is under fracturing. Once the fracture pumping is finished, warm back of the entrained fracture fluid during shut-in periods is simulated by removing the convection term and implementing the corresponding boundary conditions. Numerical solutions are necessary for time-dependent fluid loss and complex nonlinear heat exchange. Mass- and energy-conservation equations are solved by use of the fully implicit finite-difference approach for the conjoint gridding system. The results of the fracture and formation model are verified by analytical solutions for simplified cases. This paper provides synthetic case studies in a low-permeability reservoir by use of the integrated model. The influences of fluid distribution, fluid loss caused by natural and induced fractures, DTS-deployment locations, and reservoir-heat-transfer parameters on temperature behavior are investigated. At the creation and propagation of fractures, injection flow rate (convection) plays an important role on fracture propagation and leakoff front movements. Heat conduction is the dominant mechanism governing temperature response during shut-in. By use of the algorithm for single-stage treatment, a work flow for multistage fracture simulation is created by performing a single-stage stimulation, shutting in the stage, and moving to the next stage along the wellbore. For a shale reservoir, the time frame to reach thermal equilibrium is on the order of weeks, and this gives the possibility to identify the flow-rate distribution from temperature measurements. Sensitivity of fluid distribution, fluid loss, DTS fiber-cable locations for different completion methods, and reservoir parameters is examined, which helps us to understand temperature behavior for fracture diagnosis by use of DTS data during stimulation operations. The methodology developed in this work can be a complementary component to a model that predicts temperature behavior during production to provide better boundary conditions, and it can also be a standalone tool to analyze fracturing-fluid distribution.