The purpose of this paper is to create a starting point for research into using friendly and biodegradable waste material as supportive items for hydraulic fracturing fluids and additives. Conventional fluids and additives, although they can be effective, they pose serious threats to work personnel and public health and to the environment. Conventional fluids and additives can also be very costly. These risks and concerns should drive the oil and gas industry to pursue alternative options, safer and cheaper options, from conventional fracturing fluids and additives. Some waste materials provide this opportunity. It is apparent through many forms of research that waste materials are readily available globally making it easy and cheap to obtain. A driving force for this research was research previously done on finding alternative additives for drilling fluids. Researchers have proven that some of the waste materials, such as food waste, grass waste, palm tree waste, among many others, can and should replace or at least boost conventional drilling fluids and additives through a series of experiments and tests. Not only are these materials easier and cheaper to obtain, but they are also efficient and safer for both the environment and people. The same could be said for alternative hydraulic fracturing fluids and additives if proper research is done. The strides made in finding alternatives for drilling fluid additives have pushed the revolutionizing of the oil and gas industry, acting as a catalyst for the research into alternative hydraulic fracturing fluids and additives. In this work, a more thorough investigation into conventional fracturing fluids and their downfalls regarding price and health and environmental concerns are illustrated as well as the function of the main fracturing fluids; water fracs, linear gels, crosslinked gels, oil-based fluids, and foam/poly-emulsions. Throughout this paper, it becomes apparent that the oil and gas industry should attempt replacing or decreasing conventional fracturing fluids additives because of the negative influences they have on profit, people's health and safety, and the environment.

Unconventional reservoirs suffer from an ultra-low permeability, causing their drainage area to be limited to tens of feet. An efficient technique that can be used in combination with conventional hydraulic fracturing to increase the drainage area is pulse power plasma. In this study, we used an experimental approach to study the effect of pulsed power plasma discharge on the permeability change around wellbore under tri-axial confining stress conditions. We designed and used equipment, allowing for the generation of the shock wave in a true tri-axial cell to perform the analysis in this study. The equipment has a capacity for rock samples of 14 in on each edge with 1.5 in diameter well in the center. Using the equipment, the stored electrical energy in capacitors is instantaneously released into a fusible link creating a thermite reaction, which creates a shock wave in the wellbore and is transmitted to the rock afterward. The shock wave affects the permeability of samples, even in situations where the generated stress loading is below rock strength. Several types of material, such as limestone, sandstone, and concrete are tested in this study. Samples were investigated before and after the electrohydraulic discharge to find the extent and magnitude of the induced fractures (permeability enhancement) and their relationship with the released energy. Also, the effect of repetitive low-magnitude shock waves for creating micro-cracks in rock is studied. It is observed that even under sub-critical loading conditions, micro-cracks are generated in the rock samples that might be a result of the main shockwave or reflection of the stress wave from the boundary. These fractures were less controlled by the stress orientation as compared with hydraulic fractures. However, they contributed to the permeability enhancement around the wellbore that can be up to orders in magnitude. Finally, the optimum discharge energy for the maximum permeability enhancement is suggested. In this study, for the first time, we tested the rock under confining stresses and imaged them using computer tomography (CT) scanning. Also, change of permeability around the wellbore using pulse power plasma is a novel use of pulse fracturing technology that can effectively be mixed with hydraulic fracturing treatment in unconventional reservoirs and maximize the stimulated reservoir volume (SRV). The results of this paper can help to maximize the EUR from the reservoir.

A method of nonintrusive hydraulic fracturing monitoring based on high frequency pressure measurements has been known since 1985. Since that time, multiple attempts of its implementation into a commercial product have been tried. A new method using a wellhead pressure sensor during well stimulation was developed in 2017. The method discussed here is a continuation and improvement of this method. It is based on an advanced signal processing algorithm used for detection and analysis of tube waves in a wellbore and on the data science approaches for further processing of tube wave parameters and providing the answers of fluid entry point depth, plug failure probability, and casing leak detection. Use of the wellhead pressure sensor with a data acquisition box eliminates the need for sophisticated hardware. This enables cost-effective and timely decisions at the wellsite. The technique was validated in the field in several fracturing and refracturing jobs.

In this paper, we introduce a novel fracture imaging method which uses high resolution 3D laser scanning to develop detailed surface maps of the core fracture faces. The digital maps are then used to analyze fracture surface characteristics wherein observed variations provide us with meaningful insights into the fractures. We share a mathematical approach for roughness evaluation to identify morphological properties for individual fractures within rock samples. The approach is tested on core extracted at the Hydraulic Fracturing Test Site (HFTS - 1) in the Permian Basin. We characterize the roughness variations with depth across the cored section. In addition, we compare results obtained previously from core sampling and analysis to demonstrate that proppant entrapment observed within the cored interval is strongly correlated with the changes in fracture morphology. We also use calculated roughness along with the the changing behavior of roughness radially away from the center of fracture faces to predict roughness "types" such as propagational features or textural roughness characteristics. Based on the specific fracture characterization work shared here as well as other potential uses, our paper highlights significant advantages such scanning and digital imaging of fractures may have over traditional cataloging using photographic imaging. Furthermore, as demonstrated in this study, data sampled from these detailed maps can be used to further characterize and analyze these features in a more systematic and robust manner when compared with the more traditional geological analysis of cores.

We propose a new model and workflow to predict, quantify and mitigate undesired flowback of proppant from created hydraulic fractures. We demonstrate several field cases in which we predict significant proppant flowback and propose options for mitigation. Mitigation of proppant flowback is based on case- specific changes in the fracturing treatment design and modifications in the well startup schedule that preserve near-wellbore conductivity. The presented workflow integrates four key components of proppant flowback study: (A) simulation of the fracturing job with a high-resolution model of proppant placement inside a fracture; (B) subsequent simulation of flowback from the created fractures equipped by a validated proppant flowback model; (C) a series of laboratory experiments, which quantify the proppant flowback for a wide range of commercial proppants; and (D) an accurate mathematical model, which is validated by the results of laboratory experiments and integrated into a flowback simulator to predict the behavior of injected proppant. Each component is presented with sufficient details to demonstrate its necessity for accurate modeling of a coupled solid-and-fluid flow inside a fracture. The presented theory of proppant pack mobilization is based on the concept of a proppant pack erosion process evolving from free boundaries of proppant packs. The theory confirms that proppant flowback critically depends on flow rate, proppant, fracture, and reservoir parameters. Laboratory experiments on proppant flowback in a cell support these theoretical predictions. The theoretical model of proppant flowback is integrated into the numerical simulator of early-time production from a fractured reservoir and predicts flowback of both injected solids and fluids from a fracture. We show that the combination of the proppant flowback model, laboratory experiments, hydraulic fracturing design tool, and early-time production simulator result in a useful workflow for prediction and mitigation of issues with proppant flowback and production decline. The entire workflow was validated using field cases where proppant flowback was observed. Modeled amounts of flowed back proppant are in good agreement with amounts of proppant observed in the field. Hydraulic fracturing design optimization was performed to minimize or eliminate proppant flowback. The novelty of the proposed study is related to the model of proppant flowback, which accounts for erosion of the proppant pack and is calibrated against unique laboratory experiments. The presented model and proppant flowback mitigation workflow can assist in understanding and mitigating proppant flowback events that can occur during wide range of oilfield operations.

Several field trials since 2016 have showcased the early development of a novel borehole to surface geophysical technique to characterize propped fractures in the far field of the well bore. Recent advancements have been made with the technique with regards to the processing and inversion algorithms, that have improved the confidence level and extent of the proppant imaged. These advancements will be presented in detail, along with field examples of its application. The imaging technique is broadly classified into three phases: (a) survey design, (b) data acquisition and processing, and (c) inversion to provide propped fracture dimensions and location. The survey design phase includes acquisition of geophysical noise data and synthetic data generation using a realistic simulation of the target and its ambience. This helps determine source receiver locations to maximize response from the propped fracture. Acquired data is digitally processed to remove potential sources of noise arising out of cultural debris, acquisition anomolies, etc. Geophysical inversion of processed data utilizing known geological, engineering, and other constraints then provides the propped fracture image. The novel electromagnetic method for determining propped fracture location and geometry has been developed and deployed safely and successfully in multiple field trials. The recent advancements in modelling and processing have been successfully used to analyze recent field applications, providing key insights on depletion effects of parent wells on bi-wing fracture growth in child wells, as well as proppant settling and stress shadowing impacts. Additional learnings on proppant/fracture fluid interactions, well landing location, and other important issues have demonstrated the potential to impact the planning of future wells in this area. This paper will present the current full-physics methods for processing, modelling and imaging the proppant location. It will include confidence levels and probability functions of the mapped proppant. The paper will also show field examples of the various insights gained from the results (mentioned above), which can be used for future development objectives. The latest advancements in modeling, processing and inversion will be of interest to those who are knowledgeable with forward modeling and inversion theory. In addition, the field results will be useful to development engineers who are interested in optimizing well/lateral spacing, both areally and vertically, as well as understanding the impact of parent-child depletion, stress shadowing and cluster efficiency.

Providing and sustaining fracture conductivity in secondary fracture systems created during the stimulation of very tight unconventional shale plays is critical for sustaining productivity and reducing decline rates. In this paper, a discrete fracture network model which includes proppant transport will be utilized to show the effect that an unsupported vs supported dilated fracture network has on the decline and ultimate recovery of available resources in shale. In addition, the characteristics and properties of a microproppant will be described. The physical properties of the material, the oil and water conductivity of the proppant at various fracture widths along with the resultant Fcd will be presented. Utilizing a bridging factor of 3, a comparison of the surface area propped by various proppants will be made. The proppant transport characteristics will also be described. The production benefits of utilizing very small proppants will be demonstrated utilizing production data from four different rock systems including the Barnett, Woodford, Utica, Permian Basin and Marcellus shale. Several additional operational benefits including reduced pumping pressures and far field diversion to prevent fracture hits will also be discussed. Finally, operational considerations will be described including utilizing liquid slurry's, pump wear evaluations and recommended proppant addition points will be described.

Frac-Driven Interactions (FDI)s are the most pressing topic of discussion within the fracturing community at the present time. The findings of this paper are based on review of BH pressure and temperature data collected in multiple wells during active fracturing operations. Detailed examination of the data revealed similarities between inter- and intra-well interactions, including presence of fracture shadowing as well as temporary and long term frac/frac connections. The cause of most frac/frac connections was poor cement quality that resulted in migration of some of the injected fluid into the passive well segment. In many such cases the volume of migrated fluid was small with minor effect on fracturing results. In some others the migrated fluid rate was high enough to cause reactivation of one or more passive fractures. The surprising results included fluid migration from the active fracture into the passive well segment that started and stopped abruptly while active fracturing was still in progress. This unusual behavior, called reverse screen-out and reported for the first time in fracturing literature, appears to be caused by near wellbore blockage of sand which was being carried by the migrating fluid towards the passive well segment. These events were associated with build-up of sand plugs inside the passive well segment caused by sand flowback during the shut-in period. The paper shows how even a very small volume of sand can cause formation of a sand plug. Frequency of reverse screen-out was about 20% of the nearly 300 frac stages in the three wells reviewed for this paper. Paper also shows how analysis of intra-well FDIs can be used as a diagnostic tool for determination of the effectiveness of the individual stages of the created fractures. This feature allows faster evaluation of the effectiveness of new materials and techniques by comparing the differences in adjacent fracture stages performed with and without the changes.

High viscosity friction reducer (HVFR) fracturing fluids are widely implemented for unconventional reservoir development. HVFR's are easy to apply and reduce chemical costs. The research objective of this paper is to measure polymer cleanup in both propped and unpropped fractures utilizing multiple methods. Additionally, the study will compare rheological measurements to proppant transport observations in brines using a large-scale slot flow device. API conductivity cells determined pack damage over a range of proppant sizes, HVFR's, and temperatures. An extended length conductivity (ELC) apparatus was utilized for comparison with the API cell. Cleanup in unpropped fractures employed a core holder using fractured core plugs. HVFR rheological property measurements include low and high steady shear measurements, and oscillatory measurements used to determine elastic properties. Mix waters include fresh water, salt solutions, and a simulated field brine. Proppant transport in fresh and simulated field brine is evaluated in a 1 × 8 foot slot flow device. Proppant deposition rates are recorded using video cameras. Propped fracture cleanup in the API cell and ELC apparatus is a function of proppant mesh size and HVFR type. As mesh size decreased, the potential for damage increased. Tests with 50/140 mesh proppants in the API cell in some cases showed significantly impaired regain conductivities as low as 65%. When compared to the ELC, API cell cleanups were in some cases significantly optimistic. Cleanup also varied greatly with HVFR product. Even with a low loading of HVFR of 1 gallon per thousand gallons of fluid (gpt) significant damage was sometimes noted. The tests of the unpropped fractures showed that very severe damage to unpropped fractures may occur. The presence of salts significantly and negatively affects HVFR rheological properties for most of the materials selected for this study. Viscosity at higher shear rates (10-511/sec) do not necessarily reflect HVFR performance at lower shear rates. In all tests, the rheological performance between different products exhibited a wide variation in properties, likely reflecting the potentially wide variation in chemical composition. Proppant transport testing validates the rheology measurements. The slot flow evaluations showed a significant loss of transport capability in brines. Commercial HVFR's are not equivalent and require laboratory performance evaluations. The study demonstrated that the potential for significant damage to the proppant pack and reservoir is present with HVFR fluid systems. Even low salt concentrations significantly influence the HVFR rheological performance. Mix water compatibility must be a primary concern when selecting HVFR's. The results of this study provide useful information to engineers for selecting HVFR's and describes a methodology for evaluating damage potential, and proppant transport.

Hydraulic fracturing operations in unconventional reservoirs are increasingly being monitored with fiber-optic (FO) Distributed Acoustic and Temperature Sensing (DAS/DTS). In this paper, we discuss how a single well equipped with fiber optics and DAS can be used as a diagnostic tool to better understand the completions program of three offset wells and the fiber instrumented well. Strain measurements were initially conducted for seismic studies, then followed by measurements of fluid injections from monitoring wells to better understand placement along the lateral section of the wellbore for programs such as hydraulic fracturing, water flooding, and steam injection. The broadband DAS signals have shown of value for the monitoring of microseismic, as well as thermal and mechanical strain of the fiber over the entire well-pad's completion process. During well stimulation, as a fracture propagates to an offset wellbore with fiber deployed, the DAS measurements can be used to monitor very small changes of strain on the fiber. Analysis of the Cross-Well Communication (CWC) strain measurements provide information about possible fracture numbers and locations, as well as the fracture propagating rate based on known well distance. Changes in the strain measurements are coupled with microseismic events that can be simultaneously monitored using the same interrogator unit and fiber optic cable. Here we present various diagnostic tools for DAS that help to better understand the completions program. A variety of physical effects, such as temperature, strain and micro seismicity are measured and correlated with the treatment program to aid in the analysis. Two of the offset wells were zipper-fractured first, then the fiber installed well was zipper-fractured with the third offset well. By monitoring CWC strain measurements we show that DAS can assess the treatment and performance of neighboring wells that are not instrumented with fiber optic cable. Low frequency strain events from neighboring wells provide direct measurements of the fracture density and possible fracture network post fiber well completion. CWC measurements can provide strain levels that can be analyzed in the context of the various completion parameters including stage length, clusters, and well spacing, etc. We also discuss the fluid and proppant allocations measurements that can be performed on the well with fiber installation. We show how DAS can be used as a tool for investigating cluster efficiency, diverter effectiveness, and for determining completions problems like screen-outs and stage communication. The analysis of the DAS data demonstrates that current fiber-optic technology can provide enough sensitivity to detect a significant number of frac events that can be used for an improved reservoir description and as an assessment of the completions program.

Frac Driven Interactions (FDI) have gained much attention, but like many past challenges in our industry, a solution is not far behind. The ability and willingness of operators to share information is at the core of advancing this solution. Not content to just shut-in our wells and "hope for the best" during nearby frac ops, we decided to pro-actively learn about FDIs and to apply the learnings to frac defense. Frac defense not only protects the primary well, it also helps to prevent asymmetrical fractures in the infill well. We provide methodology used to design and implement FDI defense. Additionally, we also show how we analyzed the results of the FDI defense to determine its success. In 2018, we had an opportunity to learn about FDI and documented those interactions, along with the analysis, in SPE 194349-MS. The original study was initiated to understand FDI and to ultimately determine appropriate mitigation. In this case study, we used the findings from the initial study to select suitable mitigation: pre-loading the primary well with water prior to offset fraccing operations. The study location is one that had previously experienced FDI from offset development wells. The primary wells had recovered quickly from the past FDI but due to an additional year of depletion, our research showed that recovery would probably be longer. The workflow covers well candidate selection, necessary personnel and equipment on location, and the risk analysis of the overall project. To monitor the effectiveness of mitigation after pre-loading, the team placed wellhead pressure sensors on pre-loaded primary wells, and primary wells in the adjacent pad. Sensors were installed on select vertical wells perforated through the target zones. In addition, wirelessy connected, high-pressure sensors were deployed on actively fraccing wells. All sensors were time-synced and monitored in real-time. Pressure results indicated that mitigation using the water pre-load method dampened FDIs. A successful application would manifest in pressure dampening and a reduction of recovery time. At the time of this writing, flowback operations are ongoing and one primary well recovered to pre-frac rates within one week. We anticipate a corresponding reduction of recovery time in the other wells. Most importantly, the infill well immediately offset from the primary is performing as good or better than the other infills in the same interval. This paper presents methods ad processes that offer a potential solution to identify candidates for fracture mitigation, and optimize project economics in a full section, multi-bench development. A novel aspect to the data is that all wells were wirelessly connected to the internet, time-synced with the atomic clock, and monitored in real-time. Time-synched pressure indicators immediately reveal the earliest signs of well-to-well communication across the entire field of active and passive wells. Pressure readings are reflective of FDIs allowing the operator to monitor, and proactively apply mitigation techniques in real-time. This process is known as "active well defense." However, due to certain limitations, we deployed a "passive well defense" where we injected water into the primary wells prior to frac operations.

This work aims to address a challenge posed by recent observations of tightly-spaced hydraulic fractures in core samples from the Hydraulic Fracturing Test Site (HFTS). Many fractures in retrieved cores have sub-foot spacing, which is at odds with conventional models where usually one fracture is initiated per cluster. Since it is unrealistic to explicitly model all densely-spaced fractures, we develop a new upscaling law that enables existing simulation tools to predict reservoir responses to fracture swarms. The upscaling law is derived based on an energy argument and validated through multiscale simulations using a high-fidelity code, GEOS. The swarming fractures are first modeled with a spacing that is much smaller than the cluster spacing; these fractures are then approximated by an upscaled, single fracture based on the proposed upscaling law. The upscaled fracture is shown to successfully match the energy input rate and produce the total fracture aperture and average propagation length of the explicitly simulated swarm. Afterwards, the upscaling approach is further implemented in 3D field-scale simulations and validated against the HFTS microseismic data of a horizontal well in the Middle Wolfcamp Formation. Our results show that hydraulic fracture swarming can significantly affect fracture propagation behaviors compared with the propagation of single fractures as assumed by conventional modeling approaches. Under the considered situations, the conventional case entails fast propagation speed that far exceeds that indicated by the microseismic data. We also illustrate this discrepancy can be reduced readily through the implementation of the upscaling law. Our results demonstrate the importance of accounting for the fracture swarming effect in field-scale simulations and the efficacy of this approach to enable realistic predictions of reservoir responses to fracture swarms, without explicit modeling all tightly-spaced fractures observed in the field.

The effect of horizontal well spacing on stimulation performance and well results is of keen scientific and economic interest to the industry. The objective of this paper is to demonstrate these effects in a grouping of five horizontal Wolfcamp wells drilled in a down-spaced configuration where inter-well distances were reduced from 1320′ to 660′. The subject project is located in Ward County, Texas, on a 640 acre lease. A stand-alone Wolfcamp A2 zone well (legacy well) was drilled on the project acreage in late 2016 followed by the drilling of four development wells directly offsetting the legacy well in mid-2018. The four development wells were spaced 660′ apart as opposed to the existing norm of 1320′. This paper presents various pressure, microseismic, tracer, and production data collected during and following the zipper stimulation of the four development wells. This rich data set yielded significant information about the drainage characteristics of the legacy well, the effect of pressure depletion on fracture geometry, the nature of fracture driven interactions (FDI) in down-spaced wells, and the inter-relationship of these factors in their effect on production results. Active well defense was performed in the legacy well and results from these defense operations is also reported. Inter-well spacing of 660′ between wells in the same zone resulted in significantly diminished production results compared to the base case resulting in lowered projected rates of return for the well group. Depletion in the legacy well resulted in larger fracture geometries in the nearest development wells, but not in wells 990′ away. This resulted in larger stimulated volumes in the nearer wells but also diminished oil production. The inferential conclusion is that localizing stimulation energy in the near vicinity of the treated well yields improved well results. Concerning FDI, the data indicate that wells within 660′ of each other are likely to interfere with each other, while the opposite was true for wells that were 990′ apart.

This paper describes a new and comprehensive 3D hydraulic fracturing simulation model, built within a single software system combining Finite-Difference reservoir flow simulation with Finite-Element displacement and stress/strain computations. This allows dynamic and explicit calculation of fracture width (i.e., opening, propagation, and closing) and modeling of surrounding dynamic stimulated reservoir volumes. This new fracture modeling formulation advances the model initially developed by Ji et al. (2009) and the workflows described in Min et al. (2018) and Sen et al. (2018) for optimization of completion design and well spacing in unconventional reservoirs. The new code relies on carefully considered algorithmic constructs (such as iterative coupling). It was designed for ensemble modeling over ranges of uncertainties in petrophysical and mechanical stratigraphy. Multiple options for combining node displacements on the fracture face along with new iterative algorithms and efficient use of elements of symmetry allow for representative calculations for a range of models with reasonable runtimes. The workflow uses structured grids, and the same block definitions are used for both the flow and geomechanical computations. Fracture extent and width, leakoff, and stress-dependent permeability enhancement in the stimulated reservoir volume (SRV) are all computed in a coupled fashion, based on reservoir flow characterization and mechanical stratigraphy (stiffness and stress) in a fully 3D heterogeneous sense. This tool has been used to model hydraulic fracturing (fluid injection), flow-back, and production within a single workflow. The evolution of the fractures can be tracked in usual time step fashion, along with leakoff, multiphase saturations, and pressures on a 3D grid. Simultaneously, the model computes the poroelastic changes in all stresses and their effect on fracture propagation or closure and on permeability and porosity of the media, i.e., the SRV development. Dynamic fracture height, width and length are determined without the constraints of explicit shape assumptions or simplifications; rather, they are computed based on propagation criteria using local, dynamic pressure, mechanical properties and stresses. We have also used this new simulator to model and match Diagnostic Fracture Injection Tests (DFITs). The complexity of the interactions of physical mechanisms in this model requires large computing times. A significant improvement in run time (an order of magnitude) was achieved by using new algorithms for the iterative solution of the flow/stress/fracture coupled problem. This provides possibilities for modeling fracturing in complex reservoirs with a new level of accuracy. For example, the model provided new insight in the importance of flow friction in the fracture for history matching the pumping pressure. In DFITs, the simulated details of fracture initiation and closure can be used to calibrate mechanical properties as well as permeability behavior with stress. Finally, the capability to use 3D stress and reservoir characterization is invaluable in modeling cases of unusual vertical fracture growth. Practicing engineers will appreciate the value of the integrated simulator presented herein. It helps in developing a clearer understanding of the causal effects of different factors that impact the success of a hydraulic fracturing/stimulation program. These factors include geological, tectonic, mechanical, and operator influences. Using this simulator as a kernel, powerful completion optimization workflows can be built by running a priori simulations of numerous permutations of influencing factors.

Fracture propagation is a complicated process in multiple fracturing treatment, especially when initial stress field altered after long-term producing. It has been verified that injection and withdrawal of underground liquid alters stress field then leads to fracture reorientation, which benefits wells by stimulating areas with more residual oil and less depleted pressure. To investigate fracture propagation with altered stresses, multiple fracturing treatment are simulated by inducing stresses change with complicated well patterns under true-triaxial condition. Multiple fracturing treatment are performed on cubic samples with 30cm side length in laboratory on a self-assembled true-triaxial fracturing system. System is composed of five parts, true-triaxial apparatus, hydraulic injectors, digital data acquisition, drilling and completion, acoustic emission. Samples are loaded with independent confining stresses and then wells are drilled and completed with stresses applied. Well patterns of three-spot and five-spot are located on the samples to simulate field well patterns. Then multiple fracturing treatments are performed with fracture propagation monitored using AE by changing injecting pressure of each well and independent confining stresses applied on the samples. Process of fracturing and refracturing treatment is successfully simulated with two ways of altering initial stress field, changing the confining stresses and inducing stresses change by injecting from different located wells. Poroelastic theory is used to illustrate two kinds of reorientation. It is shown that fracture initiates and extends perpendicular to the minimum horizontal principal stress under initial confining stresses during the initial fracturing. By changing the confining stress, increasing the injecting flow rate and using high viscosity of injecting fluid, new fracture initiates and reorientates to a new direction which is perpendicular to the former fracture in refracturing. In the five-spot wells pattern, initial fracturing is performed on the middle well with same low backpressure applied on the other four edge wells and fracture obtained is just perpendicular to the minimum horizontal principal stress as it should be. However, by changing the injecting pressure of different located edge wells which are supposed to provide porous pressure from different directions to the middle well, fracture orientation in multiple fracturing can be changed to over 30° in angle. All fractures initiated and propagated are successfully monitored by acoustic emission and later verified by slicing the samples. Large blocks of samples are used to eliminate the scaling problem as much as possible, besides, simulations of fracturing and refracturing are all monitored by acoustic emission to depict the propagation of fracture. Angles of fracture reoriented are obtained and evaluated in the complicated fracturing process which can be used to quantitatively study the effect of stresses change to fracture reorientation based on poroelastic theory. Complicated well patterns are applied to reveal well interference.

Reduced production from child wells has been observed due to prior depletion around the parent well. In this work, a systematic simulation study is conducted to understand the effects of parent well depletion on child well fracture growth and production. A three-dimensional hydraulic fracturing simulator based on the displacement discontinuity method is used to simulate parent well fracturing. The created hydraulic fractures are transferred into a finite volume-based geomechanical reservoir simulator for production simulation. The pressure and stress profiles in the reservoir after production simulation are then used in the hydraulic fracturing simulator to capture the effect of depletion on child well fracturing. Infill timing (parent well production duration before child well stimulation) is varied, and its impact on child well fracture geometry and the production (from the child and parent wells) is investigated. The depletion of the reservoir due to production from the parent well can have a significant effect on the child well fracture growth. Asymmetric fracture growth, the tendency of the fractures to grow towards the depleted region, is clearly observed. The effect of the extent of depletion (infill timing) on asymmetric fracture growth for different reservoir diffusivities ( k μ ϕ c t ) is quantified. The impact of child well fracturing on the parent well production is explored for different operating scenarios. The effect of well spacing on parent-child well interactions is also analyzed. This work provides quantitative estimates of the impact of depletion on the fracture geometry, and productivity.

Near-wellbore diversion of fracturing fluid and proppant is a common objective when refracturing horizontal wells for expanding treatment coverage within the lateral. There are five broad categories of near-wellbore diversion methods: (1) particulate diversion for bridging open fractures connected to the wellbore, (2) perforation sealing to limit injectivity into open perforation clusters at the wellbore, (3) filling up the drained fracture system with water for achieving more uniform pressurization (i.e., fill-up), (4) injection rate cycling/hesitation fracturing and (5) mechanical isolation by installing cemented or expandable liners in the lateral followed by plug and perf stimulation. These tactics can be used in isolation or combined. Particulate diverting agents can be additionally categorized by particle type (e.g., granular, fibrous) and solubility characteristics. Perforation sealing agents consist of deformable and rigid/spherical subtypes, both of which can be further categorized by solubility characteristics. In this study, treatment and production data for 72 company-operated refractured wells in a North America shale play were analyzed to evaluate the effectiveness of the various near-wellbore diversion methods and materials. An index was formulated using information on reservoir depletion to normalize changes in bottom hole fracture pressure over time. This was determined by periodically discontinuing injection to obtain instantaneous shut in pressures (ISIP’s) over the course of the treatment. The calculated indices were plotted for each type of diverting system to compare trends for gaining insight on in-situ stress buildup. Production data grouped by different diversion methods were also analyzed. The near-wellbore diversion methods included mixed-size particulates with and without fibrous materials, deformable and rigid perforation sealers, fill-up tactics in which near-wellbore diverting agents were not utilized and mechanical isolation by cementing a newly installed liner in the lateral followed by plug and perf stimulation. Frac hit analysis of offset well treatments indicated that refracturing treatments using particulate diverters were heel biased with respect to reservoir re-pressurization. The study showed that the incremental pressure as a result of diverter landing on perforations is a poor indication of diverter efficiency. Non-normalized ISIP trend is misleading as an indicator for post-refracturing well performance. Refractured wells with either particulate diverters or perforation sealers both show initial fluid fill-up into the depleted region before the stress buildup plateaus. Wells that have liners installed and cemented inside the original wellbore and that are then re-stimulated with standard plug-and-perf techniques show superior performance compared to all other diversion methods. Choice of diversion can have a significant impact on results, but not all particulate diverters or perforation sealers behave similarly. Wells refractured using only the fill-up method have long term productivity on par with or better than wells refractured with most types of diverting agents.

Methods for analyzing surface pressure data in real time are proposed and demonstrated to improve the completion design and cluster efficiency of child wells while protecting nearby parent wells. This study involves three parent wells and ten child wells, landed horizontally in the Wolfcamp A and B reservoirs in the Delaware Basin. An integrated real-time analysis of surface pressure measurements acquired from parent and offset child well completions enabled informed decisions regarding pump rate, fluid volume, frac stage sequence, and diverter schedule on subsequent stages. Results included the mitigation of frac-hits at the parent wells and improved fluid distribution of the child wells. Real-time monitoring indicated significant fluid communication during treatment between child and parent wells. The order of operations and completion design were changed during the job to reduce the risk of adverse effects on both well types from frac hits. By changing the treatment design, the magnitude and characteristics of pressures observed in the parent well showed significant reduction in the intensity of fluid communication. The design change also improved cluster efficiency of the nearby child wells, with no indication of damaging frac hits occurring. Pressure-based fracture mapping was used to supplement observations from the parent well. These pressure responses, recorded from an isolated stage on an offset well, were used to compute fracture geometries and growth rates of the stimulated fractures. The fracture height of the child wells decreased after adjusting the order of operations and completion designs during stimulation, which indicated fracture containment within the target zone. These results validated the improved cluster efficiency findings. The differences in geometries and growth curves were interpreted as improved fracture quality near the wellbore, with no damaging frac hits from the completion stages. Real-time pressure monitoring and analysis provides immediate, accurate feedback during stimulation. Data-driven decisions enables optimization of the frac design and pump schedule (slurry rate, slurry volume, proppant volume, proppant concentration, etc). Comprehensive understanding of the fracture growth behaviors assists in making more-informed decisions during the execution of a well stimulation program, mitigates parent well damage, and enhances child well production.

The objectives of this paper are twofold. First to evaluate the extent, or shadowing, of the stresses and displacements resulting from an internally pressurized crack and second to show how a creative testing apparatus can model the interaction of multiple fractures and display the influence of stress shadowing. The solution for 2-D planar crack in elliptical-cylindrical coordinates was used to evaluate the stress and displacement shadowing. This analysis indicated that the compressive stresses for a pressurized crack of length H, will dissipate by 100% within a distance d/H = 3/4. The analysis also showed that the shear stresses and displacements are concentrated in a small area around the crack tip of radial distance equal to d/H = 0.05. H is crack length and d is distance from the crack. Following this analysis, the mechanical apparatus was used to visualize the influence of the stress and displacement shadows in the propagation of multiple fractures. The example that validated the application of the apparatus consisted of modeling the merging of two fractures observed in the 2017 Puebla, Mexico earthquake. In this case, both the testing apparatus and the numerical results given by a two dimensional Finite Element (FE) code closely reproduced the field observations. Following this validation, the application of the testing apparatus was extended to model the propagation and interaction of multiple fractures. Three cases were considered. Case 1, consisted of a main fracture propagating between pre-existing fracture-pockets filled with fluid (pressurized pockets). Case 2, included the propagation of multiple parallel fractures. Case 3, considered hydraulic fractures propagating through zones populated with micro-fissures. Case 1, showed how a hydraulic fracture can activate and propagate pre-existing frac-pockets. This example could explain how some frac-hits occur. Case 2, illustrated that from a cluster of several parallel fractures that are close to each other (D/H < 1), only one or two dominant fractures will propagate. D is distance between parallel fractures. The experimental results for Case 3 indicated that the micro-fissures diverted the direction of fracture propagation and also increased the tortuosity. The extent of departure and degree of tortuosity depended on the orientation of the micro-fissures. Micro-fissures normal to the crack resulted in more diversion and more tortuosity compared to the diversion and tortuosity resulting from micro-fissures parallel to the crack. Further the tests also showed that the micro-fissures not aligned with the fracture also suffered significant dilation.

Not all unconventional plays are created equal, in a substantial number of regions around the world the tectonic environment is quite different from the typically relaxed and more passive states found widely in most, if not all, of the US unconventional plays. This is merely a function of the relative proximity of such plays to distinct geological features characterized by active tectonic plates and with dynamic margins and recent activity. The Nazca plate associated with the Andes, the Arabian plate linked with the Al-Hajar mountains and the Indian plate connected with the Himalayan mountain range are just a few examples of tectonically influenced regions, where potential hydrocarbon traps are subject to complex states of stress generated by convergent plates, subduction zones and associated faulting. This scenario often translates into severe strike-slip and reverse fault stress states. Additionally, the presence of both multi-layered and laminated formation geology as well as the presence of overpressure and pressure differentials, typical of tight gas and shale gas, can exacerbate this situation even further. This situation can result in an extremely challenging environment for the successful execution of hydraulic fracturing and the associated development of unconventional resources. This paper will demonstrate, that such complex stress-states will directly affect well completions and hydraulic fracturing in a multitude of ways, but that some of the most impactful consequences are often severe casing failures, production-liner restrictions and complex fracture initiation scenarios. Casing failures are responsible for increased intervention costs as well as higher costs for the upgraded and strengthened wells. Equally, such issues can severely impair efficient execution of the completion plan and create a bottle-neck to subsequent well production. Horizontal, complex and pancake fractures will typically develop in strike-slip / reverse fault stress states, often resulting in fracture conductivity and connectivity loss that will greatly impair the eventual well performance. Layer interface slippage and natural fault re-activation are dominant mechanisms for hydraulic fracture induced casing failures. Examples of micro-fracs, micro-seismic and other diagnostics will be presented aiming to document the practical difficulties encountered while completing wells in these complex environments. This paper will demonstrate that unconventional development in such environments requires a renewed focus on all aspects of well design and construction, from directional drilling and lateral placement to casing selection and lower completion design. All these considerations are made with the goal of enabling the competent delivery of a highly effective and conductive fracture network, to efficiently access and produce the hydrocarbon resource.