The Eagle Ford Shale play has undergone significant development over the last decade, with indications that there is still room for additional development. As operator's move to non-core areas there is a need for additional optimization to effectively drain these new areas. This paper studies trends emerging from a post-stimulation completion diagnostics database, comprised of over 10 years of data, to help identify factors associated with effective horizontal completions in the Eagle Ford shale. By employing data analytical techniques to the horizontal well database, critical production performance metrics and insights associated with effective completions are presented. Coupled with this, case histories are also included that illustrate techniques that have increased overall completion effectiveness in relation to proppant placement, cluster treatment efficiency, stage containment, well deliverability, wells spacing/frac size optimization, and ultimately increased production performance. The case histories also highlight the effects of completion optimization on limiting production declines as operators move into non-core acreage over time in most North American shale plays, and more specifically the Eagle Ford shale.

The success of a fracturing treatment and long-term productivity highly depend on the residual proppant pack conductivity over time. One of the challenges operators face is the conductivity loss due to proppant flowback or sand production during production operations. As proppant particles come out of the fracture along with the production, the fracture conductivity diminishes with time as the fracture width decreases. This choking effect causes well production decline while the high-velocity low-concentration proppant particles wreak havoc on both downhole and surface equipment. As a result, proppant flowback costs millions of dollars through loss of production and expensive equipment damage. Wells experiencing these problems require remediation ranging from routine wellbore cleanouts to expensive artificial lift equipment repairs. Hydraulic fracturing became the mandatory stimulation technique to economically produce hydrocarbons in mature fields. However, proppant flowback following the fracturing treatment has been a major concern because of its detrimental effect on production equipment, leading to plugging or erosion of surface and downhole completions. The net impact of proppant flowback can be reduced production, damaged equipment, and downtime. This has prompted a detailed integrated study including both laboratory testing and development of the necessary numerical simulation models to fully understand the post-fracturing proppant flowback mechanism. Resin-coated proppant (RCP) was originally developed for post-fracturing treatment proppant flowback control. However, RCP requires a specific temperature trigger to get activated, which puts some restriction on the RCP application range. In addition, RCP requires prolonged shut-in time, which may cause issues with well cleanout, and RCP is relatively expensive. Another innovative solution that can be used for flowback control in certain conditions is a new flowback technology with nondegradable fiber proppant, designed specifically for low-temperature applications. This technology provides extraordinary proppant-pack integrity by interlocking proppant grains in a flexible 3D network. The grains do not require temperature activation and so perform equally well at any temperature below 200°F, both in oil and gas reservoirs. The fibers can be applied with any proppant (sand or ceramic), and they keep the proppant consolidated even at stress cycling conditions. Unlike RCP or other chemical treatment method, the nondegradable fibers rely on mechanical interference of the particles and not on chemical bonding. The key advantages of this technology are that consolidation is not dependent on activation temperature or time, and the proppant does not interfere with fracturing fluids or additives such as breakers that are known to be adversely affected by the presence of resin material. This paper presents the results of extensive laboratory evaluation and numerical simulation models of fiber performance, as well as global field case histories of successful application of the fiber as a solution for proppant flowback control in low-temperature environments. In all wells, remedial work has significantly dropped due to the excellent proppant flowback control. Meanwhile, the proppant flowback issues have been completely stopped, which led to remarkable success.

This paper covers the research, development, and field application of a cost-effective, on-the-fly chemical additive that reduces proppant flowback during well production. Laboratory tests and field results, showing the effect this chemical additive has on proppant flowback, are examined. Previous proppant flowback prevention methods are reviewed. Laboratory tests that were performed to ensure effective on-the-fly coating in the blender tub, as well as the ability to control proppant flowback, are also analyzed. A review of fracturing treatments performed in wells utilizing the proppant flowback control additive (PFCA) is provided. Post-fracture treatment proppant flowback and production results are compared to direct offset wells using conventional proppants. Fracturing treatment designs, formation characteristics, and proppant types are presented. Laboratory proppant flow tests show PFCA-treated proppant can withstand a much higher critical flow rate than uncoated fracturing sand. Unconfined compressive strength tests indicate that proppant is coated efficiently in the blender tub, enabling effective consolidation at downhole conditions. The results of laboratory tests are used to explain and support the field case studies. The field case studies show that use of PFCA significantly reduces proppant flowback and typically results in higher hydrocarbon production when compared to conventional proppants used in offset wells. With completion designs moving to finer mesh size proppant and higher proppant loadings per lateral foot, operators are increasing spending to deal with higher amounts of proppant flowback. This paper introduces an important technology that is an economically viable and beneficial substitute for traditional proppant flowback prevention methods.

Switching to utilize HVFRs has been blossomed rapidly due to enormous advantages such as the ability to carry proppant and high potential lower cost. However, challenges remain in fracking fluids rheology characteristics due to a change in water quality that leads to poor proppant transport through fractures. The primary objective of this study is to develop a mathematical model based on prior published experimental data that can be used to predict HVFRs viscosity profile as a function of essential factors. Water analysis and viscosity property characterization of the selected fracturing fluid (HVFR) were investigated to address the effect of water quality on proppant transport behavoir. In this paper, a case study of the Permian Basin produced water "high-TDS (125Kppm)" was chosen in screening criteria analysis. Also, different dosages (0.25, 0.5, 0.75, 1.0, and 2.0 gpt) of HVFRs were selected to estimate the viscosity profile in freshwater and the Permian produced water. The developed new model from this study can be used effectively to predict viscosity profile and proppant transport in HVFRs fluids taking into account fracture fluid dosage, water quality, and operation shear rate. The developed model covers HVFRs dosage ranging from 0.25 to 2.0 gpt (gallons per thousand gallons). This model can be used to assist in obtaining proppant settling velocity as a function of shear rate. The developed model shows the high accuracy of prediction HVFR viscosity profile with a low average error of 0.14% and 0.07% in freshwater and Permian produced water, respectively. This paper will help provide a full understanding of the distinct changes of the mechanical characterization on the HVFRs. The findings provide an in-depth understanding of the behavior of HVFRs under high-salinity conditions effect, which could be used as guidance for fracture engineers to design and select the optimum dosage of friction reducers.

This paper presents a case study of fracture interaction mitigation in a multistage horizontal stimulation of an offshore Black Sea well. A multi-faceted approach in applying lessons learned and pre-job geo-mechanical analysis of depletion-induced stress differential and its effects on fracture interactions will be discussed. Details of on-the-job, real-time bottom-hole pressure monitoring of nearby wells, with the effort of on-the-fly pumping schedule changes, will also be provided. An analysis was conducted on past fracture interactions observed from multistage stimulation jobs in the area. Depletion, distances between producing wells, and a stress analysis was performed using fracture simulation software, and a consequent analysis of fracture geometry was applied. A bottom-hole gauge pressure profile assessment of nearby wells, including the pre-stimulation, shut-in, and post-stimulation period of the targeted well, was completed. A redesigned treatment was applied, considering a mitigation plan for potential on-the-fly changes during pumping. A holistic tracer analysis of production contribution between stages and wells was performed, with the goal of understanding possible crossflow of production fluids. Past-fracture interaction events have been analyzed, and clear drivers for fracture hit communication were observed. Extreme depletion effects were a primary factor in enabling fracture communication. The preferential fracture growth was further enabled owing to the continuous production of nearby wells and no shut-in implementation. The 3D geo-mechanical model was built using pertinent data from the targeted and nearby wells. The model was further optimized using fracture geometry outputs, and constraints were input to limit the fracture growth and avoid communication. The outcome of the analysis showed a clear driving force behind the interactions was depletion. An on-the-job assessment of diagnostic tests yielded a heterogeneous behavior of the horizontal segment, further proving stress differentials along the lateral. An overall chemical tracer analysis of the targeted and nearby wells was completed using pre- and post-stimulation fluid samples. The results were crucial in understanding the stimulation approach and possible crossflow effects due to fracture communication. Additionally, using bottom-hole temperature readings, a rudimentary cool-down and heat-back analysis was performed to better understand possible fluid interactions with nearby wells and optimize fluid design. Intra-stage fracture interference presents unique events and challenges that are typically managed on a case-by-case basis, and this work presents the critical analyses that are paramount to planning stimulation treatments in highly depleted segments and reservoirs with wells in close proximity.

The Turonian siltstone found throughout the Siberian region in Russia is laminated, heterogeneous, and shaly; has permeability of 0.1 to 3.0 md; and contains hundreds of trillions cubic feet of natural gas. Hydraulic fracturing is necessary to achieve commercial production rates. Important developments have been made in optimizing a water-free fracturing fluid that can be used in similar cold and highly water-sensitive reservoirs worldwide. The study encompassed laboratory testing methodology, testing results, and field trial campaign analysis of the advanced water-free fracturing fluid. Non-Newtonian fluid rheological behavior, proppant transport ability, and fluid break under dynamic and static conditions at 60°F (15°C) were investigated and compared to conventional crosslinked water-based fracturing fluids. The field trials used a fluid recipe that enabled successful execution of very aggressive fracturing designs using large-size proppant placed at concentrations of up to 12 lbm/gal added (1400 kg/m 3 ) in multistage fracturing treatments along a horizontal wellbore. This approach was used to improve fracture conductivity and fracture cleanup while minimizing fluid costs. The most significant advancements have been made in the breaker package design for the fluid mixed in diesel fuel. Improved breaking can accelerate the flowback period and create a high-retained-conductivity proppant pack, allowing large volumes of gas to flow with minimal restriction. Additional study of proppant transport revealed the presence of elastic properties that are not common for water-based guar-borate gels. This property enabled increased proppant concentration and aggressive hydraulic fracturing designs that were successfully employed in a field trial campaign comprising three horizontal wells completed with a total of 10 fracturing operations. Multistage fracturing completions consisted of shifting sleeves for the fracturing stages and separate ports with screens for the production stage to control formation and proppant flowback. This completion enabled selective fracture cleanout, which is vital in the low-temperature geological conditions. The developed stimulation approach resulted in progressive gas production increases after stimulation. Fluid development results indicate the new diesel-based fracturing fluid delivers an improved stimulation approach for low-temperature siltstones containing a high content of sensitive clays. It is the only project we have seen in the literature with a successful diesel-based fracturing fluid application in extremely low-temperature geology. Although developed for Russian fields, the work is equally applicable to any water-sensitive, shaly, low-temperature reservoir globally.

As part of a Department of Energy (DOE)-sponsored program, an optimal thermodynamic pathway to transform natural gas (NG) into pressurized NG suitable for use as the internal phase in a foamed fracturing fluid has been already developed. Using NG foamed fracturing fluids reduces the enormous water requirements for stimulation by as much as 60% to 80% and poses benefits for productivity in water-sensitive formations. This study aims to extend the investigation to characterize the hydraulic fracture geometry and quantify the expected production when using an NG foam fracturing fluid. Using validated models, we provide a comparative analysis to determine the advantages of using natural gas foams relative to conventionally used slickwater, linear gel, and crosslinked fluid. A full 3D reservoir model in a Duvernay Shale formation was constructed. Fundamental laboratory and pilot field tests data was collected for the NG foam fluid properties for numerical modeling. Rheology, friction, and leakoff properties of the fracturing fluids were incorporated in creating a numerical model. A 3D-complex hydraulic fracture simulation model incorporating 1D and 2D particle transport models were used. A numerical reservoir simulation for different sensitivity scenarios was incorporated for fracture modeling and gas production evaluation. Owing to lower density than conventional liquid column, the NG-foamed fluids are likely to result in higher surface pressure. A reduced pump rate with NG foamed fracturing fluid leads to a lower frictional pressure loss in tubing, without compromising the ability to place the desired amount of proppant in the formation. The non-Newtonian shear-thinning NG-foamed fracturing fluid exhibits a higher, effective viscosity that enables effective transport of the proppant. Modeling results indicate that the overall fracture geometry and proppant placement is much better for NG-foamed fluids than high-volume slickwater needed to pump the same amount of proppant for well spacing and a field development plan. The simulated production performance for medium-viscosity fluids such as NG-foamed fluid, linear gel, and high-viscosity slickwater, is better than that of low-viscosity slickwater or high-viscosity crosslinked gel fluids. A low-viscosity fluid results in proppant settling and dunning, resulting in lower conductive height of fractures while the high viscosity treatment uses less fluid, so the surface area created is less and there is potential for height grow out of the target formation.

Hydraulic fracturing is a widely applied technology to increase recoverable reserves and accelerate production in low permeability reservoirs. In this technique, the hydraulic fractures are generated by pumping a fracturing fluid at a high flow rate and introducing proppant with the fluid to keep the fractures open after the pumping is halted. In horizontal well fracturing, one of the most important factors in this method is the proppant transport and distribution in the wellbore and among perforation clusters. Uneven proppant distribution between multiple clusters/fractures can cause a drop in the near-wellbore fracture conductivity, which in turn causes a negative impact on the production performance of the hydraulic fractures. This paper presents new experimental correlations that were developed and can be utilized to predict the proppant distribution between subsequent perforation clusters. The experimental correlations were developed using dimensional analysis from appropriate experimental data. The experimental data for this study was obtained from a horizontal wellbore apparatus with three perforation clusters at shot densities of 4 SPF with 90-degree phasing. Several experimental tests were conducted on 20/40 and 40/70 for white sand (SG of 2.65) and ultra-light weight ceramic (SG of 2.0) using freshwater fluids at three flow rates and over a wide range of proppant concentrations. Four types of experimental correlations were developed by experimentally investigating the effect of each parameter on the proppant distribution between the three perforation clusters. The first correlation type developed is based on the proppant concentration, while the second type is based on the flow rate and proppant concentration. The third correlation type includes the particle median diameter as another independent variable, along with the flow rate and proppant concentration. The fourth and final correlation developed consists of the proppant density along with the proppant median diameter, flow rate and proppant concentration as its independent variables. This fourth and final correlation was validated by comparing the predicted values to the laboratory values. The results of correlation analysis comparison to lab data show that the 20/40 and 40/70 ULW ceramic showed the lowest average error values at 2.92% and 1.56%, respectively, while the 20/40 and 40/70 white sand transport predictions were reasonable (average error range of 3.67% - 11.67%). The low error values indicate the high reliability of the developed correlations in predicting the proppant distribution between perforation clusters. To the authors’ knowledge, the developed correlations are the first of their kind to be based on experimental data. These correlations can help to determine the optimum flow rate that is required to attain even distribution of the proppant and provide more insight about the anticipated proppant distribution into and out of perforation clusters.

Acid stimulation is a common remedial practice for formations that produce below the target production rates. Acid stimulation can be performed during the early-life of a well, soon after the well is put on production, or more typically, following a production period once production rates have started to decline. Often, acid treatments are repeated multiple times during the producing life of a well, as restimulation becomes necessary. Sandstone acid systems can contain organic acids and/or hydrochloric acid, HCl, to target damage caused by carbonate solids, inorganic scaling, residual gel from fracturing operations or fluid loss control events, while hydrofluoric acid, HF, is used for siliceous damage/fines removal, mainly from and around the proppant pack in a hydraulically fractured formation. In a fractured formation, the acid sequence will first penetrate the least resistant zones, i.e. the fracture, and leak into the fracture face. For a propped fracture, proppant embedment at the fracture formation face naturally occurs under closure stress and increases with depletion. A test program was designed to evaluate the effect of remedial acidizing practices on proppant embedment, frac face damage and reduction in porosity and permeability of the formation in these zones. A test method that can directly measure fracture-face permeability in parallel to fracture conductivity has been used to measure acid exposed fracture face permeability and proppant pack conductivity under depletion conditions. Initial tests were conducted in intermediate permeability, medium strength sandstone rock where baseline proppant conductivity and fracture face permeability were established with synthetic brine flow. Next, a remedial acid system was injected into the fracture and was allowed to leak-off into the fracture face. Following a shut-in period, brine was flowed back across the core platen representing the formation and the permeability of the core was tracked as a function of time under constant stress. Proppant pack permeability was also measured with brine flow along the fracture. The acidizing, shut-in and flow-back sequence was repeated three times to measure the impact of multiple acidizing treatments on proppant embedment, frac face damage and permeability loss. A similar test was conducted with five sequences of acid injection for comparison. Post-test analysis was conducted to study frac face damage, depth of proppant embedment and damage zone, rock strength and presence of fines in pore space. Test results were compared to those conducted with unacidized core. The impact of repetitive acidizing practices on stimulation at the fracture face and on proppant embedment was investigated using the modified Frac Face Damage (FFD) test set-up, a test system that was introduced in earlier studies. At constant closure stress, FFD tests with acid injection can show permeability increase, followed by a decline in permeability. Current results suggest rate of permeability decline might accelerate after multiple acid treatments. Post-test analysis of the fracture face core has been conducted to evaluate the cause of the permeability reduction. Scanning Electron Microscopy (SEM) analysis show dissolved core material and fines being carried into the fracture face with one test. Micro CT-scan analysis is used to track porosity reduction at the fracture face. UCS and triaxial measurements are conducted to compare the change in the rock strength to that of the unacidized core. Thin section analysis of the fracture face core shows wide-spread grain crushing that penetrate deeper into the fracture face compared to unacidized core material tested with the same equipment.

This paper presents a method for identifying the optimum soaking time between the cessation of pumping, and the flowback of hydraulic fracturing fluids after a hydraulic fracture stimulation job, to increase productivity of shale gas and oil wells. Multiple cracks were observed at the surfaces of cores from a shale oil reservoir under simulated water-soaking conditions. The observation proposes a hypothesis that the formation of cracks should increase well productivity. Well shut-in pressure data recorded in a watersoaking process in a shale gas reservoir were employed to derive a mathematical model to describe the process of crack propagation in shale gas/oil formations. This crack model was incorporated in a well productivity model to form an objective function for selection of the water soaking time. A field case was studied with the mathematical model to proof the hypothesis and explore factors affecting the optimum water-soaking time. Analysis of the model shows a quick increase of well productivity with water-soaking time in the beginning followed by a trend of leveling-off. The water-soaking process is mainly controlled by the number of cracks along the bedding plane. High viscosity of fracturing fluid corresponds to longer soaking time, while increasing water-shale interfacial tension reduces the optimum soaking time. The effect of different initial water saturations on optimum soaking time was found to be insignificant. If real time shut-in pressure data are used, this technique can translate the pressure data to dynamic crack propagation data and "monitor" the potential well productivity as a function of water-soaking time.

During hydraulic fracturing of low to moderate (0.1 – 50 md) permeability reservoirs using crosslinked gel fluids, the final proppant stage displacement is designed to leave some volume of proppant slurry above the perforated interval. This practice of underflushing is based on a paradigm that considers the overdisplacement of proppant past perforations to be a major risk to well productivity. The theory behind this paradigm is investigated and finds that it relies on several physically unrealistic assumptions. Numerical simulations were performed to understand the impact of a fracture overflush on well productivity. A new methodology was developed for overflushing fractures that enables significant cost/time savings without impacting well productivity. A multi-well field trial in a 2-20 md reservoir was conducted andcompared well performance from overflushed crosslinked gel fractures to underflushed fractures. Some of the trial results have been reported by the authors ( Chaplygin et. al. (2019) ) and are further updated/analyzed in this work. The analysis confirmed that the managed overflush fractures have equivalent performance to underflushed fractures. The analysis also confirmed multiple benefits from the managed overflush wells including reductions in completion costs/time and an improved HSSE risk profile. The results challenge the validity of this decades old paradigm.

Production history matching data is an important step in any study that seeks to optimize unconventional completions and well development criteria. Understanding the reservoir mechanisms during production allows for better optimization of the hydraulic fracture system. Generating a model that fits historical data can be easy but honoring the true petrophysics and fluid dynamics of the reservoir is often challenging. Some of the major challenges during reservoir simulation are uncertainties in water saturation, permeability, phase behavior, and effective fracture surface area during production. This paper discusses how fit-for-purpose core measurements help reduce the uncertainty in these parameters, ultimately requiring a multiple porosity reservoir simulation model to account for these improved measurements and understandings. Industry accepted core analysis techniques under-estimate reservoir water saturation due to loss of water from evaporation and core handling techniques (preservation, crushing, time). Proper evaluation of the void space will be shown and how this is better calibrated to field data. A review of how steady-state liquid permeability testing provides better estimates for reservoir permeability and deliverability in shale reservoirs will be discussed. Coupling these measurements with imbibition effects from hydraulic fracturing fluids and lab studies showing oil-wet and water-wet pore systems acting independently of each other, a slightly "outside of the box" reservoir simulation model was needed to mimic these physics. The proposed reservoir simulation methodology consists of multiple porosities and was developed to incorporate near-wellbore hydraulic fracture effects that are observed during lab testing. Combining this methodology with other lab measurements and a fully three-dimensional (3D) hydraulic fracture model, the number of "knobs" that need to be turned to get a good history match are reduced. Two examples will be presented in this paper showing how the proposed model better honors the physics of lab measurements and provides the user more flexibility during reservoir simulation, especially when buildup data is available. Reducing the uncertainty in these parameters has provided a workflow that helps minimize the multiple non-unique realizations during the history match process and provides a more reliable model for the engineer while reducing the amount of time needed to obtain a match.

The La Cira Infantas field is located in the Middle Magdalena basin in the Santander region of central Colombia. This oil-producing development is under secondary waterflood using five-spot and inverted seven-spot patterns. The reservoir has high vertical and horizontal heterogeneity, and there was concern about effectively draining the reservoir. A new hydraulic fracturing design was deployed for the first time in Colombia (and South America) to improve drainage and surveillance. With over 1200 producers and 500 injectors, the La Cira Infantas waterflood is well established. Waterflood surveillance indicated less-than-optimal recovery due to near-wellbore skin in the injectors and suspected poor height coverage. A novel proppant technology was incorporated into the fracture design allowing for consolidation of the proppant pack in the fracture with low bottomhole temperature and minimal stress on proppant, enabling long-term undamaged injectivity. This technology also incorporates an inert tracer into the proppant grains, which provides propped height determination after the treatment using a neutron log. This multi-faceted proppant technology was successfully deployed on one well, and additional wells are planned in 2020. This paper will first review the background of the field development including current completion techniques, along with the challenges being faced with the waterflood recovery. It will review the self-consolidating proppant technology and show the benefits of its use in this application to promote high-conductivity fractures and minimize damage to injectivity. The companion tracer technology will be presented along with plans to perform neutron logging and identify propped fracture height. This information can be fed into fracture propagation models to determine the fracture geometry, which is then used for reservoir and waterflood surveillance analysis. The technique allows for meeting the goal to improve injectivity into both high-skin and low-permeability reservoirs. Although this proppant technology has been used in other frac pack applications, this is one of the first case histories of the technology being used on land for improving injectivity and waterflood coverage in Colombia. This paper will be useful for reservoir and completion engineers working on waterflood fields that contain vertically and horizontally heterogeneous formations, and wish to maintain undamaged injectivity, improve waterflood sweep efficiency, and monitor the proppant pack over time.

In conventional formations it has long been established that designing fracture treatments with improved near-wellbore conductivity generates improved production and economic returns. This is accomplished by pumping treatments with increased proppant concentration in the final stages (the traditional proppant ramp design), and in some cases by changing proppant size or type in the final stages to effect greater near-wellbore conductivity - commonly referred to as a "tail-in" design. These designs overcome the impacts of greater near-wellbore pressure loss during production caused by flow concentration in the near-wellbore region compared to distal parts of the fracture. For vertical wells and crosslinked fracture fluid treatments, the fluid flow and suspended proppant transport is effectively "piston" flow and it was a relatively straight forward matter to engineer the near-wellbore region with a tail-in of higher conductivity proppant. For unconventional reservoirs, with multi-stage horizontal completions using slickwater fluids, it has not been obvious how best to create this improved near-wellbore conductivity and most operators have employed a "one size fits all" strategy of pumping a single proppant type unless there was perhaps a need for flowback control in which case a resin coated proppant might be used as a tail-in. This paper reports the results of two projects to address the engineering of the near-wellbore fracture conductivity for horizontal well fracturing. Firstly, a series of laboratory tests were run in a 10 ft. × 20 ft. slot wall to visualize near-wellbore proppant duning and layering associated with both "lead-in" and "tail-in" designs. The impacts of these depositions were then quantified using a 3D hydraulic fracture / reservoir simulation code for a variety of stimulation designs in the Middle Bakken and Three Forks formations of the Williston Basin. The results of this work show that well stimulation treatments in liquid-rich unconventional formations would benefit from a combination of small (5 to 10%) lead-ins and tail-ins of high conductivity ceramic proppant. This minimizes the effects of radial flow convergence in the transverse fractures generated from the horizontal well and maximizes the economic benefit of the well stimulation. In addition to paying out the small cost increase in only 1 to 2 months, the proppant bands of higher conductivity ceramic help mitigate the effects of longer-term sand crushing and degradation on near-wellbore plugging and thus increases 3-year cumulative free cash flow and the Estimated Ultimate Recovery (EUR) of the well.

This paper investigates the effect of variable perforation configurations on proppant transport, settling, and distribution across different perforation clusters in multistage horizontal wells. The results are compared to other previously published data ( Ahmad and Miskimins, 2019 ) using different proppant sizes and densities. A 30-foot horizontal laboratory apparatus with three perforation clusters is used to simulate a multistage horizontal well. Low viscosity fresh water is used as the carrier fluid to transport the proppant. This research incorporates the influence of testing various injection rates and proppant concentrations on proppant transport of 100-mesh brown sand. Different perforation configurations are used to test the perforation effect on proppant transport using similar injection rates and proppant concentrations. A 200-gallon tank is used to mix the proppant before injecting the slurry mixture using a slurry pump. The apparatus also incorporates a variable frequency drive, a flow meter and pressure transducers. Sieve analysis is then conducted to identify the proppant distribution exiting from each cluster at different perforation configurations. It commonly assumed that the injected proppant is distributed evenly across the perforation clusters and that the distribution of fluid and proppant is identical. However, this research shows that this is not always the case. The results show uneven fluid and proppant distributions between clusters when altering the perforation configurations, injection rates, and proppant concentrations. Sieve analysis also shows different size distribution of the settled and exited sand through different clusters and individual perforations. Such information is beneficial to understanding transport in horizontal, multi-stage completions and how such impacts the overall treatment efficiency.

Drilling and completion operations introduce microbial contaminants into the reservoir via numerous pathways including drilling muds and hydraulic fracturing fluids. Uncontrolled microbial growth in the reservoir can lead to reduced flow and production rate of hydrocarbons due to accumulation of biofilm and plugging. Microbial contaminants can also lead to microbially influenced corrosion (MIC) of topside and downhole production equipment, causing undesirable impacts to capital spending and operational efficiency. As a mitigation strategy, biocides are often added to hydraulic fracturing fluids to control microorganisms which cause these operational issues. Oilfield service laboratories often receive water samples from the field to provide recommendations on the most optimum biocide use and concentration. The standard industry method ( NACE TM-0194 ) used for measuring biocide performance is based on a time-kill test in which water collected from the field is spiked with bacteria. Biocides are added at desired concentrations and samples are withdrawn to determine log reductions. Bacterial levels are often determined by ATP so results can be collected within minutes. A wide number of biocides are available for oil and gas operations. They differ primarily by mechanism of action, speed of kill, and interaction with other components of fracturing fluids. As the NACE method relies on rapid activity, misleading test results are often observed with preservative biocides which are intended for slow-release / long-term activity. Preservatives are utilized for extended protection of the well and reservoir after drilling and/or completion operations, not for the rapid reduction of microbes in a water sample. Therefore, as current methods are intended for rapid-kill biocides, novel methods are required to demonstrate the efficacy of preservatives. Methods were designed primarily to demonstrate efficacy of preservative treatment for waters used in hydraulic fracturing. Using culture-based methods, biocides were added to water samples that were incubated at elevated temperatures and challenged periodically. Glutaraldehyde was an effective preservative at 55 °C, providing antimicrobial efficacy for >7 days. 4,4-dimethyloxazolidine (DMO) was effective for 4 weeks or more, with improved efficacy at elevated temperature. The methods described in this work can differentiate rapid-kill from preservative biocides, be performed at a service company laboratory, and provide results within an "actionable" period (approximately 7-10 days) of time.

We use a high-quality dataset in the Bakken Shale to calibrate a numerical model to a complex and diverse set of parent/child observations. Two vertical wells (V1 and V2) were drilled 1000 ft and 1200 ft away from a legacy well with 10 years of production, H1. A DFIT was performed in the V1, followed by a 24 hour low-rate injection in the H1 (a microseismic depletion delineation, MDD, test). Subsequently, a small frac job was performed in the V1, followed by DFITs in the V1 and V2. The dataset yields a diversity of data to calibrate a numerical model: historical production of the H1, pressure response in the H1 from the MDD injection and the V1 fracture treatment, production rate uplift in the H1 following the V1 frac, microseismic, and pressure response during the three DFITs. The entire dataset was history matched in a single continuous simulation with a numerical simulator that fully integrates hydraulic fracture and reservoir simulation. The simulation was set up to closely match a geologic model that was built in prior work. The integrated simulation allows simulation of the fractures reopening around the H1 as a consequence of the MDD, the transport of proppant from the V1 to the H1 well, and the subsequent communication and poroelastic stress response. The Biot coefficient was calibrated to match the observed change in stress at the H1 well after ten years of depletion. The fracture toughness was calibrated to match the observed fracture geometry from the microseismic around the V1 well during fracturing. A proppant transport parameter called ‘maximum immobilized proppant’ was tuned to the production and DFIT data. The match to the V2 DFIT suggests that it is not directly in contact with the V1 fracture, even though the wells are relatively close together along fracture strike. The initial V1 DFIT suggests that it has, at most, weak contact with the H1. The second V1 DFIT, performed after the fracturing treatment, demonstrates communication with the H1, and consequently, depletion. The observations demonstrate that the H1 was able to produce from the previously undepleted rock around the V1, even though it was 1000 ft away. Overall, the results indicate that Bakken wells can achieve substantial (at least 1000 ft) effective half-length, that frac hits on parent wells in the Bakken do not necessarily result in production degradation and can even increase production, that the apparent Biot coefficient is relatively low (∼0.34), that the amount of proppant trapping due to localized screenout is relatively low (but nonzero), and this entire, complex dataset can be explained using a planar fracture modeling approach.

Limited entry is used in multistage fracturing to attempt to distribute fracture fluid among multiple perforation clusters evenly. As the slurry is pumped through perforations, the perforation holes can be eroded because of abrasion by the proppant, and therefore become enlarged, resulting in less effective limited entry and lower efficiency of the fracture treatment. Distributed Acoustic Sensing (DAS) is a method used for monitoring of fluid flow during hydraulic fracturing. By evaluating the changing DAS responses at perforation cluster locations during fracture pumping, DAS can be used to evaluate perforation erosion. DAS is a measurement of acoustic energy induced by fluid movement with fiber optic sensing cables. A raw acoustic signal recorded by the interrogator is transformed into an energy response (Frequency Band Energy), which is used for further interpretation of fluid volume distribution among perforated clusters on each stage of the fracturing treatment. Based on previous laboratory experiments and computational simulations, there is a correlation between the Frequency Band Energy and fluid flow rate. As the flow rate is a function of fluid velocity and perforation area (diameter of perforation), the same flow rate could be attained with a combination of different velocities and areas, leading to a non-unique solution when interpreting DAS measurements. We transferred the correlation into the relationship between velocity and Frequency Band Energy, using the perforation area as an additional parameter. It enforces avoiding non-unique solutions in the interpretation process. Perforation diameter is a function of erosion rate, which depends on the proppant concentration and velocity of fluid passing through the perforation. In order to connect correlation parameters with the diameter of perforations, computational simulations of fluid injection were conducted with different perforations geometries. Based on these simulations, a function that connects the area of perforation with a correlation parameter was obtained. It allows us to include the diameter of perforation in the analytical equation explicitly. The application of the enhanced correlation in the interpretation process leads to increased accuracy of the fluid distribution calculation. For each time step, the velocity of the fluid, the mass of proppant, and the diameter of the perforations are computed, allowing the calculation of the flow rate in each perforation cluster. Perforation erosion is included in the model. Examples using field data are presented in the paper.

Technology to interrogate perforations to quantify cluster efficiency in limited entry, plug and perf completions has improved in operational efficiency, image quality and quantity. The entire pipe wall of the lateral is now visually imaged, and the discovery of significant casing erosion damage caused by leaking frac plugs during stimulations is easily observable, often multiple times in the same well. The effect of a breached casing with significant erosion between stages could potentially divert proppant from the intended perforation targets leading to reduced cluster efficiency and uncertainty of proppant distribution results. Video images have been used for several years to evaluate proppant distribution. The recent introduction of array side-view camera technology now provides highly detailed images of the full 360 circumference of the wellbore over extended intervals. Image logging methods for unconventional wells have changed from capturing a limited number of images of individual perforations through a small ‘spy hole’ to a complete panoramic view of the entire wellbore. Perforations, connections and everything in between can be efficiently imaged and analysed. Enhanced processing methods have additionally improved visualization of results and allowed quantification of areas of interest with image-based dimensioning. Greatly enhanced borehole image coverage has allowed the discovery of unintended interactions that can be very detrimental to fracture treatments. Evidence of these unwanted effects that were previously difficult to diagnose are now uncovered during routine fracture diagnostics. Evidence includes Erosion at plug setting depths has been observed in a relatively high proportion of wells Multiple casing breaches have also been observed in some wells with as many as 35% of plug setting depths subject to this issue The areal extent of erosion at plugs has been measured in the range of 10% of the casing circumference up to 100% full parting While the exact effects on the fracture treatment of potentially large volumes of fluid and proppant being diverted away from their intended target has not yet been quantified the catastrophic effect on well integrity is very clear. Examples, analysis methods, results, primary conclusions, and other relevant findings are discussed in detail. The technology we discuss is undoubtedly helping raise awareness in the industry of the potential extent of this previously under-diagnosed issue. Increased awareness and improved understanding of the issue will lead operators to better equipment selection, enhanced procedures and ultimately more productive and profitable wells. Hydraulic fracture performance will improve while cases of compromised well integrity will decline.

In this paper, we present an integrated equation-of-state based compositional hydraulic fracturing and reservoir simulator. The goal of this research is to develop a general simulator that can simulate the lifecycle of wells, which includes hydraulic fracturing treatment using water-based or energized fracturing fluid, post-frac shut-in and flowback with fracture closure and proppant settling, primary production with proppant embedment and fluid reinjection in a multiple well pad. This simulator fully couples the reservoir, fracture, and wellbore domains with multiple physics in each domain. The rock deformation, porous flow and temperature change in the reservoir domain, fluid and proppant transport in the fracture domain, and wellbore slurry flow and fluid/proppant distribution among clusters are fully coupled together and solved fully implicitly using the Newton-Raphson method. The phase behavior of hydrocarbon phases is modeled using Peng-Robinson Equation-of-state. The fracture propagation is modeled by mesh topology change (dynamic remeshing and local refinement) and the propagation direction is evaluated using the stress intensity factors. This simulator has been fully parallelized using MPI. We show two applications of this simulator for lifecycle analysis in US unconventional oil reservoirs on frac-hits and CO 2 fracturing. In the first field application, we simulate a multi-well fracture diagnostics. We used the parent well to monitor the child well fracture growth. Child well fracture growth is correctly interpreted using the monitoring data. In the second field application, we perform lifecycle analysis of hydraulic fracturing treatment using hybrid CO 2 -slick water-crosslinked gel fracturing fluids and 100/30-50 mesh proppants and the following production phase from a well in the Bakken formation. We successfully match the complex surface treating pressure data from the field. We also successfully matched the cumulative production of oil, gas and water and explained the long-term CO 2 flowback phenomenon in the field. The novelty of this simulator comes from its unique modeling capability in the well lifecycle analysis. Fully coupled reservoir-fracture-wellbore framework allows accurate modeling of hydraulic fracture propagation in multiple well pads using multiple fracturing fluids and proppants, fracture closure during shut-in, primary production, refracturing, and pre-loading for parent well protection, and huff-n-puff improved oil recovery, all in one simulation. This simulator can be used as a reliable and efficient tool by operators in well lifecycle analysis.