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Abstract In previous frac designs, proppant tracer logs revealed poor proppant distribution between clusters. In this study, various technologies were utilized to improve cluster efficiency, primarily focusing on selecting perforations in like-rock, adjusting perforation designs and the use of diverters. Effectiveness of the changes were analyzed using proppant tracer. This study consisted of a group of four wells completed sequentially. Sections of each well were divided into completion design groups characterized by different perforating methodologies. Perforation placement was primarily driven by RockMSE (Mechanical Specific Energy), a calculation derived from drilling data that relates to a rock's compressive strength. Additionally, the RockMSE values were compared alongside three different datasets: gamma ray collected while drilling, a calculation of stresses from accelerometer data placed at the bit, and Pulsed Neutron Cross Dipole Sonic log data. The results of this study showed strong indications that fluid flow is greatly affected by rock strength as mapped with the RockMSE, with fluid preferentially entering areas with low RockMSE. It was found that placing clusters in similar rock types yielded an improved fluid distribution. Additional improved fluid distribution was observed by adjusting hole diameter, number of perforations and pump rate.
Abstract A unique well-tracing design for three horizontally drilled wells is presented utilizing proppant tracers and water- and hydrocarbon-soluble tracers to evaluate multiple completion strategies. Results are combined to present an interpretation of them in the reservoir as a whole, where applicable, as well as on an individual well basis. The new approach consists of tracing the horizontal well(s) leaving unchanged segments along the wellbore to obtain relevant control group results not available otherwise. The application of the tracers throughout each wellbore was designed to mitigate or counterbalance variables out of the controllable completion engineering parameters such as heterogeneity along the wellbores, existing reservoir depletion, intra- and inter-well hydraulically driven interactions (frac hits) as well as to minimize any unloading and production biases. Completion strategies are provided, and all the evaluation methodologies are described in detail to permit readers to replicate the approach. One field case study with five horizontal wells is presented. Three infill wells were drilled between two primary wells of varying ages. All wells are shale oil wells with approximately 7,700 ft lateral sections. The recovery of each tracer is compared between the surfactant treated and untreated segments on each well and totalized to see how the petroleum reservoir system is performing. A complete project economic analysis was performed to determine the viability of a chemical additive (a production enhancement surfactant). Meticulous analysis and interpretation of the proppant image logs were performed to discern the cluster stimulation efficiency during the hydraulic fracturing treatments. Furthermore, comparisons of the cluster stimulation efficiency between the two mesh sizes of proppant pumped are also provided for each of the three new unconventional well completions. The most significant new findings are the surfactant effects on the wells’ production performance, and the impact the engineered perforations with tapered shots along the stages had on the stimulation efficiency. Both the right chemistry for the formation and higher cluster stimulation efficiencies are important because they can lead to increased well oil production. The novelty of this tracing design methodology rests in the ability to generate results with a statistically relevant sample size, therefore, increasing the confidence in the conclusions and course of action in future well completions.
Abstract Stage length and perforation cluster spacing are important design parameters for multi-stage hydraulic fracturing. This study aims to demonstrate that the interplay between subtle variations of the least principal stress (Shmin) with depth and the stress shadows induced by simultaneously propagating hydraulic fractures from multiple perforation clusters, primarily determines the propped and fractured area in the target formations. This principle is illustrated with the help of a case study in a prolific unconventional formation in the north eastern US, where the vertical stress variations are well characterized through discrete multi-depth stress measurements and actual stage design parameters used by the operator are known. At first, we show how the hydraulic fracture footprint and proppant distribution varies with a change in the vertical stress profile. The stress profile is shown to be a very important in determining the optimal vertical and lateral well spacing. The evolution of the stress shadow in the different layers is shown during the pumping as the fracture propagates across multiple layer boundaries. Subsequently, we demonstrate that by changing the magnitude of stress perturbations caused by the stress shadow effect, the distribution of propped area can be altered significantly. We use this method to determine the optimal cluster spacing keeping other design parameters constant such as flow rate, perforation diameter, etc. Simulations from selected cluster spacing realizations are run with high and low permeability scenarios to show the importance of correct matrix permeability inputs in determining the three-dimensional depletion profile and ultimate production. By varying the cluster spacing we show the hydraulic fracture propagation change from being solely stress layering driven to stress shadow influenced. The effect of stress shadow on the final fracture footprint is highly specific depending on the given stress layering and is thus case-dependent. This study demonstrates that knowledge of stress variations with depth and modeling are critical for optimizing stimulation efficiency.
Summary Heel‐dominated treatment distribution among multiple perforation clusters is frequently observed in plug-and-perforate (plug-and-perf) stages, causing small propped surface areas, suboptimal production, and unexpected fracture hits. A multifracture simulator with a novel wellbore‐fluid and proppant‐transport model is applied to quantify treatment distribution among multiple perforation clusters in a plug-and-perf operation. A simulation base case is set up on the basis of a field treatment design with four clusters. Simulation results show that the two toe‐side clusters screened out early in the treatment and the two heel‐side clusters were dominant. The simulated proppant placement is consistent with distributed‐acoustic‐sensing observations. The impact of different perforating strategies and pumping schedules on final treatment distribution is investigated. Two criteria are defined that quantify the proppant distribution and fracture area: the weighted average (WA) and standard deviation (SD) of the final fluid and proppant distribution, as well as the hydraulic surface area (HSA) and propped surface area (PSA) of the created fractures. An optimal plug-and-perf design is defined as one that minimizes the SD of the treatment distribution among perforation clusters, and maximizes the PSA. Both perforating strategy and pumping schedule are found to affect the final treatment distribution significantly, and uniform treatment distribution is shown to create more PSA. Having fewer perforations per cluster was found to promote uniform fluid and proppant placement. Other helpful strategies include reducing the number of perforations near the heel and using small, lightweight proppant. The stress shadow effect is accounted for using the displacement discontinuity method (DDM) and was found to play a smaller role than perforation friction and proppant inertia in most cases. An automated process is developed to optimize plug-and-perf completion design with multiple decision variables using a genetic algorithm (GA). Thirteen parameters are optimized simultaneously. The optimal design solution creates an almost even treatment distribution and more than doubles the PSA compared with the base case. The multifracture model presented in this paper provides a way to quantify fluid and proppant distribution for any perforating strategy and pumping schedule, and provides more insight into the physics relevant to plug-and-perf treatment distribution. The perforation and pumping schedule recommendations presented in this paper provide directional guidance for the design of fracturing jobs with balanced treatment distribution and large PSA.
ABSTRACT: This work offers a predictive model as a success-of-completion strategy (treatment) for a major successful shale play (Wolfcamp). The predictive model may be used to evaluate spacing between fracture clusters and the number of clusters and perforations, and to guide future selective optimum completion for the shale play. Many important parameters that control behavior of producing wells have been analyzed, including number of days on production; depth; fluids in bbl; horizontal well completion configurations; stages per well; fracture type; average water requirement; proppant type; fluid type; hydraulic horsepower (HHP) per stage; lb/ft2 of proppants per stage; number of stages, and lateral length (completed interval) of horizontal wells,.
We analyzed the performance of thousands of horizontal wells from the Wolfcamp formations for which data were available. The analysis of the data identified key parameters (depth, bbl. of fluids, type and amount of proppant, fluid type, and initial production (IP30)) in defining number of stages, clusters and perforations. Production performance from private and public data was used as a separate criterion to determine predictivity of the models.
Various datasets from Wolfcamp are investigated. The procedure for exploring the data can be used as a decision criterion in similar cases for number of clusters, perforations and clusters spacing and additional factors in optimum resource development. A multivariate linear regression predictive model is advised for number of fracture clusters, cluster spacing, and perforations. Testing of the models shows relatively good in-sample predictions using public data.
Hydraulic fracturing design is one of the key parameters driving the performance of horizontal wells in unconventional resources. The design process includes multiple parameters and metrics. The metrics are listed in Table 1, including completed interval of the horizontal well; number of perforations; clusters per stage; cluster spacing; fluids in bbls; fluid in gal/ft; proppant in lbs; concentration of the proppant in the fluid; average injection rate; pressure; fluid type, and proppant type and size, in addition to production metrics (e.g., Initial production, GOR, Yield, WCUT). Some of the metrics are currently available in the public database and others are usually obtained through private parties. The paper describes an attempt to better understand completion effectiveness in the Wolfcamp formation.
Abstract One of the most significant components of hydraulic fracturing modeling is the prediction of proppant transport in both the wellbore and fractures, as the resulting conductivity has a great impact on post treatment production. In multistage horizontal well treatments, the distribution of proppant between multiple perforation clusters has a substantial impact on treatment behaviors and results. If the proppant is not evenly distributed between the perforation clusters, the perforated intervals will not be equally stimulated. Only a few studies evaluating proppant transport in horizontal wellbores are found in the literature. This paper aims to investigate the parameters that have a large influence on the proppant settling in the wellbore and distribution of the proppants between perforation clusters, as well as providing insight into post-treatment flowback behaviors. The approach to this work uses a model of a horizontal wellbore with three perforation clusters at shot densities of 4 SPF with 90-degree phasing. Fresh water was used as a carrier fluid to transport the proppant in the horizontal pipe. Two different types of proppants, sand and ultra-light-weight ceramic, of varying mesh sizes were used. Two design parameters, injection rate and proppant concentration, have been varied throughout the experimental tests. The results from this work demonstrate that proppant settling velocity in the wellbore is different for each type of proppant. These differences are mainly due to the changes in the proppant concentration as well as the changes in the size and shape of proppant particles. The uneven proppant distribution between perforation clusters was mostly observed in cases where the density of proppnat was relatively high and at low flow rates. However, at high flow rates, the toe cluster received the largest amount of proppant. This occurs because the high flow rates near the first and second clusters prevent the proppant particles from turning into the perforation tunnels. The ultra-light weight ceramic shows the most even distribution between the perforation clusters since the density difference between the carrier fluid and the proppant particle is relatively low. The most significant finding is that the low viscosity fluid (fresh water) is not an effective transport system for larger particles with relatively high densities. The results obtained from this study can be used to improve the understanding of good practices of fracture stimulation flushing, as well as proppant distribution/deposition throughout the horizontal pipe during the fracture stimulation treatment and during flowback processes.
Weijers, Leen (Liberty Oilfield Services) | Wright, Chris (Liberty Oilfield Services) | Mayerhofer, Mike (Liberty Oilfield Services) | Pearson, Mark (Liberty Resources) | Griffin, Larry (Liberty Resources) | Weddle, Paul (Liberty Resources)
Abstract Hydraulic fracturing has been a part of oil & gas development in North America for seven decades. Hydraulic fracturing was first conducted in 1947. Commercial operations began in 1949. After over twenty years fracturing took a large step up in the late-1970s with its application to tight gas sand formations. The game changer that brought discussion of hydraulic fracturing to dinner tables, bars and sidelines of soccer games is the recent advances that enable commercial extraction of natural gas and oil directly from shale source rocks. Since the start of shale fracturing in the early-1990s, fracturing technology and the pressure pumping industry's efficiency in delivering fracturing services have changed almost beyond recognition. The result has been the world-changing Shale Revolution. Through researching industry databases, the authors have compiled an industry-wide review of North American hydraulic fracturing activity dating back to the first work done in the late 1940s. Yearly stage count in the 1950s through the early 1990s was 10,000 – 30,000 stages/year, while recent peak levels show a step change in activity aproaching 500,000 stages/year (Fig. 1). While the North American industry's fracturing horsepower grew about 10-fold between 2000 and 2018, yearly frac stage count grew 20-fold in North America and proppant mass pumped grew 40-fold. The authors show how the industry achieved a step-change in reducing service delivery cost through innovation and efficiency, allowing sustained economic development of unconventional resources at decreasing breakeven production costs. Technological changes, as assisted by a better understanding through frac diagnostics, integrated modeling and statistical analysis have enabled the large cost reduction to commercially produce a barrel of oil. As a result, shale frac designs have focused on higher intensity completions with tighter stage and cluster spacing, improved diversion through extreme limited entry perforation design and simultaneous and zipper frac'ing, increasing proppant mass per well, utilizing next-generation frac fluids to increase produced water recycling and using cheaper lower-quality proppant. At the same time, the environmental footprint of oil & gas production has been shrinking and will continue to do so as operational changes continue to make our industry a better neighbor, for example through faster well construction utilizing fewer pad locations, development of quiet fleets, greener frac chemistry, frac focus disclosure, etc. Together, oil and gas operators and their service providers have used technology & innovation to improve efficiencies and increase the overall daily pump time per frac crew. However, there is plenty of room for further improvements in technology and efficiency. We believe this is the first industry database of its kind covering hydraulic fracturing activity in the United States, going back to the 1940s. We hope this paper provides a unique perspective of how our industry has changed through the Shale Revolution.
Abstract Heel-dominated treatment distribution among multiple perforation clusters is frequently observed in plug-and-perf stages, causing small propped surface areas, suboptimal production, and unexpected frac-hits. A multi-fracture simulator with a novel wellbore fluid and proppant transport model is applied to quantify treatment distribution among multiple perforation clusters in a plug-and-perf operation. A simulation Base Case is set up based on a field treatment design with four clusters. Simulation results show that the two toe-side clusters screened out early in the treatment and the two heel-side clusters were dominant. The simulated proppant placement is consistent with DAS observations. The impact of different perforating strategies and pumping schedules on final treatment distribution is investigated. Two criteria are defined that quantify the proppant distribution and fracture area: the Weighted Average (WA) and Standard Deviation (SD) of the final fluid and proppant distribution, as well as the Hydraulic and Propped Surface Area (HSA and PSA) of the created fractures. An optimum plug-and-perf design is defined as one that minimizes the SD of the treatment distribution among perforation clusters and maximizes the PSA. Both perforating strategy and pumping schedule are found to affect the final treatment distribution significantly, and uniform treatment distribution is shown to create more PSA. Fewer perforations-per-cluster were found to promote uniform fluid and proppant placement. Other helpful strategies include reducing the number of perforations near the heel, using small, lightweight proppant and so on. The stress shadow effect is accounted for using the Displacement Discontinuity Method (DDM) and was found to play a smaller role than perforation friction and proppant inertia in most cases. An automated process is developed to optimize plug-and-perf completion design with multiple decision variables using a Genetic Algorithm. Thirteen parameters are optimized simultaneously. The optimal design solution creates an almost even treatment distribution and more than doubled the PSA compared to the Base Case. The multi-fracture model presented in this paper provides a way to quantify fluid and proppant distribution for any perforating strategy and pumping schedule and provides more insights of the physics relevant to plug-and-perf treatment distribution. The perforation and pumping schedule recommendations presented in this paper provide directional guidance to design a fracturing job of balanced treatment distribution and large propped surface area.
Abstract The success of shale development has inspired new technologies to economize the extensive fracturing treatments necessary to complete extremely low permeability commercial wells. While bi-wing fractures are typically achieved during conventional fracture stimulation applications, it is often necessary to generate a complex fracturing network for most formation types encountered in very low permeability unconventional wells. Therefore, for source shale formations, the emphasis is on connectivity to natural fractures to establish an adequate stimulated reservoir volume (SRV). This paper discusses a new approach where improved initial wellbore-to-formation connections can be achieved by creating extended large diameter vertical cavities from the lateral as an effective fracture initiation point. This provides improved connectivity to the stimulated reservoir network both during stimulation and production. Additionally, this paper discusses the unique mechanics of the new procedure to generate a large connected SRV (CSRV) in unconventional formations, the technique, and the resulting benefits in fracture stimulation of resource shales or in ultra low permeability sandstones or carbonates as well as coal reservoirs. This new approach is fairly easy to implement, can be applied with limited hydraulic horsepower availability, and the impact could be substantial.
Abstract UAE which has traditionally been an oil producing country is reassessing the nation's energy production strategy and are appraising alternate energy sources. A part of this strategy includes exploring and assessing the potential of their unconventional and tight gas reservoirs. In order produce gas at economic rates from these deep unconventional reservoirs hydraulic fracturing is a vital technology to unlock the reservoir potential and enable hydrocarbon flow to surface. The first onshore hydraulic fracturing treatment in UAE was a challenging operation since the target formation was never successfully fractured previously. The expected breakdown pressure, insitu stresses and pore pressure regimes were unknown. A robust workflow was put into place using global and regional experience. An integrated formation evaluation was conducted during drilling and logging the vertical wellbore in order to select target zones and perforating intervals. Triaxial testing and ultrasonic measurements were conducted on core samples from the treatment well to calibrate the Geomechanical model before the hydraulic fracture treatment execution. Detailed lab testing was carried out to assist fracturing fluid and proppant selection. Multiple hydraulic fracturing simulations were conducted to define the final stimulation treatment program. Evaluation of the target UAE unconventional gas reservoir during the drilling and evaluation phase indicated the formation possessed high static stiffness, highly laminated depositional environment, significant overpressure and high insitu horizontal stresses. These formation characteristics posed some challenges during the hydraulic fracturing design and execution. High fracturing treatment pressures and propellant based perforation charges were required to effectively breakdown the formation in order to place the proppant into the fracture during execution. The stimulated target zone showed good initial gas production post treatment execution, which met the primary objective of proving recoverable gas in place. The hydraulic fracturing lessons learned from this first onshore unconventional well will be applied to future exploration and appraisal wells to ensure stimulation success and hydrocarbon deliverability. Unlocking the large quantity of gas from these organic rich carbonate reservoirs will play a significant role in UAE hydrocarbon production strategy.