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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 Uniformity of proppant distribution among multiple perforation clusters affects treatment efficiency in multistage fractured wells stimulated using the plug-and-perf technique. Multiple physical phenomena taking place in the well and perforation tunnels can cause uneven proppant distribution among multiple clusters. The problem has been studied in the recent years with experimental and computational fluid dynamics (CFD) methods, which provide useful insights but are impractical for routine designs. Simplified models that incorporated the proppant transport efficiency (PTE) correlation derived from the CFD results in a hydraulic fracture model have been also presented in literature. In this paper, we present a numerical model that simulates the transient proppant slurry flow in the wellbore, considering proppant transport and settling including bed formation, rate- and concentration-dependent pressure drop, PTE, and dynamic pressure coupling with the hydraulic fractures. The model is efficient and is designed to be an independent wellbore transport model so it can be integrated with any fracture models, including fully 3D and/or complex fracture network models, for practical design optimization. The model predictions are compared and found to agree with previously published studies. Parametric studies demonstrate sensitivity of proppant distribution to grain size, fluid viscosity, and pumping rate for fixed perforation designs. Analysis of the simulation results shows that the dominant cause of uneven proppant distribution is proppant inertia. Possible slurry stratification is less important, except for the cases with relatively low flow rates and near toe clusters. Accordingly, proppant distribution is less sensitive to perforation phasing than to the number of perforations in clusters. Alterations of the number of perforations per cluster within a stage enable achieving more even proppant distribution.
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 Fracture growth in layered formations with depth-dependent properties has been a topic of interest amongst researchers because of its critical influence on well performance. This paper revisits some of the existing height-growth models and discusses the evaluation process of a new and modified model developed after incorporating additional constraints.The net-pressure is the primary driver behind fracture propagation and the pressure distribution in the fracture plays an important role in vertical propagation, as it supplies the necessary energy for fracture advancement in the presence of opposing forces. The workflow adopted for this study included developing a preliminary model that solves a system of non-linear equations iteratively to arrive at fracture height versus net pressure mapping. The theoretical results were then compared to those available in the literature. The solution set was then extended to a 100-layer model after incorporating additional constraints using superposition techniques.The predicted outcomes were finally compared to the fracture height observations made in the field on several treatments. A reasonable agreement between model-predicted and observed height was observed when a comparison between the two was made, for most cases.The majority of these treatments were pumped in vertical wells, at low injection rates of up to 8.0 bbl/min (0.021 m/s) where net pressures were intentionally restricted to 250 psi (1.72 MPa) in order to prevent fracture rotation to the horizontal plane.The leak-off was minimal given the low permeability formations. In some cases, however, the pumping parameters and fluid imparted pressure distribution appeared to dominate. Overall, it was apparent that for a slowly advancing fracture front, which is the case in low injection rate treatments, the fracture height could be predicted with reasonable accuracy. This condition could also be met in high rate treatments pumped down multiple perforation clusters such as in horizontal wells, though fracture-height measurement may not be as straightforward as in vertical wells. The model developed under the current study is suitable for vertical wells where fracture treatments are pumped at low injection rates. The solid-mechanics solution that is presented here is independent of pumping parameters and can be readily implemented to assist in selection of critical design parameters prior to the job, with a wide range of applicability worldwide.
Summary Knowledge of fracture‐entry pressures or formation‐face pressures (FFPs) during acid‐fracturing treatments in real‐time mode can help in evaluating the effectiveness of the treatment and improve the decision‐making process during execution. In this paper, methods and tools used to generate FFPs in real‐time mode with the help of bottomhole‐pressure (BHP) data are discussed in detail. The horizontal wells selected for the study were drilled and completed in the North Sea with permanent BHP gauges that enabled constant monitoring of downhole pressures. The tool in discussion uses the combination of treatment data such as surface pressure, fluid density, injection rates, fluid type, wellbore details, and wellbore deviation, along with bottomhole‐gauge pressures, to calculate fracture‐inlet pressures just outside the casing at active perforation(s) depth. The tool performs the calculations in “live” mode during treatment execution and simultaneously generates a dynamic array of data that assists in “on‐the‐fly” evaluation and the decision‐making process. Several acid‐fracture treatments were analyzed using the tool and led to important conclusions related to fracture‐propagation modes, acid‐exposure times, and the effectiveness of given acid types. The results had a direct influence on the modification of treatment designs and pump schedules to optimize treatment outcomes.
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.
Vitthal, Sanjay (Shell Exploration & Production Co) | Chapylgin, Dmitry (Salym Petroleum Development) | Liu, Xin (Shell International Exploration and Production) | Khamadaliev, Damir (Salym Petroleum Development) | Fair, Phillip (Shell International Exploration and Production)
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 (
Dalamarinis, Panagiotis (Seismos) | Mueller, Paul (Mueller Energy Consulting) | Logan, Dale (NexTier Completion Solutions) | Glascock, Jason (NexTier Completion Solutions) | Broll, Stephen (VirTex Operating)
This paper assesses the effectiveness of combining hydraulic fracture monitoring (performed using borehole pressure-wave readings) with facies analysis based on mechanical specific energy (MSE) measurements. Beneficial applications include: 1) evaluation and optimization of completion designs, 2) design and measurement of diversion effectiveness and 3) placement of the frac as designed – while avoiding offset well communication – to increase estimated ultimate recovery (EUR). The evaluation was performed on a four-well dataset in the Eagle Ford shale.
For each well, facies analysis directed pre-job planning, resulting in various frac stage designs that were based on variations in MSE. The stages were monitored during the job, and, based on results, frac stage designs were modified in real time to optimize the next geomechanically similar stage. Far-field diversion was used on targeted stages to limit half-length growth in select wells. On all the wells, the number of clusters per stage was varied and the impact was monitored.
The first well was used as a baseline to provide direct, quantifiable correlations between the facies MSE and the measured fracture half-lengths. On subsequent wells, different treatment designs were executed, based on the varying MSE measurements, to obtain the desired half-length. The design changes included variations in the number of clusters per stage, far-field diversion strategies, pump rates, and proppant concentrations and quantities. Throughout the operation, frac performance was monitored continuously and pumping designs were optimized by varying parameters such as perforation clusters spacing, pump rate, diverter, acid volume, pad volume, slurry/proppant design, and volume per linear foot. The completion design of every stage was modified in real time, based on the performance of the fracture system. In each well, the first stages in each rock type served as control stages for calibration purposes. The result was the development of a uniform fracture system, in terms of both its extension as well as its near- and far-field conductivity. In a series of 204 stages across all four wells, the integration of MSE facies with fracture performance enabled real-time optimization of the fracture system, which delivered significant improvements in production performance, reservoir development, and reduced rate of depletion.
The combination of MSE analysis with borehole pressure-wave-based hydraulic fracture monitoring is a paradigm shift that has the potential to revolutionize how horizontal plays are developed. Employing these combined technologies can be used to drive each frac stage to meet frac half-length, height, and conductivity goals. The fit-for-purpose, noninvasive and scalable qualities of both technologies deliver strong cost efficiencies and can significantly increase EUR from the project acreage. At both the well and field levels, this combination of cost efficiency and customizability is critical to optimizing recovery from the field and increasing the economic life of industrialized shale completions.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Austin, Texas, USA, 20-22 July 2020. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract The publicly available multi-terabyte dataset of the Marcellus Shale Energy and Environmental Lab (MSEEL) consortium provides a unique opportunity to develop fracture models and analyze the effectiveness of the stimulation of a reservoir on a consistent base. Sonic, microresistivity image and production logs, microseismic data, and raw fiber optic measurements are examples of such data. Abundant core samples supplied demonstrate reservoir complexity and high density of natural fractures. The planar fracture model allows us to compare and contrast multiple stimulation strategies and propose engineered completions that cannot be done solely by data-driven approaches. Conclusions about stage spacing, stimulation design, wellbore placement, and stage isolation are shared. The workflow will be detailed to allow others to use, verify, and critique our findings using the same initial data.
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.