Multi-fractured Wells Research Articles

Multidisciplinary Approach Underpins Development of Marginal Presalt Reservoir

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35273, “Sururu Central: Appraisal and Development Plan for a Marginal Presalt Reservoir,” by Thiago E.S. Azevedo, L.M. Hayashi, and Rodrigo R.S. Leal, SPE, Petrobras, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ The complete paper presents a multidisciplinary view of the evolution of the concept of a development project for the central area of the Sururu reservoir and the method applied to address challenges and propose solutions. The central area presents distinct characteristics from typical Brazilian presalt fields, with low permeabilities despite high porosity. Sururu Reservoir The reservoir is in the Santos Basin 230 km offshore Rio de Janeiro at water depths ranging from 2000 to 2300 m. The wildcat in the reservoir, 1-BRSA-618-RJS (1-RJS-656), is in the central area of the field, which is the main subject of the present work. The well exhibited reasonably high average porosity while presenting low permeabilities and low productivity when compared with other presalt wells. The second well, 3-BRSA-891A-RJS (3-RJS-682A), was drilled in 2011 in an area known as Iara Horst, also in the central area of the Sururu reservoir and presenting the same challenges faced by the wildcat. The third well, 3-BRSA-1181D-RJS (3-RJS-715D), was drilled in 2013 as a high-angle multifractured well consisting of an alternative architecture. Productivity results, however, were similar to the ones obtained in the previous wells. Investments were made in acquiring and reprocessing seismic data, ultimately leading to the drilling of the fourth well, 9-BRSA-1212-RJS (9-RJS-726). This well, in the Sururu Oeste area, revealed characteristics more similar to other Brazilian presalt fields and cleared the path to the later drilling of other Sururu Oeste wells. These good results paved the way for floating production, storage, and offloading (FPSO) vessel Petrobras 68 (P-68), which has produced both the Berbigão and Sururu reservoirs since November of 2019. P-68 is a 150,000-BOPD, 6-million std m³/d gas processing “replicant” FPSO that includes 10 producers (five from Berbigão and five from Sururu) and seven injectors (four in Berbigão and three in Sururu). However, the idea of developing an alternative for producing the Sururu Central area was never abandoned. In 2020, the ninth Sururu well and the fourth well in the central area, 9-SRR-5-RJS, was drilled near some of the main Sururu Central faults, aiming to test the existence of better reservoir quality or the presence of conductive in-situ fractures. The results from the well were in line with the results from the previous three wells drilled in the area, confirming the challenging nature of Sururu Central productivity. A suitable development strategy for the area was increasingly dependent on the attainment of long-term dynamic data that could support a modeling hypothesis for this unique presalt reservoir.

Rate Transient Analysis for Multi-Fractured Wells in Tight Gas Reservoirs Considering Multiple Nonlinear Flow Mechanisms

Making rate transient analysis (RTA) and formation evaluation for multi-fractured tight gas wells has always been a difficult problem. This is because the fluid flow in the formation has multiple nonlinear flow mechanisms, including gas-water two-phase flow, gas slippage, low-velocity non-Darcy flow, and stress-dependent permeability. In this paper, a novel RTA method is proposed for multi-fractured wells in tight gas reservoirs incorporating nonlinear flow mechanisms. The RTA method is based on an analytical model, which is modified from the classical trilinear flow model by considering all the nonlinear flow mechanisms. The concept of material balance time and normalized rate is used to process the production data for both water and gas phases. The techniques of approximate solutions in linear/bilinear flow regimes and type curve fitting are combined in the proposed RTA method. After that, the rate transient behaviors and influencing factors of multi-fractured tight gas wells are analyzed. A field case from Northwestern China is used to test the efficiency and practicability of the proposed RTA method. The results show that six flow regimes for both gas and water production performances are exhibited on the log-log plots of normalized production rate against material balance time. The rate transient responses are sensitive to the nonlinear flow mechanisms, and formation and fracture properties. The medium flow regimes are significantly affected by fracture number, fracture conductivity, fracture half-length, stress-dependent permeability, gas-water two-phase flow, and formation permeability, which should be considered in making RTA of fractured tight gas wells. The field case shows that both gas and water production performances can be well-fitted using the proposed RTA method. The major innovation of this paper is that a novel RTA method is proposed for fractured tight gas wells considering multiple nonlinear flow mechanisms, and it can be used to make reasonable formation and fracturing evaluations in the field.

Reservoir and Fracture Characterization for Enhanced Geothermal Systems: A Case Study Using Multifractured Wells at the Utah Frontier Observatory for Research in Geothermal Energy Site

Summary For enhanced geothermal systems (EGS), multistage hydraulic fracturing along a deviated or horizontal well is a key technology used to create a high-conductivity fracture network between injection and production wells in deep, low-permeability geothermal reservoirs. The purpose of the created fracture network is to allow for the efficient transfer of fluid, heated by the geothermal reservoir, from the injection to the production well; therefore, well spacing (between injection and production wells) and hydraulic fracturing must be designed not only to promote connectivity between well pairs but also to mitigate thermal short-circuiting and thermal breakthrough. Analysis of post-fracture pressure decay (PFPD) data measured after each stage of a hydraulic fracturing treatment can be used to provide critical reservoir and fracture parameters required for well and hydraulic fracturing design optimization; this method provides a low-cost alternative and complementary approach to in-situ observation techniques, such as core-through experiments, fiber optics, or image logs in offset wells. Until now, PFPD has primarily been applied to multifractured horizontal wells (MFHWs) completed in low-permeability hydrocarbon reservoirs. The goal of this study is therefore to develop a methodology to estimate fracture and reservoir parameters using stage-by-stage PFPD data associated with EGS projects. An analytical model is proposed herein to estimate fracturing fluid efficiency, fracture length, average fracture aperture, average fracture conductivity, and reservoir permeability for different possible fracture geometries in EGS reservoirs. PFPD data collected for three hydraulic fracture stages in the injection well at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) site were analyzed to demonstrate the practical application of the proposed method. The results of this study indicate that, due to the presence of natural fractures in the target (granitic) reservoir, the hydraulic fracturing treatment (using slickwater) in the openhole section resulted in low fracturing fluid efficiency and small hydraulic fractures. In contrast, hydraulic fracturing treatments conducted in the perforated casedhole wellbore resulted in higher fracturing fluid efficiency and created larger hydraulic fractures even with smaller injected volumes. The results of the PFPD analysis were confirmed using a Formation MicroScanner image log and microseismic data collected during each stage of hydraulic fracturing.

Potential production gains of multi-stage fractured wells in shale plays: sensitivity of well performance to changes in design parameters assessed with fast and accurate Gaussian solutions

Potential production gains of multi-stage fractured wells in shale plays: sensitivity of well performance to changes in design parameters assessed with fast and accurate Gaussian solutions

Quantifying micro-proppants crushing rate and evaluating propped micro-fractures

Micro-proppants used in reservoir stimulation to enable oil and gas recovery from tight hydrocarbon reservoirs can be delivered deeper with slick water and prop microfracture networks during hydraulic fracturing. The production of a multi-fractured well system depends on fracture permeability, which is ultimately a function of proppant strength and concentration. However, it is challenging to evaluate the performance of micro-proppants due to their tiny particle size. This paper proposed a practical method for assessing micro-proppant strength based on micro-proppant crushing rates and optimizing micro-proppant delivery to achieve effective concentrations in the pad fluid to prop up the micro-fractures more effectively. Micro-proppants undergo two crushing steps when transported in the fluid and when hydraulic fractures close. Under a pressure of 70 MPa, the crushing rate is 12%–25% of the hydraulic loading, and 42%–66% of the solid loading for three types of micro-proppants. The concentration of micro-proppants in the pad fluid should be higher than 0.9 lbm/gal to maintain economic permeability under high closure stress of 50 MPa. The numerical simulation results demonstrate that adding micro-proppants to the pad fluid will increase the effective propped fracture area, and the initial productivity and stable productivity increase by more than 40% and 20%, respectively. This study has a guiding value for selecting micro-proppants and the number of micro-proppants used in hydraulic fracturing.

A multi-fractured well performance model for unconventional reservoirs

Due to the ultra-low permeability of unconventional reservoirs, transient state prevails for a considerable period. Despite this, fracture interference can cause an apparent no-flow boundary. Consequently, the Duong's model, which was developed for transient-state period, yields unreliable estimates during the late-time period. In this paper, the Duong's model is modified to account for boundary effects caused by fracture interference and/or unstimulated reservoir regions that serve as no-flow boundaries. Specifically, an empirical correction function, which assumes an exponential decline, has been used as a “modifier” to extend the Duong's model to boundary-dominated flow period. The correction function ensures that during boundary-dominated flow period, an exponential-decline behaviour dominates. The proposed rate-decline model encompasses a gamma function, which converges at large times. Results show that a fractured-well production behaviour is characterised by a decaying power-law during early-time period and tends to exponential decline during late-time period. The results also suggest that although the conventional Duong's model gives good estimates during the transient-state period, it yields optimistic estimates during the boundary-dominated flow period. The proposed model gives a good match and estimates not only in the transient-state period, but also in the boundary-dominated flow period. A major advantage of the proposed model is that it converges to estimated ultimate recovery at large times without imposing any rate and time limits. A good agreement of the estimated ultimate recovery with analytical and semi-analytical models was obtained. Also, results suggest that the proposed model gives conservative estimates. The proposed model will be useful for analysing and predicting both the early- and late-time production performance of a multi-fractured well producing from an unconventional reservoir.

Formation damage simulation of a multi-fractured horizontal well in a tight gas/shale oil formation

Formation damage in drilling comes from drilling fluid invasion due to high differential pressure between a wellbore and the formation. This mechanism happens with fracture fluid invasion of multi-fractured horizontal wells in tight formations. Some multi-fractured wells show production rates and cumulative productions far lower than expected. Those damaged wells may sustain further impact such as well shutting due to unexpected events such as the COVID-19 outbreak and then experience a further reduction in cumulative production. This paper focuses on the root causes of formation damage of fractured wells and provides possible solutions to improve production. A simulation study was conducted using Computer Modelling Group software to simulate formation damage due to fracture fluid invasion and well shut-in. Simulation results revealed that the decrease in cumulative hydrocarbon production due to leak-off and shut-in of the simulated well could range from 20 to 41%, depending on different conditions. The results showed that the main causes are high critical water saturation of tight formations, low drawdown, and low residual proppant permeability under formation closure stress. The sensitivity analysis suggests two feasible solutions to mitigate formation damage: optimizing drawdown during production and optimized proppant pack permeability of the hydraulic fracturing process. Optimizing pressure drawdown is effective in fixing leak-off damage, but it does not mitigate shut-in damage. Formation damage due to shut-in should be prevented in advance by using an appropriate proppant permeability. These key findings enhance productivity and improve the economics of tight gas and shale oil formations.

Design and Analysis of Improved Swelling and Degradable Diverting Agent for Multistage Hydraulic Fracturing

Summary Fracturing fluid diversion plays a crucial role in maximizing the well productivity of multistage fractured wells. Proper sizing and material design of diverting agents are key elements to effectively bridge and plug perforations and fractures during treatment. In this study, we present an improved design for a water-soluble diverting agent that can cover a range of fracture widths. In addition, a wellbore flow model that predicts the swelling and dissolution behaviors of diverting agents flowing from the surface to the fractures was developed for field applications. Butenediol vinyl alcohol copolymer (BVOH), which has elastic and sticking properties in water, is used as a diverting agent. Cylindrical pellets and smaller sized powder, made from the polymer, were mixed to bridge and plug hydraulic fractures. BVOH diverting agents were evaluated for slit widths of 1–4 mm with different pellet geometries using a high-pressure and high-temperature filtration apparatus. The swelling and dissolution rates depend on many parameters such as the temperature, dissolution time, crystallinity degree, and geometry. In this study, empirical correlations that predict the swelling and dissolution rates of BVOH polymers for various formulations were developed and implemented in a wellbore flow model that simulates fluid flow and heat transfer during pumping operations. A theoretical case study of a multistage hydraulic fracturing treatment was also presented to demonstrate the applicability and effectiveness of the treatment. The filtration test results with various diverting agent designs indicate that the length and diameter of the pellets affect the performance and effectiveness of the bridging and plugging fracture-like slits. Moreover, an optimum pellet size exists for different slit sizes. With modified pellet size and diameter ratios, wider slits of 3–4 mm can be effectively plugged by diverting agents with reduced leakoff volumes. The swelling and dissolution models correlated well with the experimental data, considering the temperature, dissolution time, and crystallinity degree. The case studies presented in this study illustrate that the models can predict the time required for the diverting agents to dissolve under field conditions and determine whether the diverting agents pumped into the well provide sufficient conditions for diversion. Furthermore, the study results indicate that the pump rate and injection conditions before pumping the diverting agent are key controlling factors in determining the dynamic downhole temperatures and thus affect the time required for the degradation of the diverting agent. In addition, a field trial result is presented to demonstrate the effectiveness of the swellable, BVOH diverting agent at low downhole temperatures, and hydraulic fracturing treatment in the Permian Basin. Swelling diverting agents exhibit a more elastic behavior than existing particulate diverting agents. Swelling polymers are less abrasive and thus reduce the risk of equipment damage during preparation and pumping. The wellbore flow simulator developed in this study helps stimulation engineers optimize material types, particle-size distribution, and concentration of diverting agents for various field applications.

Fast-running model for high-volume hydraulic fracturing

We develop a rapid simulator of hydraulic fracture growth in complex geologic layered conditions and extensively drilled multistage fractured wells in a reservoir. The simulator allows running independent simulations for thousands hydraulic fractures within a minute on modern personal computers. The model is meshless and has a simplified rectangular fracture shape; however, coupling all conventional hydraulic fracture mechanics equations makes the model accurate enough. We demonstrate it via comparison with exact analytical solutions in limiting toughness-, viscosity-, and leakoff-dominated regimes, as well as via comparison with other commercial simulators on real field cases. Field validation of the model by temperature log measurements is also provided.To demonstrate the practical implications of the model for reservoir engineering, we show several examples of numerical simulations for a huge number of hydraulic fractures in a reservoir, which interact with each other due to the closeness of stimulated wells and perforation clusters. Rapid simulations allow obtaining the field-scale simulations of fracture growth in the range of a minute and efficiently building distributions of asymmetric fracture growth both in length and in height. We show that the stress shadow effect causes undesired outbreaks to adjacent gas- or water-saturated geological layers if the fracture placement in a reservoir is dense enough. Even small spatial misalignment of stages in the offset wells may result in changes of geometry of transverse fractures growing from neighbored wells. Vertical true vertical depths mismatch in offset wells; their deviations in the dip and azimuth angles are shown to cause the asymmetry of fracture growth as well, which hardly can be predicted in field development workflows without rigorous fracture simulations. Examples of longitudinal fracturing in horizontal wells demonstrate the strongest distortion of conventionally assumed lateral symmetry and height growth similarity of fractures created in one horizontal well. Our simulations also show that these results are affected by the viscosity of pumped fracturing fluids. The presented model of field-scale interactive fracture growth in a reservoir enables finding the best fracture placement characteristics and pumping schedule for the needs of field development with hundreds to thousands of fractures in a short time frame.

Production rate of multi-fractured wells modeled with Gaussian pressure transients

This study presents new pressure transient solutions, illustrated with some examples of the vast practical application potential. Gaussian pressure transients (GPT) are derived here to quantify the temporal and spatial propagation of instantaneous pressure changes in porous media, as initiated from cylindrical sources (vertical wells) and planar sources (hydraulic fractures). After solving the scalar pressure field in the reservoir space, and adequately accounting for the interference of the various pressure fronts by mathematical integration and superposition, the resulting pressure gradients solve for the velocity field in the reservoir space. Unique for GPT solutions is that the well rate, unlike in the traditional well-testing equations, does not appear as an input. Applying Darcy's Law, the fluid flux from the reservoir into the well and hydraulic fractures can be directly computed from the GPT solutions. The closed-form production-forecasting model can be implemented either in matrix-coded flow-visualizations of pressure depletion and flow paths for reservoir sections or in grid-less spreadsheet solutions to instantaneously generate production profiles for wells in any type of fluid injection/extraction project (water production, geothermal energy extraction, hydrocarbon production, and fluid disposal wells). Additionally, the Gaussian method also is suitable for physics-based decline curve analysis. The practical examples included in this study are for Eagle Ford shale oil and Marcellus dry gas wells. The hydraulic diffusivities are constrained by the field data, and range between 2.36 x10−10 and 3.48 x10−10 m2 s−1 for the Eagle Ford Formation; for the Marcellus the range is 3.64x10−9 to 5.67x10−8 m2 s−1. The breakthrough solution method of Gaussian pressure transients is placed in the context of past and present modeling approaches for shale plays developed with multi-fractured wells.

The paradox of increasing initial oil production but faster decline rates in fracking the Bakken Shale: Implications for long term productivity of tight oil plays

In the US, tight oil is the largest source of liquid hydrocarbons and has enabled the country to become the world's largest oil producer. The estimated ultimate recovery (EUR) and rate of production decline are key metrics in the evaluation of the future productivity of tight oil wells. We chose the Bakken Shale because of its high quality, publicly available data. Traditionally, well operators have estimated the EUR for each well from the initial production (IP), using empirical type curves to extrapolate to the ultimate production. From 2015 to 2018 the IP of the average Bakken well increased by approximately 50%. This increase resulted in claims by operators and in the academic literature that more intense hydraulic fracturing was increasing the average EUR of the Bakken play. At the same time, other observers claimed the wells declined much more rapidly than previous wells. This faster decline provided evidence for lower ultimate production from newer wells. The aim of this study was to understand the origin of these seemingly conflicting observations. A physics-based, scaling model was used to predict production from horizontal multi-stage fractured wells. The model for oil recovery is based on pressure diffusion through fractured porous media. The model assumes that the rock is incompressible, the permeability and oil saturation are constant, the water is incompressible, and the viscosity is slowly varying with space. The scaling model was applied to 13,444 wells. The EUR and terminal decline rate (TDR) were estimated from fitting production to our scaling model. Our study found that implementation of more intensive hydraulic fracturing resulted in higher IP and steeper terminal-production declines. Recently published results estimating the total production from the Bakken that include increased lifetime production commensurate with observed increases in average IP, significantly overestimate the long-term production potential of tight oil, both in the US and globally.

Transient Temperature Impact on Deep Reservoir Fracturing

Hydraulic fracturing enables the commercial development of unconventional resources in shales and tight formations. The conductivity and complexity of created fractures are critically dependent on the rheology of fracking fluid and the mechanics properties of rocks. Literatures show that both the rheology of fracturing fluid and fracture propagation dynamics are affected by the temperature of fracturing fluid. Neglecting the temperature transient behaviour may defeat the purpose of fracturing optimization during fracture initiation, propagation, and sand packing. The objective of this paper is to investigate the impact of temperature on fracturing design by studying the transient temperature behaviour across a complex wellbore using numerical modelling by coupling a finite difference heat transfer model with a dynamic fracture propagation model. The study results show that with the injection of cold fracturing fluid, hydraulic fracture propagation is decelerated, and production prediction is thus lessened compared with the case ignoring temperature effect. For multistage fractured wells, fracture geometry enlarges along the fluid flow direction in a horizontal segment. This potentially lowers the cost of hydraulic fracturing designs.

Horizontal Wells: Applications, Considerations, and Case Histories

This paper discusses many aspects of the application of horizontal wells for field development, starting with the basic question of why to opt to this technology. The different considerations to be taken into account when dealing with the technology are reviewed, including some inherent downsides like higher cost and operational complications. The main emphasis, however, is placed on practical reservoir engineering aspects, including well planning and performance, and the handling of horizontal wells in specific technical applications like well test
 analysis and numerical modeling.
 
 
 
 The theoretical basis and pertinent differences in physics and flow regimes around vertical and
 horizontal wells are discussed in the context, together with the inherent practical implications.
 Case histories and examples are presented for several successful applications worldwide that the author was involved in. In one case, a medium size field offshore Canada was developed with waterflood utilizing very few horizontal producers, with a set of horizontal and vertical water injectors. Detailed planning and intensive modeling, carried out by a team of engineers and geoscientists, led to a remarkably
 successful field development. In another case, few horizontals were used among many directional wells to develop a Mediterranean oil reservoir under aquifer and gas cap drives in an attempt to reduce coning problems, raising an opportunity to compare the long term performance of different geometry wells.
 A brief description is also presented to some advanced techniques and special cases of implementing horizontal wells such as thermal recovery (Steam-Assisted-Gravity-Drainage, or SAGD Process), multi-lateral wells, and multi-fractured wells, with discussion on these applications. Under favorable conditions, horizontal wells can also be used as an Improved Oil Recovery (IOR) tool in mature fields, an application that became very common in many super giant fields in the Arabian Gulf Area.

Optimization of Fracture Spacing and Well Spacing in Utica Shale Play Using Fast Analytical Flow-Cell Model (FCM) Calibrated with Numerical Reservoir Simulator

Recently, a flow-cell model (FCM) was specifically developed to quickly generate physics-based forecasts of production rates and estimated ultimate resources (EURs) for infill wells, as the basis for the estimation of proven undeveloped reserves. Such reserves estimations provide operators with key collateral for further field development with reserves-based loans. FCM has been verified in previous studies to accurately forecast production rates and EURs for both black oil and dry gas wells. This study aims to expand the application range of FCM to predict the production performance and EURs of wells planned in undeveloped acreage of the wet gas window. Forecasts of the well rates and EURs with FCM are compared with the performance predictions generated with an integrated reservoir simulator for multi-fractured wells, using detailed field data from the Utica Field Experiment. Results of FCM, with adjustment factors to account for wet gas compressibility effects, match closely with the numerical performance forecasts. The advantage of FCM is that it can run on a fast spreadsheet template. Once calibrated for wet gas wells by a numerical reservoir simulator accounting for compositional flow, FCM can forecast the performance of future wells when completion design parameters, such as fracture spacing and well spacing, are changed.

Improved DTS profiling model for horizontal gas wells completed with the open-hole multi-stage fracturing system

The fiber-optic distributed temperatrue sensor (DTS) has been used for flow profiling in horizontal multi-stage fractured wells, and several reservoir/wellbore coupled thermal models were developed. Although these theoretical models are applicable only to some specific scenarios, the industry has realized the great potential of DTS for production prediction in unconventional resources. This paper presents a DTS flow profiling case for a horizontal multi-stage fractured well in tight gas reservoirs with open-hole packer completion scenarios by applying a newly improved theoretical model.In this paper, we extended the conventional semi-analytical wellbore-fracture-reservoir coupled flow/thermal model which have been developed for cased, perforated, and multi-stage fractured wells, by considering the special feature of the openhole packer completion scenario. Since the formation fluid flows first through the fracture into the open-hole annular space between the formation and the production liner, and then flow along the annular space until meeting the frac port on the production pipe, a simulation sub-region was added for representing the open-hole annular space, which helps to understand the flow and heat transfer inside it. The presented model successfully simulated the two-segment flow regime caused by the simultaneous flow and heat transfer in the annular space and the production pipe. In each stage, the DTS temperature data possibly show double drops due to the Joule-Thompson cooling effects at the fractures and frac ports if their locations are not consistent.With the improved model, the synthetic cases were firstly used for studying the temperature characteristics and the effects of gas production rate and frac port location. Then the DTS monitoring data during a three-rate production test in a horizontal multi-stage fractured well in the Erdos Basin of China was simulated and analyzed. The open-hole packer completion was taken into account in the simulation and the gas rate prediction is satisfactory.

Productivity Improvement by Reperforation of Multistage-Fractured Wells in High-Pressure/High-Temperature Tight Gas Reservoirs: A Case History

SummaryProductivity of multistage-fractured gas wells is possibly degraded by conductivity impairments and non-Darcy flow during long-term production. Such degradations are pronounced by flow convergence to short perforated intervals, while it is challenging to identify degraded stages for remediation. Moreover, remedial actions can be expensive under a high-pressure/high-temperature (HP/HT) environment. A field case demonstrates successful application of reperforation as a cost-effective way to mitigate the flow convergence by prioritizing targets with multirate production-logging (PL) results.This work presents theoretical investigations using numerical simulations and field execution of reperforation for a well with six-stage fracturing treatments in a HP/HT volcanic gas reservoir onshore Japan. Apparent conductivity reduction was suspected during more than 15 years of production, and it was pronounced by non-Darcy flow effects associated with flow convergence to short perforated intervals. Multirate PL was used to identify impaired stages by quantifying the inflow-performance relationship (IPR) of each stage under transient flow-after-flow (FAF) testing. The impaired stages were reperforated, adding perforation intervals with wireline-conveyed perforators. Pressure-buildup (PBU) tests before and after the job and post-job PL were used to validate productivity improvements.Target zones for reperforations were identified and prioritized with results of the multirate PL conducted. The stage IPRs were drawn, and relatively large non-Darcy effects were identified in three stages by shapes of the IPRs and/or decreasing inflow contributions as the surface rate increased. Also, a temperature log showed steep temperature change at the bottom of the fourth stage; the fracture might propagate below the perforated interval. Ranges of production increment were estimated using a numerical model calibrated against the estimated stage IPRs. The estimated increment was in the range of 15 to 30% with the planned reperforation program, while its magnitude depended on the connection between new perforations and existing fractures. Afterward, the reperforation job was performed and the gas rate was confirmed to be increased by 26% with the same wellhead pressure after 1 month of production. The post-job PL was conducted 3 months after the reperforation. The well IPR was improved, implying reduction of the non-Darcy effects. Results of PBU tests also indicated reduction of skin factor. The stage IPRs were redrawn with the post-job PL, and they suggested clear improvements in two stages where screenout occurred during fracturing treatments and a stage where significant non-Darcy effect was suspected.The workflow and strategy in this paper can be applied for productivity restoration in a cost-effective way to multistage-fractured gas wells with short perforated intervals and impaired apparent conductivity during long-term production. Especially, the interpreted results suggested effectiveness of the proposed approach for productivity improvement in stages where screenout occurs during fracturing treatments. Moreover, lessons learned on the importance of careful test designs for PL were discussed because they are keys for success.

Pre-Drilling Production Forecasting of Parent and Child Wells Using a 2-Segment Decline Curve Analysis (DCA) Method Based on an Analytical Flow-Cell Model Scaled by a Single Type Well

This paper advances a practical tool for production forecasting, using a 2-segment Decline Curve Analysis (DCA) method, based on an analytical flow-cell model for multi-stage fractured shale wells. The flow-cell model uses a type well and can forecast the production rate and estimated ultimate recovery (EUR) of newly planned wells, accounting for changes in completion design (fracture spacing, height, half-length), total well length, and well spacing. The basic equations for the flow-cell model have been derived in two earlier papers, the first one dedicated to well forecasts with fracture down-spacing, the second one to well performance forecasts when inter-well spacing changes (and for wells drilled at different times, to account for parent-child well interaction). The present paper provides a practical workflow, introduces correction parameters to account for acreage quality and fracture treatment quality. Further adjustments to the flow-cell model based 2-segment DCA method are made after history matching field data and numerical reservoir simulations, which indicate that terminal decline is not exponential (b = 0) but hyperbolic (with 0 < b< 1). The timing for the onset of boundary dominated flow was also better constrained, using inputs from a reservoir simulator. The new 2-segment DCA method is applied to real field data from the Eagle Ford Formation. Among the major insights of our analyses are: (1) fracture down-spacing does not increase the long-term EUR, and (2) fracture down-spacing of real wells does not result in the rate increases predicted by either the flow-cell model based 2-segment DCA (or its matching reservoir simulations) with the assumed perfect fractures in the down-spaced well models. Our conclusion is that real wells with down-spaced fracture clusters, involving up to 5000 perforations, are unlikely to develop successful hydraulic fractures from each cluster. The fracture treatment quality factor (TQF) or failure rate (1-TQF) can be estimated by comparing the actual well performance with the well forecast based on the ideal well model (albeit flow-cell model or reservoir model, both history-matched on the type curve).

Impact of Flowback Dynamics on Fracture Conductivity

We aim at the development of an integrated modeling workflow for design and optimization of the flowback operation on a multistage fractured well within the concept of a managed pressure flowback, where the process is controlled by the choke on surface. In this paper, we focus on the impact of flowback dynamics on the conductivity of a single fracture in a multi-stage fractured completion. In our methodology, we employ a coupled modeling approach, where geomechanics phenomena are considered together in the framework of a global model for fluids displacement in a fracture. Among the solid mechanics effects considered are: proppant embedment with plastic deformations and creep of the rock near the fracture surface, proppant crushing, proppant pack compaction under the action of the closure stress with elastic compaction of proppant grains and frictional rearrangement of the grains, tensile rock failure at high filtration rates from the reservoir to the fracture (when drawdown pressure drop is excessively high). These geomechanics effects are implemented into the global fluid flow model in a propped fracture, which takes into account: displacement of fracturing fluid by oil, two-phase effects, suspension filtration with particle trapping and mobilization resulting in permeability damage, colmatation and skin buildup inside the fracture in the near-wellbore zone (where particles are mainly formation fines and crushed proppant).In our numerical experiments and parametric study, we made the following observations, structured by the discipline. Geomechanics: proppant pack compaction and proppant embedment due to rock plasticity and creep may reduce the fracture width by tens percent from the original (ideal) estimates, thus having a profound impact on fracture conductivity. Tensile rock failure in the near-wellbore zone may result in fracture being disconnected hydraulically from the wellbore. Fluid mechanics: colmatation of the proppant pack by small particles (formation fines or crushed proppant) may result in further conductivity decrease.We developed a modeling workflow for the transient fracture flowback to evaluate two scenarios of managed pressure flowback: "fastback" vs. "slowback". Based on the results of parametric studies, we provide evidence that a “smooth” scenario of piece-wise constant choke opening ("slowback") is preferable in terms of the preserved nondimensional fracture conductivity and increased cumulative well production, as compared to an “aggressive” scenario wtih rapid choke opening and dramatic decrease in bottomhole pressure. Implications for field operations are discussed along with modeling-based scenarios to be evaluated in a field-testing campaign. The novelty of our approach stems from the ambition to construct an integrated framework for a coupled geomechanics-fluid mechanics model of flowback, accurately equipped with proper submodels for each important physics phenomenon peculiar to the flowback operation. This effort will continue to scale up from a single fracture to the system of fractures connected to a near-horizontal wellbore with the choke on surface, with the ultimate goal to solve an inverse problem in terms of the optimum choke size sequence to provide the drawdown strategy for the managed pressure flowback.

Practical Solutions for Rate-Transient Analysis of Tight/Shale Reservoirs with Interfracture Induced Heterogeneity

Summary Production from previously uneconomic tight/shale formations has become feasible by constructing multifractured horizontal wells. Rate-transient analysis of these wells is commonly performed with the assumption of homogeneous-reservoir models, which might not be valid in reality. During hydraulic fracturing, secondary fractures might be formed in the reservoir. Because of the limited energy of hydraulic fracturing, the quality of secondary fractures decreases with the distance from the main fracture. This would negate the assumption of a homogeneous reservoir. In this paper, we present practical solutions that include reservoir heterogeneity in rate-transient analysis of multifractured wells. The solutions are developed for transient linear flow, which is a dominant-flow regime in many tight/shale reservoirs. In addition to forward solutions, inverse solutions are also developed that would ease the analysis procedure and reduce the uncertainty of estimation. The solutions are presented in simple formats and can be easily applied. We first developed the solutions such that they can be applied for any arbitrary permeability profile. We further considered special formats for the permeability/distance relationship and developed the relevant models. For a homogeneous system, the well-known square-root-of-time (time to the power of 0.5) plot is used. For the case of heterogeneity, however, the power of time should be greater than 0.5 and less than unity to produce a straight-line plot. We mathematically demonstrate this for a recognized format of the permeability/distance relationship. The presented solutions are verified with the numerical simulation of synthetic examples. Comparison of the results reveals the accuracy of the analytical solutions. Two field examples are also analyzed to indicate the practical applicability of the analytical solutions. The permeability/distance profiles for these field examples are derived using the inverse solutions.

Competitive propagation of multi-fractures and their control on multi-clustered fracturing of horizontal wells

For the issue of multi-fracture growth from horizontal multi-fractured wells, a new model of multiple fracture growth model was established based on the approximate solutions of interaction stresses among multi-fractures. The computation amount of the model was reduced because of using an approximate method, and the accuracy of the model was validated by the Implicit Level Set Algorithm, which is a benchmark simulator of multi-fracture propagation simulation. Then simulations about fracture length, fracture width and influx rate under different parameters based on the model show that perforation loss and interaction stress are two dominate factors controlling fluid partitioning into each fracture. Influenced by the compression effect exerted by the exterior fractures, inflow rate, fracture length and fracture width of the middle fractures are less than the exterior fractures, and the effect can be weakened by increasing fracture spacing. Decreasing perforation numbers and diameters, or using non-uniform perforation method can promote homogeneous growth of multiple fractures. The research provides a theoretical basis and reference for optimization of multi-fracture propagation.