Design Optimization of Horizontal Wells With Multiple Hydraulic Fractures

Hydraulic fracturing is currently the completion of choice in most tight reservoirs; however, the ultimate performance of fractured wells is severely affected by the interfering effects inside the fracture and inter fractures. Previous simulation studies investigated the effects of well spacing and fracture length on well productivity in low-permeability oil and gas reservoirs. It was shown that the most important parameters for determining the optimum fracture length are the formation permeability and the stimulated reservoir volume. Although a number of studies have examined the performance of horizontal fractured wells and fracture geometry effect, fracture spacing and intersecting angles in vertical and horizontal wells should be further investigated. This study presents the results of a tight oil reservoir in the Bakken shale. Reservoir parameters considered include local rock stresses, rock compressibility, absolute and relative permeability, and porosity. The well-completion parameters included fracture length, height, width, conductivity, number and spacing between fractures, fracture intersecting angle, and cased vs. open-hole completion. Fracture modeling considered rigorous description of the hydraulic fracture properties and finite difference reservoir modeling. Economically attractive reserves recovery were modeled through multiple fracture placements in a 10,000 ft horizontal well. Numerical simulation showed that oil recovery increased between 8 to 15% while net present value (NPV) increased 8 to 24%, as the number of fractures increased. Based on the critical assumptions in the study (permeability, natural fracture distribution and stress orientation), an optimum number of fractures was identified. Open hole completions provided better performance in most cases, and recovery was greater for a higher number of contributing perpendicular vs. longitudinal fractures. The results of the study may hopefully be used to improve the understanding of the role of fracture geometry, spacing and open/cased-hole completion strategy to enhance operators optimum completion design.

At present, hundreds of horizontal wells have been drilled in Hassi Messaoud counting for about one fourth of the field's output. Among these, several wells are underperforming and could not yield the expected production. Vertical and areal permeability anisotropies, absence of natural fractures, severe heterogeneity, reservoir damage and wellbore instability are the main factors to blame for poor productivity. To address the problem of poor vertical communication and get past the near wellbore damage, hydraulic fracturing has been thought of as the best solution to improve productivity. This paper describes the candidate selection criteria, the design and execution of the first fracturing job to be carried in a horizontal well. A new openhole completion system is to be deployed in the horizontal section. The system uses a series of mechanical openhole packers that allow for stimulation in each desired interval. The use of mechanical packers provides positive mechanical diversion at high differential fracturing pressures. In this case the horizontal drain has been divided into six sections. Three of them have been hydraulically fractured while the remaining sections characterized by natural fractures are producing naturally by simply opening the frac port. The system has been designed, so the fracturing treatments along the horizontal wellbore can be pumped in one continuous operation, thus minimizing the associated risks and optimizing the efficiencies of both personnel and equipment needed to perform the work. In this case the pumping operation has been successfully performed in less than 48 hours with no operational issue. The first operation has proven the feasibility to set multiple hydraulic fractures in openhole horizontal wells in Hassi Messaoud field. The drastic production increase demonstrates how the multiple fractures allow improving the vertical and areal drainage of the reservoir for this type of wells. The article presents all the project phase from candidate selection, design to job execution. It also highlights the risks involved with regard to many aspects during the project. Finally, the paper summarizes some lessons learned and draws suggestions for prospective candidate wells. Introduction The Hassi Messaoud reservoir has been on stream since 1958. Currently, it produces about 65 Mm3/D of 45°API oil from a thick Cambro-Ordovician sandstone formation. The structure is a flattened anticline with a sequence of horts and grabbens contained by faults in a submeridian direction. The faults are generally oriented SSW to NNE and cross the entire reservoir. The depositional environment is fluvial at the bottom to marine at the top. The shaly sandstone contains silt interbeds which have a thickness between 0.2 and 0.4 m with a metric to kilometric lateral extension. The reservoir is naturally fractured in some parts because of tectonic activity. Fractures are either open or plugged with materials such as shale, silica, anhydrite, pyrite, and bitumen. The reservoir is subdivided into four distinct formations—Ri, Ra, R2, and R3—in addition to a zone of alternance with Ra-Ri and R2 being the main and secondary reservoirs respectively. The producing Ra-Ri is subdivided into six intervals: D5, D4, D3, D2, ID, and D1. The reservoir has a porosity ranging from 6 to 12 %. Overall, the permeability is low with a range from less than 1 to more than 100 md in open-fissures layers. The reservoir was initially undersaturated with an oil saturation of about 80%. The reservoir was subdivided into productive zones. Most zones are under miscible gas flooding. Five zones are under water injection. Up until 1995, the reservoir was developed using vertical wells. Along with matrix treatments, hydraulic fracturing is extensively used with more than 300 wells already treated to compensate for low permeability or to bypass nearby wellbore damage. Gaslift is used for production activation throughout the field.

Summary Horizontal wells with multiple hydraulic fractures have become a standard completion for the development of tight oil and gas reservoirs. Successful optimization of multiple-fracture design on horizontal wells began empirically in the Barnett Shale in the late 1990s (Steward 2013; Gertner 2013). More recently, research has focused on further improving fracturing performance by developing a model-derived optimum. Some researchers have focused on an economic optimum on the basis of multiple runs of an analytical or numerical model (Zhang et al. 2012; Saputelli et al. 2014). With such an approach, a new set of model runs is necessary to optimize the design each time the input parameters change significantly. Running multiple simulations for every optimization case might not always be practical. An alternative approach is to develop well-performance curves with dimensionless variables on the basis of the performance model. Such an approach was the basis for unified fracture design (UFD) for a single fracture in a vertical well (Economides et al. 2002). However, a similar systemized method to calculate the optimum for a horizontal well with multiple hydraulic fractures was missing. The objective of this study was to develop a rigorous and unified dimensionless optimization technique with type curves for the case of multiple transverse fractures in a horizontal well—an extension of UFD. The mathematical problem was solved in dimensionless variables. Multiple fractures include the proppant number (NP), penetration ratio (Ix), dimensionless conductivity (CfD), and aspect ratio (yeD) for each fracture, which is inversely proportional to the number of fractures. The direct boundary element (DBE) method was used to generate the dimensionless productivity index (JD) for a given range of these parameters (28,000 runs) for the pseudosteady-state case. Finally, total well JD was plotted as a function of the number of fractures for various NP. The effect of minimum fracture width was studied, and the optimization curves were adjusted for three cases of minimum fracture width. The provided dimensionless type curves can be used to identify the optimized number of fractures and their geometry for a given set of parameters, without running a more complicated numerical model multiple times. First, the proppant mass (and hence, NP) used for the fracture design can be selected on the basis of economic or other considerations. For this purpose, a relationship between total JD and NP, which accounts for the minimum fracture width requirement, was provided. Then, the optimal number of fractures can be calculated for a given NP using the generated type curves with minimum width constraints. The following observations were made during the study on the basis of the performed runs: For a given volume or proppant, NP, total JD for multiple fractures increases to an asymptote as the number of fractures increases. This asymptote represents a technical potential for multiple fractures and for high proppant numbers (NP≥100), with a technical potential of 3πNP. Below this asymptote, the more fractures that are created for a fixed NP, the larger the JD. In practice, minimum fracture width constrains the fracture geometry, and therefore maximum JD. For the case when 20/40 sand is used for multiple hydraulic fracturing of a 0.01-md formation with square total area, the optimal number of factures is approximately NP25. Application of horizontal drilling technology with multiple fractures assumes the availability of high proppant numbers. It was shown mathematically that the alternative low proppant numbers (NP≤20 for the previous case) are impractical for multiple fractures, because total JD cannot be significantly higher than JD for an optimized single fracture in the same area. This means that low formation permeability and/or high proppant volumes are needed for multiple fracture treatments.

In the last several years, the unconventional gas reservoirs development has grown tremendously. Most of these unconventional reservoirs have very low permeability and are not able to produce an economic flow rate without stimulation treatments. The common method to improve the production is by a horizontal well with multiple hydraulic fractures. Hydraulic fracturing is a stimulation practice to improve the permeability in order to obtain commercial production. Horizontal wells with multiple hydraulic fracture treatments have proven to be an effective method for development of unconventional reservoirs.;The objective of this study is to investigate the interpretation of pressure transient responses from horizontal wells with single and multiple hydraulic fractures using the commercial reservoir simulator. In addition, the research will focus on identifying the impact of the reservoir and fracture properties on the flow regimes of a horizontal well producing from the low permeability reservoirs.;The different flow regimes appear during horizontal-well transient flow. However, the existence of these flow regimes is closely associated with the dimensions of the half length of the fracture, fracture permeability, drainage area, horizontal well length, etc. Hence, it is common that some flow regimes are not present.;The impact of some of the reservoir parameters was analyzed. Drainage area, horizontal well length and reservoir permeability were found to have an impact on flow regimes. In addition to the reservoir parameters, a range of hydraulic fracture parameters was studied. The number of hydraulic fracture, fracture width and fracture half-length were found to have an impact on flow regimes. Fracture permeability and fracture porosity have no major impact on flow regimes.

Numerous papers have been published in recent years on the subject of optimization of multiple transverse fractures in horizontal wells (for instance Saputelli et al., 2014). These studies usually focus on searching for an economical optimum based on multiple runs of 3D or 2D numerical simulator, each for certain fixed properties of hydraulic fractures. What we found missing is a systemized approach to calculate a solution to this problem. The objective of this study is to develop a systemized, rigorous mathematical and unified approach to the design of multiple transverse fractures in horizontal well – an extension of Unified Fracture Design (UFD).This paper provides a rigorous methodology to optimize the number of fractures (and consequently, fracture geometry) for a given amount of proppant. We follow the UFD concepts and solve our problem in dimensionless variables. For the case of multiple fractures these are: Proppant Number (NP), Penetration Ratio (Ix), Dimensionless Conductivity (CfD) and Aspect Ratio (yeD) for each fracture, which is inversely proportional to the number of fractures. We used the Direct Boundary Element method to generate the Dimensionless Productivity Index (JD) for a given range of these parameters (28,000 runs) for the Pseudo-Steady state case. Finally we plot total JD as a function of the number of fractures for various NP, which allows optimization. In addition, we generate minimum width curves for various proppants, which represent a practical constraint.Based on our study we found the following:For a given volume or proppant, NP, total JD for multiple fractures increases to an asymptote as the number of fractures increases. This asymptote represents a technical potential for multiple fractures and for high Proppant Numbers (NP ≥ 100) reaches a technical potential of 3πNP. Below this asymptote, the more fractures that are created for a fixed NP the larger the JD In practice however, there's a minimum fracture width (3 proppant grains), which constrains the fracture geometry and therefore maximum JD. It was shown, that for the case when 20/40 sand is used for multiple hydraulic fracturing of 0.01md formation with square total area, optimal number of factures reduces to approximately Np25. Application of horizontal drilling technology with multiple fractures assumes availability of high Proppant Numbers. We show mathematically that the alternative low Proppant Numbers (NP ≤ 20 for the case in p.3) are impractical for multiple fractures because total JD cannot be significantly higher than JD for optimized single fracture in the same area. In practice this means low formation permeability and/or high proppant volumes are necessary for multiple fracture treatments. Our work shows the methodology to determine optimum geometry and required volume to perform multifracture treatments. Total proppant mass (and hence, NP) used for the fracture design must be selected based on economic considerations. For this purpose we constructed a relationship between total JD and the NP, which accounts for the minimum fracture width requirement.Our paper presents a mathematically rigorous, systematic and comprehensive approach to the selection of optimal number of transverse hydraulic fractures in a horizontal well. Using the relationship between Proppant Number and maximum practical JD, the proppant mass should be selected for the treatment. Then, based on the formation and proppant permeability, the maximum number of fractures should be calculated for a given NP using the generated type curves and minimum width restriction.

PreviousNext No AccessUnconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013Determining the Contributing Reservoir Volume from Hydraulically Fractured Horizontal Wells in the Wolfcamp Formation in the Midland BasinAuthors: Mickey FriedrichMike MillikenMickey FriedrichPioneer Natural ResourcesSearch for more papers by this author and Mike MillikenPioneer Natural ResourcesSearch for more papers by this authorhttps://doi.org/10.1190/urtec2013-149 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract URTeC 1582170 This paper provides a methodology that is practical and logical in its approach to provide answers involving the evaluation and development of unconventional reservoirs. Multiple sources of data are analyzed to estimate the effectively stimulated volume of reservoir for horizontal wells in the Wolfcamp formation in the Midland Basin of west Texas. Estimating this volume is critical in determining optimum spacing and stacking of horizontal wellbores in unconventional reservoirs. Stimulated Reservoir Volume (SRV), as determined from microseismic, locates seismic events due to rock failure but does not necessarily represent the reservoir volume contributing to production. The reduced volume contributing to production is defined as the Contributing Reservoir Volume (CRV). This paper presents a workflow of using three methods - interpreted microseismic, proppant material balance, and calibrated hydraulic fracture modeling - to collectively estimate the CRV in hydraulically fractured horizontal Wolfcamp wells. Microseismic data is interpreted both by applying a discount factor based on industry studies and by analyzing locations and concentrations of events. Then a method of proppant material balance is used to estimate the maximum propped dimensions based on the mass of sand that is placed in each cluster of perforations. Finally, a calibrated geomechanical hydraulic fracturing model is used to model the CRV of 25 wells drilled in the Wolfcamp throughout the study area. Keywords: horizontal wells, fractures, unconventional, stacking, modelingPermalink: https://doi.org/10.1190/urtec2013-149FiguresReferencesRelatedDetailsCited ByA mathematical model for estimating effective stimulated reservoir volume24 November 2021 | Journal of Petroleum Exploration and Production Technology, Vol. 12, No. 7Analysis of Mancos Shale gas production scenarios under various stress mechanisms24 August 2021 | Arabian Journal of Geosciences, Vol. 14, No. 18A Review of Flow Mechanism and Inversion Methods of Fracture Network in Shale Gas ReservoirsGeofluids, Vol. 2021Production Interference of Hydraulically Fractured Hydrocarbon Wells: New Tools for Optimization of Productivity and Economic Performance of Parent and Child Wells3 June 2019Unconventional Reservoir Geomechanics14 June 2019 | , Vol. 1Surmounting Paucity of Data in Hydraulic Fracture Designs: Case Studies From the Permian Basin23 April 2018Case Study for Effective Stimulated Reservoir Volume Identification in Unconventional ReservoirsJournal of the Korean Society of Mineral and Energy Resources Engineers, Vol. 55, No. 2PKN Solution Revisit: 3-D Hydraulic Fracture Size and Stress Anisotropy Effects24 October 2017 | Rock Mechanics and Rock Engineering, Vol. 51, No. 2Performance-based fractal fracture model for complex fracture network simulation22 December 2017 | Petroleum Science, Vol. 15, No. 1Method of Characterization of Complex Fracture Network with Combination of Microseismic using Fractal theory17 October 2017Case History - Continued Diagnostic Technology Integration with Completions in Horizontal Wolfcamp Shale Wells in the Delaware Basin9 October 2017Midland Basin Wolfcamp Shale: Completions Observations and Lateral Length OptimizationKyle M. Richter12 September 2017Application of the fractal geometry theory on fracture network simulation23 July 2016 | Journal of Petroleum Exploration and Production Technology, Vol. 7, No. 2Deciphering Dynamic Fracture Systems through Multiple Monitoring Wells with Permanent Downhole Gauges in the Midland BasinYula Tang, Baosheng Liang, and Leif Larsen3 August 2016Understanding Wolfcamp Well Performance - A Workflow to Describe the Relationship between Well Spacing and EURJared Pettegrew*, Jiale Qiu, and Lang Zhan3 August 2016Application of Real-Time Bottom-Hole Pressure to Improve Field Development Strategies in the Midland Basin Wolfcamp ShaleKyle D. Scott*, Wei-Chun Chu, and Raymond W. Flumerfelt12 August 2015The role of hydraulic fracture geometry and conductivity profile, unpropped zone conductivity and fracturing fluid flowback on production performance of shale oil wellsJournal of Unconventional Oil and Gas Resources, Vol. 9Application of Real-Time Bottom-Hole Pressure to Improve Field Development Strategies in the Midland Basin Wolfcamp Shale4 August 2015Proper Inclusion of Hydraulic Fracture and Unpropped Zone Conductivity and Fracturing Fluid Flowback in Single Shale Oil Well Simulation17 April 2014Well-Spacing Study to Develop Stacked Tight Oil Pay in Midland Basin1 April 2014Estimation of Stimulated Reservoir Volume Using the Concept of Shale Capacity and its Validation with Microseismic and Well Performance25 February 2014 Unconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013ISSN (online):2159-6832Copyright: 2013 Pages: 1229 publication data© 2013 Published in electronic format with permission by the Society of Exploration Geophysicists, American Association of Petroleum Geologists, and Society of Petroleum EngineersPublisher:Unconventional Resources Technology ConferenceSociety of Exploration Geophysicists HistoryPublished: 26 Sep 2013 CITATION INFORMATION Mickey Friedrich and Mike Milliken, (2013), "Determining the Contributing Reservoir Volume from Hydraulically Fractured Horizontal Wells in the Wolfcamp Formation in the Midland Basin," SEG Global Meeting Abstracts : 1461-1468. https://doi.org/10.1190/urtec2013-149 Plain-Language Summary Keywordshorizontal wellsfracturesunconventionalstackingmodelingPDF DownloadLoading ...

Numerical simulation of stress shadow in multiple cluster hydraulic fracturing in horizontal wells based on lattice modelling

We investigate the rate-transient behavior of multistage fractured horizontal wells in conventional and unconventional homogeneous and naturally fractured reservoirs, the latter of which can contain any spatial distribution of finite- or infinite-conductivity fractures of arbitrary length and orientation. The number and type of fractures (hydraulic or natural) intersecting the wellbore and self-intersecting is unlimited. We show that there are many factors that dominate the ratetransient behavior of horizontal wells intersected by multiple hydraulic fractures in naturally fractured reservoirs, such as fracture conductivity, length, and distribution, as well as whether or not fractures intersect the wellbore. It is shown that the magnitude of the fracture conductivity is one of the most important parameters that affects the production performance of multistage fractured horizontal wells. It is also shown that, as the space increases between hydraulic and natural fractures intersecting a horizontal well, the fracture pseudosteady-state flow regime tends to disappear. Using the pressure and flow rate equivalency principle, we show that a production rate and/or cumulative production data set can be transformed into an equivalent pressure or pressure derivative data set. This is also very important for unconventional gas and oil reservoirs, where the boundary-dominated pseudosteady-state flow regime takes years to develop. A new technique is presented for determining stimulated reservoir volume (SRV) and production forecasting. It is shown that rate derivatives exhibit unusual behavior, from which system identification and flow regime analysis become impossible. The material balance time does not totally correct the unusual behavior of the rate derivative. However, the deconvolved pressure of the cumulative production derivatives behave like pressure derivatives.

Development of tight or low permeability reservoirs (e.g. Bakken formation) commences to reveal its potential and significance and expected to become even more essential in the future. The Canadian Bakken has been produced for over 40 years. At present, the combination of horizontal well drilling and the new multi-stage fracturing and completion technologies has been the key to economically unlocking the vast reserves of the Bakken formation. Parametric studies of fracture geometry on well productivity and oil recovery are essential for a successful hydraulic fracturing stimulation treatment. In this paper, we will investigate the best hydraulic fracturing scenario for Bakken formation and the effects of fracture geometries on oil recovery. More specifically, a geological model is firstly built using typical fluid and rock properties in Bakken formation; the horizontal wells with multistage hydraulic fractures will then be modeled using local grid refinement (LGR) and history matched based on the field production data. Various fracture treatment designs are evaluated, which include the investigation of various fracture spacing, lengths, and fracture locations on the horizontal wells. The results of this study show that, employing multistage hydraulic fracturing along horizontal wells can significantly improve oil recovery in Bakken formation. Compared to fracture length, fracture spaces or fracture numbers have greater impacts on oil recovery. More importantly, for the same fractured volume in the reservoir (i.e., the same usage of proppant and fracturing fluid), fractures with longer and smaller fracture numbers lead to a similar oil recovery compared to shorter but larger fracture numbers along the horizontal well laterals.

Drilling horizontal wells to accelerate production and increase recovery efficiency of oil and gas has now become common. With the increasing number of wells, transient well tests have been conducted in many wells with different geological settings. In this paper, we present a number of analytical models for horizontal wells with multiple fractures in homogeneous and laterally composite reservoirs. These solutions are applicable to finite-conductivity transverse fractures, and infinite-conductivity transverse and longitudinal fractures. They may also be used for the fractured reservoirs where the wellbore intersects with multiple fractures. We examine the pressure behavior of horizontal wells with single and multiple fractures in homogeneous systems. It is shown that the wellbore cannot be neglected in the modeling of horizontal wells with fractures unless the fracture conductivity is high. If the fracture permeability (conductivity) variations in different zones are moderate, compared to the formation permeability, the multiple fractures have almost no effect on the pressure behavior of the system; the horizontal well dominates the system's pressure behavior. If the conductivities are high, the intersected fractures will dominate the behavior of the system at early times. It is also shown that multiple finite- and infinite-conductivity transverse fractures may exhibit multiple linear flow regimes before the onset of the first horizontal well radial flow regime.

The impacts of the fluid type and stress shadow on proppant transport during hydraulic fracturing in a Marcellus shale horizontal well with multiple hydraulic fracture stages were investigated. The available data from a Marcellus Shale horizontal well were utilized to determine the hydraulic fracture properties and to develop a reservoir model. The reliability of the model was confirmed by the close agreement between the predicted production by the model and the well production data. The impact of fluid type and stage spacing on proppant transport during hydraulic fracturing and gas production from Marcellus shale horizontal well were then investigated by employing the reservoir models. Slickwater, compared to crosslinked gels and high viscosity friction reducers (HVFRs), is more efficient in horizontal Marcellus shale wells that are fractured in multiple stages. The application of the HVFRs and crosslinked gels resulted in fracture height growth out of the pay zone. While the use of slickwater directed all stimulation energy towards the pay zone and resulted in improved hydraulic fracture properties in the Marcellus shale and lead to high gas recovery. INTRODUCTION The advancements in horizontal drilling and hydraulic fracturing technologies have made shale production a reality for the past decade. With the technical and economical limitations posed by hydraulic fracturing operations in unconventional reservoirs, it is imperative to create an optimized fracturing design to achieve economic production. A number of treatment design considerations including the type of fluid, proppant type and size, and the additives must be evaluated to achieve successful well stimulation results. In general, proppant transport is dependent on proppant size, density, and type; fluid rheology; temperature changes; pumping rate, among others. The fracturing fluid should be compatible with the formation and promote the increase in the stimulated volume. In order to transport the proppants deep into the fracture, the fluid should be capable of keeping the proppants suspended. With an inherent viscosity, fluid should be able to develop the necessary fracture width to accept proppants. Also, it should have low friction pressure loss and sufficient stability to retain its viscosity throughout the treatment and finally, it should be easy to remove after the treatment. The type of fluid used therefore has pronounced impact on the transport of proppants and the properties of the created hydraulic fracture and consequently the hydrocarbon production. Proppant selection is a contributing factor in the dimensions of a propagating fracture. The most prevalent hydraulic fracturing treatment fluids in shale formations is slickwater with no significant amount of thickening agent. The application of this low viscosity fluid system contradicts conventional fracturing theory. However, slickwater is the preferable fracturing fluid in shale because of its cost-effectiveness and low potential for damaging the shale. In addition, slickwater has the potential to prevent high fracture height growth leading to better fracture containment within the pay zone.

Multiple hydraulic fractures growth from a highly deviated well: A XFEM study

Accurate modeling of hydrocarbon production is a necessary, yet challenging step for economic exploitation of unconventional resources. One of the main challenges is to model flow to a horizontal well from a complex network of hydraulic and natural fractures. Many unconventional reservoirs comprise well-developed natural fracture networks with multiple orientations and complex hydraulic fracture patterns based on microseismic data. Conventional dual porosity and dual permeability models are not adequate for modeling these complex networks of natural and hydraulic fractures. Also, it is neither practical nor advantageous to model a large number of pre-existing fractures with a discrete fracture model. Therefore, an appropriate approach to model production from low-permeability reservoirs is to perform discrete fracture modeling for hydraulic fractures and employ a dual continuum approach for numerous natural fractures. We have developed a coupled dual continuum and discrete fracture method to simulate production from unconventional oil and gas reservoirs. Large-scale hydraulic fractures (macro-fractures) are modeled explicitly using a discrete fracture model, called EDFM, and numerous small-scale natural fractures (micro-fractures) are modeled using a dual continuum approach. The hybrid model includes three domains: matrix, discrete-fracture, and continuum-fracture domains. A systematic approach is devised to calculate transport parameters between all three domains. Moreover, EDFM allows for not only transverse and longitudinal hydraulic fractures but also macro-fractures of any orientation. Thus, the coupled model provides an effective and reliable environment to improve stimulation designs and completion strategies. We present several examples in this study to show the applicability, robustness, and performance of the hybrid method for the simulation of unconventional oil and gas reservoirs. We examine multi-stage hydraulic fractures with multiple configurations in the presence of numerous pre-existing fractures. Simulations show a noticeable contribution from natural fracture networks on total production. Furthermore, for the tight oil reservoir examined in this study, the stimulation scheme with longer hydraulic fractures improves cumulative oil production compared to the scheme with larger number of shorter hydraulic fractures. We also examine production from a tight gas reservoir wherein hydraulic fractures partially penetrate the formation height. Simulations indicate that inefficient fracture treatment can result in significant loss of production.

Effective matrix acidizing in Kuwait's horizontal openhole wells is a real challenge. Reservoir heterogeneity and the length of the horizontal wells make acid placement and diversion difficult, particularly in high water-cut wells in which bottom water has broken through high permeability streaks or natural fractures. Furthermore, acid penetration is limited by the large surface area of the horizontal wellbore and is exacerbated by the relatively small injection rate imposed by the use of coiled tubing. To make matters worse, formation damage in horizontal wells is usually deep due to long exposure times.This paper discusses the application of a new viscoelastic surfactant-based, self-diverting acid system for stimulation of more than 20 horizontal openhole wells in carbonate reservoirs in Kuwait. The application also deployed a new non-particulate material that forms a highly viscous plug when it contacts water, and degrades when mixed with oil in the formation. The new fluid system is pumped prior to the acid treatment to effectively prevent the acid from stimulating high water saturation sections.The field results show significant improvement on post stimulation production owing to effective diversion and water production control, compared with wells in which a conventional polymer diversion technique was used in the past with no consideration of high water cut cases. The new technique has been selected as the standard stimulation practice in most horizontal openhole carbonate wells in Kuwait.

The number of horizontally drilled wells has continued to increase in the past few years. Nearly all of these well s have been completed as "drainholes" with slotted or perforated liner and without a cement sheath. The majority of these have been successful in their designed intent. Hydraulic fracturing treatments have been performed on a relatively small number of these wells. To be effectively fracture stimulated, a horizontally drilled well must be cased and cemented through the horizontal producing section of the well. Casing and cementing the horizontal section allows fracture initiation points to be controlled in placing multiple fractures. In situ stresses greatly influence the potential effectiveness of any fracturing treatment procedure. The one factor which most directly affects horizontal wellbore fracturing is the least principal stress, which is at a right angle to the induced fracture. The direction of the horizontal segment of the borehole dictates whether or not the induced fracture will be parallel or at an angle to the borehole. The use of properly applied controlled entry techniques at several fracture initiation points will help allow equal placement of proppant or reactive fluids in one stimulation treatment. Ei ther fracturi ng wi th proppant or fracture acidizing can be used in the stimulation treatment. The potential economic benefit to be derived from a successful multiple entry fracturing treatment merits strong consideration be given to the development of fracturing techniques to help obtain maximum wellbore drainage. Subject paper explains techniques and methods to be used in creating and placing proppant and/or reactive fluids in each of the multiple fractures in a horizontally drilled well. Economic considerations of the simultaneous stimulation treatment procedure are presented and compared to a vertical well under similar conditions.