Successful Pinpoint Placement of Multiple Fractures in Highly Deviated Wells in Deepwater Offshore Brazil Fields (original) (raw)
SPE Drilling & Completion, 2007
Summary Cased cemented completions have not been the preferred horizon-tal-well completion method in offshore Brazil. Lower-cost solutions such as uncemented preperforated liners were often used in completing horizontal wells offshore and are usually very effective. Often, however, low production rates mean that stimulation treatments become necessary for many wells. The use of conventional stimulation technology has generally been ineffective for these completions, which posed a challenge for the operator to find an effective solution for continuing developments in some fields. These challenges included reevaluating the more expensive cased cemented completions to allow more effective options for future stimulation, as well as trying to find newer stimulation techniques that can be effective with lower-cost completions (noncemented liners). In the attempt to find an economical yet effective stimulation solution, the operator chose to implement a unique and relatively new hydrajet s...
SPE Western North American and Rocky Mountain Joint Meeting, 2014
The revolution of the multistage horizontal completions has made low-permeability laminated reservoirs a cost-effective business. The key to success relies on maximizing the surface area contacted, a process that requires an adequate stage isolation technique. From traditional "plug and perf" to efficient sliding sleeves, the application of a particular system is related to the number of fractures that can be propagated during a single treatment injection. This condition varies according to rock and reservoir properties, principal stresses, zonal isolation and stimulation design. This study introduces a methodology to build predictive, repeatable models that integrate reservoir characteristics (mineralogy, pore pressure, thickness) along with geomechanics (anisotropic Poisson's Ratio, Young's Modulus, and horizontal stresses) and fracture pressure diagnostics (pressure history match, near-wellbore pressure analysis) to predict the likelihood of propagating multiple...
Interaction of Multiple Hydraulic Fractures in Horizontal Wells
All Days, 2013
The use of multi-fracced horizontal well technology in unconventional gas and liquid rich reservoirs is one of the key reasons for the recent success in the exploitation of Unconventional Resources. These multiple fractures are placed in many stages along the horizontal well using diverse completion technologies. Yet, the understanding of fracture growth mechanics and the optimum fracture placement design methodology are still preliminary. Recent advances in computational mechanics and the development of appropriate stimulation modeling technology will further nurture innovation and press forward much needed optimization of the Completion and Stimulation technology in multi-fracced horizontal wells. This paper contains two key components. Firstly, an analytical model is used to highlight some of the salient features of multiple hydraulic fractures interaction. The advantage of an analytical model is that it provides immediate insights into the controlling parameters and steer furthe...
Competition Between Transverse And Axial Hydraulic Fractures In Horizontal Wells
SPE Hydraulic Fracturing Technology Conference, 2013
Most horizontal wells in unconventional reservoirs are drilled in the direction of the minimum stress. The preferred far-field fracture orientation thus favors hydraulic fractures transverse to the wellbore. The near-wellbore stress concentration, however, sometimes favors the initiation of fractures in a plane defined by the well axis. Transverse and axial hydraulic fractures can thus both initiate in some situations and cause significant near-wellbore tortuosity. We investigate the competition between these two types of fractures by comparing their energy requirement during hydraulic fracture initiation and propagation. First, we investigate the limiting cases of slow and fast pressurization where fluid flow and fracture mechanics uncouple. We then use recently developed numerical models for the initiation and propagation of hydraulic fractures from an open hole accounting for fluid flow in the newly created crack, wellbore stress concentration and injection system compressibility.
ACS Omega, 2020
Hydraulic fracturing is a stimulation process, most frequently used in tight and unconventional reservoirs for successful and economical hydrocarbon production. This study deals with the propagation behavior of induced hydraulic fractures (HFs) in naturally fractured formations within heterogeneous Middle Eastern tight gas reservoirs. Local sensitivity analysis was conducted for a Middle East candidate reservoir by varying fracture design parameters to investigate the fracture propagation behavior. After a comprehensive evaluation, a discrete fracture networkbased simulator was used to introduce multiple sets of natural fractures (NFs) into the model to further analyze their interactions. Furthermore, simplistic wellbore placement analysis was also conducted. It is observed that production in tight reservoirs is governed by the presence of NFs and their distribution. This investigation analyzes HF propagation behavior and its correlated effects in the presence of NFs. Further assessment in terms of varying fracture geometry, NF sets, wellbore placement, and their effects on the conductivity are also presented. The introduced NF sets further illustrate the significance of the NF properties in this assessment. Additionally, variations in well placement demonstrate how effective the treatment can be in the presence of complex NF sets when properly located. The study is unique as it is one of its kind based on field data within the Middle East region and offers an insight into the potential concerns that may assist future fracturing operations within the region. The outcomes from this research validate the significance of NF orientation and its subsequent effects on the final HF geometry and network. Additionally, it further highlights the criticality of well placement and design strategies during hydraulic fracturing treatment design. Results describe how a minor modification with respect to the well placement can significantly affect hydraulic fracturing operations and subsequently the productivity and feasibility.
International Journal of Chemical Engineering and Applications
Multiple deformation over geologic time leads to generation of natural fractures. In naturally fractured reservoirs (NFRs), there are sets of fractures favourably oriented to fail in shear under the present-day stress field. These fractures which are critically stressed or at the threshold of being critically stressed are more likely to create good fluid conduit and to be the producing fractures in the reservoir. Conversely, non-critically stressed fractures, despite of their extensive population, do not contribute much to the reservoir permeability. Thus, identification of the critically stressed fractures, their distribution and orientations, is imperative to optimize different stages of wellbore construction ranging from wellbore trajectory planning and placement, to stimulation strategy. In this study, a tight sandstone reservoir was brought as a case study to indicate how production optimization can be achieved by a careful analysis of fractures. To do this, a comprehensive analysis was done on Formation Micro Scanner (FMS) log to identify the direction of principal stresses and natural fractures. This was followed by a thorough geomechanical model associated with coulomb failure function (CFF) to identify critically stressed natural fractures. Consequently, an optimized wellbore orientation was proposed to have the best production from the tight reservoir. In addition, the feasibility of underbalanced drilling performance due to minimizing formation damage was examined. A sensitivity analysis was also performed at the end to analyse the mud pressure reqired for hydraulic fracture propagation in order to effectively enhance reservoir permeability regarding various wellbore deviation and azimuth chosen for the wellbore.
The economic feasibility of the exploitation of unconventional resources is highly dependent on the ability of the operator to maximize individual well productivity, making hydraulic fracture design and implementation the defining factor for a successful field development in most cases. Some unconventional reservoirs, as shallow coal bed methane and over-pressured oil and gas shale formations, commonly present the minimum principal stress in the vertical direction, resulting in the occurrence of horizontal hydraulic fractures. Models for the transient flow and pressure behavior of horizontal fractures emanating from vertical wells exist and clearly show distinct performance from those for vertical fractures. This suggests that the widely accepted unified fracture design (UFD) approach to maximize well productivity for vertical and horizontal wells with vertical hydraulic fractures cannot be used for horizontal fractures. Thereafter, the necessity for guidelines to model and design horizontal fractures becomes evident. This investigation begins by presenting a new set of equations for horizontal fracture design based on the UFD approach, which allows the direct calculation of fracture width, half-length and conductivity for a given proppant number. Later, a reservoir numerical simulator is used to model well productivity behavior for horizontal fractures in homogeneous formations, with or without vertical to horizontal permeability anisotropy and for different aspect ratios as a function of suitably-defined proppant number, dimensionless fracture conductivity, and fracture penetration index parameters. The findings of this work reveal a complex behavior for horizontal fractures that prohibits the extrapolation of previous generalizations between proppant number, penetration index and dimensionless fracture conductivity established for vertical fractures. For a number of scenarios, new relationships among these variables are provided to guide horizontal fracture design. Anisotropy and reservoir aspect ratio were also found to significantly impact fracture performance. Additionally, a set of multi-variable functions that permit the estimation of maximum achievable productivity index for the horizontal fracture has been fitted, based on commonly known reservoir parameters and the proppant number. This investigation provides a comprehensive framework to assist the design of optimal horizontal fracture geometry that maximizes productivity for a given mass of proppant.
Optimization of Fracture Treatment Design in a Vertical Well
Petroleum & Petrochemical Engineering Journal, 2023
This project focuses on designing a fracture treatment in a vertical well with the goal of optimizing its parameters to increase its productivity index. The project uses EFRAC 3.3.0.0 software to model and optimize the design of the fracture treatment. The project first compares and selects the optimum fracking fluid, followed by a completion design to choose the best parameters using the optimum fluid selected. The project then analyzes the impact of the number of perforations, perforation diameter, proppant size, injection rate, and duration for each stage on the overall design. The final optimized design includes slick water as the fracking fluid, with a perforation diameter of 0.45 inches, 10 perforations, 20/40 proppant size, 25 BPM injection rate, 15-25-30-minute duration time, and 0-2-4 lbm/gal proppant loading rate. This final design resulted in a productivity index of 6.01, dimensionless.
ARMA-CUPB Geothermal International Conference, 2019
Hydraulic fracturing is the most effective reservoir-stimulation techniques in the petroleum and geothermal industries. It is most suitable for wells in low and moderate permeability reservoirs that do not provide commercial production rates. Due to technical and economical limitations of hydraulic fracturing operations in unconventional reservoirs, geothermal systems, and block cave mining worldwide, an optimized hydraulic fracturing design is critical for successful stimulation operation. Fractures created require proppant to keep it open after injection has stopped. Furthermore, proppant transport and placement, proppant and frac-fluid compatibility, and optimum spacing are some of the challenges inhibiting successful hydraulic fracturing operations. Proppant transport depends on the particle size, proppant density, and the fluid viscosity. In this paper, we investigate the effects of proppant densities, fluid viscosities, and injection rates on hydraulic fracturing parameters. To accomplish our objectives, we created the geological layering in the zone of interest using specified formation properties in a 3-D numerical simulator. Appropriate fluid and proppant were selected. Results obtained show that injection rate of 13 bpm yielded the longest fracture, propped and effective prop length for both proppants. While the high-density proppant gave the longer fracture length, the low-density proppant produced the longest effective fracture length. In the rate sensitivity on dimensionless fracture conductivity (C_FD), high density proppants yield lower C_FD, while lower density proppants yield higher C_FD. The methodology is applicable to geothermal wells that require fracturing to create effective communication between the reservoir and the wellbore. Hence, we suggest application of the methods and results in geothermal wells, for proactive decision making in well stimulation treatments.
Journal of Petroleum Science and Engineering, 2017
This work presents promising results for the application of a novel approach to estimate geopressure to optimize allocation of clusters in a horizontal wellbore in an unconventional shale play using information from logging while drilling (LWD) techniques. In previous publications on this subject, the usefulness of implementing the diffusivity equation in conjunction with information from well logs to estimate geopressure in conventional and complex unconventional geological scenarios was demonstrated. In this new study, a novel approach is applied to characterize reservoir and fracture pressures along the horizontal section of a well drilled in the Southwest part of the Eagle Ford unconventional shale play. To the best of the authors' knowledge, there is no report of estimation of pore pressure in a horizontal wellbore using theoretical principles, such as the diffusivity theory. The recorded rock properties from LWD along the horizontal section of the well serve multiple purposes. Firstly, they were introduced into the solution of the diffusivity equation as "normalized values" to obtain the pore pressure distribution. Secondly, they are employed to generate a synthetic acoustic log along the horizontal section of the wellbore to determine geomechanical properties of Eagle Ford formation. The results documented in this work demonstrate that when using this novel methodology, horizontal wells can be characterized in great detail from the standpoint of reservoir pressure and brittleness. This novel approach is effective, reliable, and can help the completion engineer to decide where to allocate the clusters (perforations) to make more efficient the multistage hydraulic fracturing jobs and improve productivity. Furthermore, geoscientists, reservoir, and production engineers will benefit from knowing reservoir pressure distribution along the path of the horizontal section of the well in more detail. As a result, a more efficient reservoir characterization is obtained to improve horizontal wellbore performance.
Optimization of Multiple-Fractured Horizontal Tight Gas Well
Horizontal drilling and hydraulic fracturing are two reliable technologies which have made recovery of tight/shale gas economically viable. A common practice is to drill horizontal well parallel to the minimum horizontal stress, consider short perforation intervals and hydraulically fracture the formation. It is expected that the created fractures would be perpendicular to the horizontal well (transverse fractures). Determining the number of fractures in such horizontal wells is of great interest by the industry. Although one may assume that the more the number of fractures the better the productivity, there is always an optimum number of fractures (hence optimum fracture spacing) which is obtained based on both production rate of the reservoir and its cumulative production. In this paper, different sensitivity analyses on physical optimization parameters are combined by economical evaluation to find the optimum value of fractures spacing (number of fractures), and the length of horizontal section. These optimization analyses have been done on horizontal section length, total permeability, anisotropic permeability ratio, and drainage area. Analyses have been performed based on the values of gas production rates, cumulative production, and defined K value. Finally, economical optimization which was performed using U.S. historical monthly gas prices, inflation and interest rates over a period of 27 years, was coupled with production data obtained from modeling. All the costs and revenues were converted to U.S. Dollar value in 2009. This evaluation shows that for each specific reservoir an optimization study is required and there is no unique solution for all types of reservoirs. However, the gas price forecast is the main factor which governs the whole optimization process. Introduction Decline in conventional gas resources and the raise of demand is going to make the production from low permeability reservoirs economical and as a result more money is being invested on low-quality reservoirs. Almost all of these wells need to be stimulated in order to produce economically by creating enough contact area between reservoir and the well. Multi Fractured Horizontal Well (MFHW) is one of the methods that meet the production limitations, established well in North America as a way to maximize the production. Due to the high cost of horizontal well drilling and fracturing treatments,
The Geomechanical Interaction of Multiple Hydraulic Fractures in Horizontal Wells
The technology of multiple hydraulic fracture stimulation in horizontal wells has transformed the business of oil and gas exploitation from extremely tight, unconventional hydrocarbon bearing rock formations. The fracture stimulation process typically involves placing multiple fractures stage-by-stage along the horizontal well using diverse well completion technologies. The effective design of such massive fracture stimulation requires an understanding of how multiple hydraulic fractures would grow and interact with each other in heterogeneous formations. This is especially challenging as the interaction of these fractures are subject to the dynamic process of subsurface geomechanical stress changes induced by the fracture treatment itself. This paper consists of two parts. Firstly, an idealised analytical model is used to highlight some key features of multiple hydraulic fractures interaction, and to provide a quantification of 'stress shadow'. Secondly, a new non-planar three dimensional (3D) hydraulic fracturing numerical model is used to provide an insight into the growth of multiple fractures under the influence of subsurface geomechanical stress shadows. Attention is given to studying the height growth of multiple fractures.
Optimization of fracture length and well spacing can be critical to the economics of the exploitation of natural gas resources. If the fracture length is small compared to well spacing, then fracture azimuth will not affect interference between wells; many fields will be drilled to dense spacings and therefore require knowledge of the fracture azimuth to optimize the number of wells, the placement of the wells, and the length of the fractures. This is contrary to historical approaches to the optimization of ultimate recovery and net present value from tight gas fields, which are based on the idealiza-tion of homogenous, isotropic reservoirs and which neglect interwell interference. This paper reviews current technology for determining hydraulic fracture azimuth, and presents a solution for uniform flux fractures which accounts for fracture azimuth. It is shown that the uniform flux fracture model fails when interference between wells is significant. Numerical simulation of high conductivity fractures confirms that knowledge of fracture azimuth will be important for cases for which the ratio of interwell distance to fracture length is less than 2.0. Permeability anisotropies increase the importance of knowing fracture azimuth. A general procedure for optimization of fracture azimuth and well spacing is presented. OVERVIEW Increased well density is typically required when :
SPE Annual Technical Conference and Exhibition, 2015
Multi-stage hydraulic fracturing together with horizontal drilling plays an important role in the economic development of unconventional reservoirs. However, according to field analysis of stimulation effectiveness, only a small percentage of perforation clusters contribute to most of the well production. One reason for this low effectiveness is that multiple fractures do not take the same amount of fluid and proppant due to fracture interaction (i.e., stress shadow effects). Unfortunately, how best to minimize the negative effects of stress shadowing is still poorly understood in the petroleum industry. In this paper, we analyzed this problem in order to promote more uniform fracture growth using our complex hydraulic fracture development model. We employed our fracture propagation model that couples rock deformation and fluid flow in the fracture and horizontal wellbore. Partitioning of flow rate between multiple fractures was calculated by analogizing to the electric circuit netw...