Optimizing the Number of Fractures in a Horizontal Well

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 1364-1377 ◽  
Author(s):  
Vyacheslav Guk ◽  
Mikhail Tuzovskiy ◽  
Don Wolcott ◽  
Joe Mach
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Optimal Number ◽  
Hydraulic Fractures ◽  
Single Fracture ◽  
Multiple Fracture ◽  
Multiple Fractures ◽  
Type Curves ◽  
Fracture Width ◽  
Technical Potential

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.

Improving Proppant Placement Success in Horizontal Wells in Layered Reservoirs in the Sultanate of Oman

2021 ◽  
Author(s):  
Andrew Boucher ◽  
Josef Shaoul ◽  
Inna Tkachuk ◽  
Mohammed Rashdi ◽  
Khalfan Bahri ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Complex Geometry ◽  
Horizontal Wells ◽  
Vertical Position ◽  
Sultanate Of Oman ◽  
Vertical Wells ◽  
Multiple Fractures ◽  
Initiation Point ◽  
Interval Selection ◽  
Geological Units

Abstract A gas condensate field in the Sultanate of Oman has been developed since 1999 with vertical wells, with multiple fractures targeting different geological units. There were always issues with premature screenouts, especially when 16/30 or 12/20 proppant were used. The problems placing proppant were mainly in the upper two units, which have the lowest permeability and the most heterogeneous lithology, with alternating sand and shaly layers between the thick competent heterolith layers. Since 2015, a horizontal well pilot has been under way to determine if horizontal wells could be used for infill drilling, focusing on the least depleted units at the top of the reservoir. The horizontal wells have been plagued with problems of high fracturing pressures, low injectivity and premature screenouts. This paper describes a comprehensive analysis performed to understand the reasons for these difficulties and to determine how to improve the perforation interval selection criteria and treatment approach to minimize these problems in future horizontal wells. The method for improving the success rate of propped fracturing was based on analyzing all treatments performed in the first seven horizontal wells, and categorizing their proppant placement behavior into one of three categories (easy, difficult, impossible) based on injectivity, net pressure trend, proppant pumped and screenout occurrence. The stages in all three categories were then compared with relevant parameters, until a relationship was found that could explain both the successful and unsuccessful treatments. Treatments from offset vertical wells performed in the same geological units were re-analyzed, and used to better understand the behavior seen in the horizontal wells. The first observation was that proppant placement challenges and associated fracturing behavior were also seen in vertical wells in the two uppermost units, although to a much lesser extent. A strong correlation was found in the horizontal well fractures between the problems and the location of the perforated interval vertically within this heterogeneous reservoir. In order to place proppant successfully, it was necessary to initiate the fracture in a clean sand layer with sufficient vertical distance (TVT) to the heterolith (barrier) layers above and below the initiation point. The thickness of the heterolith layers was also important. Without sufficient "room" to grow vertically from where it initiates, the fracture appears to generate complex geometry, including horizontal fracture components that result in high fracturing pressures, large tortuosity friction, limited height growth and even poroelastic stress increase. This study has resulted in a better understanding of mechanisms that can make hydraulic fracturing more difficult in a horizontal well than a vertical well in a laminated heterogeneous low permeability reservoir. The guidelines given on how to select perforated intervals based on vertical position in the reservoir, rather than their position along the horizontal well, is a different approach than what is commonly used for horizontal well perforation interval selection.

Evaluating the Performance of Horizontal Multi-Frac Wells in a Depleted Gas Condensate Reservoir in Sultanate of Oman

2022 ◽  
Author(s):  
Josef R. Shaoul ◽  
Jason Park ◽  
Andrew Boucher ◽  
Inna Tkachuk ◽  
Cornelis Veeken ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Gas Condensate ◽  
Integrated Analysis ◽  
Single Fracture ◽  
Reservoir Pressure ◽  
Well Test ◽  
Vertical Wells ◽  
Fracture Conductivity ◽  
Half Length

Abstract The Saih Rawl gas condensate field has been producing for 20 years from multiple fractured vertical wells covering a very thick gross interval with varying reservoir permeability. After many years of production, the remaining reserves are mainly in the lowest permeability upper units. A pilot program using horizontal multi-frac wells was started in 2015, and five wells were drilled, stimulated and tested over a four-year period. The number of stages per horizontal well ranged from 6 to 14, but in all cases production was much less than expected based on the number of stages and the production from offset vertical wells producing from the same reservoir units with a single fracture. The scope of this paper is to describe the work that was performed to understand the reason for the lower than expected performance of the horizontal wells, how to improve the performance, and the implementation of those ideas in two additional horizontal wells completed in 2020. The study workflow was to perform an integrated analysis of fracturing, production and well test data, in order to history match all available data with a consistent reservoir description (permeability and fracture properties). Fracturing data included diagnostic injections (breakdown, step-rate test and minifrac) and main fracture treatments, where net pressure matching was performed. After closure analysis (ACA) was not possible in most cases due to low reservoir pressure and absence of downhole gauges. Post-fracture well test and production matching was performed using 3D reservoir simulation models including local grid refinement to capture fracture dimensions and conductivity. Based on simulation results, the effective propped fracture half-length seen in the post-frac production was extremely small, on the order of tens of meters, in some of the wells. In other wells, the effective fracture half-length was consistent with the created propped half-length, but the fracture conductivity was extremely small (finite conductivity fracture). The problems with the propped fractures appear to be related to a combination of poor proppant pack cleanup, low proppant concentration and small proppant diameter, compounded by low reservoir pressure which has a negative impact on proppant regained permeability after fracturing with crosslinked gel. Key conclusions from this study are that 1) using the same fracture design in a horizontal well with transverse fractures will not give the same result as in a vertical well in the same reservoir, 2) the effect of depletion on proppant pack cleanup in high temperature tight gas reservoirs appears to be very strong, requiring an adjustment in fracture design and proppant selection to achieve reasonable fracture conductivity, and 3) achieving sufficient effective propped length and height is key to economic production.

Can We Engineer Better Multistage Horizontal Completions? Evidence of the Importance of Near-wellbore Fracture Geometry from Theory, Lab and Field Experiments

2015 ◽  
Author(s):  
B.. Lecampion ◽  
J.. Desroches ◽  
X.. Weng ◽  
J.. Burghardt ◽  
J.E.. E. Brown
Keyword(s):  
Pressure Drop ◽  
Field Experiments ◽  
Horizontal Wells ◽  
Fracture Plane ◽  
Hydraulic Fractures ◽  
Multiple Fractures ◽  
Fracture Geometry ◽  
Complex Fracture ◽  
Limited Entry ◽  
The Impact

Abstract There is accepted evidence that multistage fracturing of horizontal wells in shale reservoirs results in significant production variation from perforation cluster to perforation cluster. Typically, between 30 and 40% of the clusters do not significantly contribute to production while the majority of the production comes from only 20 to 30% of the clusters. Based on numerical modeling, laboratory and field experiments, we investigate the process of simultaneously initiating and propagating several hydraulic fractures. In particular, we clarify the interplay between the impact of perforation friction and stress shadow on the stability of the propagation of multiple fractures. We show that a sufficiently large perforation pressure drop (limited entry) can counteract the stress interference between different growing fractures. We also discuss the robustness of the current design practices (cluster location, limited entry) in the presence of characterized stress heterogeneities. Laboratory experiments highlight the complexity of the fracture geometry in the near-wellbore region. Such complex fracture path results from local stress perturbations around the well and the perforations, as well as the rock fabric. The fracture complexity (i.e., the merging of multiple fractures and the reorientation towards the preferred far-field fracture plane) induces a strong nonlinear pressure drop on a scale of a few meters. Single entry field experiments in horizontal wells show that this near-wellbore effect is larger in magnitude than perforation friction and is highly variable between clusters, without being predictable. Through a combination of field measurements and modeling, we show that such variability results in a very heterogeneous slurry rate distribution; and therefore, proppant intake between clusters during a stage, even in the presence of limited entry techniques. We also note that the estimated distribution of proppant intake between clusters appears similar to published production log data. We conclude that understanding and accounting for the complex fracture geometry in the near-wellbore is an important missing link to better engineer horizontal well multistage completions.

Characterizing Tight Oil Reservoirs With Dual- and Triple-Porosity Models

2016 ◽  
Vol 138 (3) ◽  
Author(s):  
Ezulike Daniel Obinna ◽  
Dehghanpour Hassan
Keyword(s):  
Aspect Ratio ◽  
Horizontal Wells ◽  
Production Data ◽  
Hydraulic Fractures ◽  
High Fracture ◽  
Type Curves ◽  
Fracture Spacing ◽  
Aspect Ratios ◽  
Fractured Horizontal Wells ◽  
Porosity Model

The response of existing transient triple-porosity models for fractured horizontal wells do not converge to that of linear dual-porosity model (DPM) in the absence of natural/microfractures (MFs). The main reason is the assumption of sequential-depletion from matrix to MF, and from MF to hydraulic-fractures (HFs). This can result in unreasonable estimates of MF and/or HF parameters. Hence, the authors proposed a quadrilinear flow model (QFM) in a previous paper which relaxes this sequential-depletion assumption to allow simultaneous matrix–MF and matrix–HF depletion. Also, it is proved that QFM simplifies to both DPM and linear sequential triple-porosity model (STPM). This work considers the implications of applying QFM, STPM, and DPM type-curves and analysis equations on production data of two fractured horizontal wells completed in the Bakken and Cardium Formations. A comparative study of the reservoir parameters estimated from the application of these models to the same production data reveals two key results. First, the application of DPM on the production data from reservoirs with active MF could result in overestimation of HF half-length. This happens to compensate for the extra fluid depletion pathways provided by MF. Second, the application of STPM on the production data from the reservoirs with active matrix–HF communication could result in overestimation of the MF intensity. Results from this study are significant when selecting the appropriate model for interpreting production data from fractured horizontal wells completed in formations with or without active MF. The DPM is appropriate if analog studies (e.g., outcrop, microseismic and image log analyses) reveal high fracture spacing aspect ratio (negligible MF) in the reservoir. Fracture spacing aspect ratio is MF spacing divided by the HF spacing. The STPM is appropriate if analog studies reveal low spacing aspect ratio (e.g., matrix–HF face damage or high MF intensity within a given HF spacing). QFM is appropriate for all fracture spacing aspect ratios.

A Semianalytical Model for Horizontal-Well Productivity With Pressure Drop Along the Wellbore

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1603-1614 ◽  
Author(s):  
Wanjing Luo ◽  
Changfu Tang ◽  
Yin Feng
Keyword(s):  
Reynolds Number ◽  
Fluid Flow ◽  
Pressure Drop ◽  
Horizontal Well ◽  
Horizontal Wells ◽  
Productivity Index ◽  
Type Curves ◽  
Penetration Ratio ◽  
New Type ◽  
The One

Summary This study aims to develop a semianalytical model to calculate the productivity index (PI) of a horizontal well with pressure drop along the wellbore. It has been indicated that by introducing novel definitions of horizontal-well permeability and conductivity, the equation of fluid flow along a horizontal well with pressure drop has the same form as the one for fluid flow in a varying-conductivity fracture. Thus, the varying-conductivity-fracture model and PI model can be used to obtain the PI of a horizontal well. Results indicate that the PI of a horizontal well depends on the interaction between horizontal-well conductivity, penetration ratio, and Reynolds number. New type curves of the penetration ratios with various combinations of parameters have been presented. A complete-penetration zone and a partial-penetration zone can be identified on the type curves. Based on the type curves, two examples have also been presented to illustrate the advantages of this work in optimizing parameters of horizontal wells.

Formation of a Methodology for Calculating the Optimal Number of Wells in the Development of Lenticular Formations to Achieve Maximum NPV

2021 ◽  
Author(s):  
Vadim Andreevich Rubailo ◽  
Kirill Dmitrievich Isakov ◽  
Alexey Stanislavovich Osipenko ◽  
Marcel Mansurovich Akhmadiev
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Optimal Number ◽  
Project Development ◽  
Analytical Methodology ◽  
Petrophysical Parameters ◽  
Early Stages ◽  
Reservoir Fluid ◽  
Economic Parameters ◽  
New Equation

Abstract The work is devoted to the analytical methodology for the development of oil lenticular formations. The method is based on the theory of potentials for vertical and horizontal wells. The work takes into account the interference of wells, geological and petrophysical parameters of lenses, as well as the properties of the reservoir fluid, and a new equation for estimating the inflow to a horizontal well is derived. An assessment of the correctness of this work on the company's assets was made. The dependence for the express estimation of the number of wells depending on the economic parameters at the early stages of project development is obtained.

Simultaneous Multifracture Treatments: Fully Coupled Fluid Flow and Fracture Mechanics for Horizontal Wells

SPE Journal ◽  
2014 ◽  
Vol 20 (02) ◽  
pp. 337-346 ◽  
Author(s):  
Kan Wu ◽  
Jon E. Olson
Keyword(s):  
Fluid Flow ◽  
Fracture Propagation ◽  
Horizontal Wells ◽  
Gas Production ◽  
Propagation Model ◽  
Displacement Discontinuity ◽  
Hydraulic Fractures ◽  
Multiple Fractures ◽  
Frictional Pressure Drop ◽  
Horizontal Wellbore

Summary Successfully creating multiple hydraulic fractures in horizontal wells is critical for unconventional gas production economically. Optimizing the stimulation of these wells will require models that can account for the simultaneous propagation of multiple, potentially nonplanar, fractures. In this paper, a novel fracture-propagation model (FPM) is described that can simulate multiple-hydraulic-fracture propagation from a horizontal wellbore. The model couples fracture deformation with fluid flow in the fractures and the horizontal wellbore. The displacement discontinuity method (DDM) is used to represent the mechanics of the fractures and their opening, including interaction effects between closely spaced fractures. Fluid flow in the fractures is determined by the lubrication theory. Frictional pressure drop in the wellbore and perforation zones is taken into account by applying Kirchoff's first and second laws. The fluid-flow rates and pressure compatibility are maintained between the wellbore and the multiple fractures with Newton's numerical method. The model generates physically realistic multiple-fracture geometries and nonplanar-fracture trajectories that are consistent with physical-laboratory results and inferences drawn from microseismic diagnostic interpretations. One can use the simulation results of the FPM for sensitivity analysis of in-situ and fracture treatment parameters for shale-gas stimulation design. They provide a physics-based complex fracture network that one can import into reservoir-simulation models for production analysis. Furthermore, the results from the model can highlight conditions under which restricted width occurs that could lead to proppant screenout.

scholarly journals Sensitivity analysis for the appraisal of hydrofractures in horizontal wells with borehole resistivity measurements

Geophysics ◽  
2013 ◽  
Vol 78 (4) ◽  
pp. D209-D222 ◽  
Author(s):  
David Pardo ◽  
Carlos Torres-Verdín
Keyword(s):  
High Frequency ◽  
Horizontal Well ◽  
Low Frequency ◽  
Horizontal Wells ◽  
Hydraulic Fractures ◽  
Electrically Conductive ◽  
Resistivity Measurements ◽  
Electromagnetic Measurements ◽  
Open Hole ◽  
Thin Disks

We numerically evaluate the possibility of using borehole electromagnetic measurements to diagnose and quantify hydraulic fractures that have been artificially generated in a horizontal well. Hydrofractures are modeled as thin disks perpendicular to the well and filled with either sand-based or electrically conductive proppant. The study focuses on the effect of thickness and length (radius) of hydrofractures to assess their effects on specific configurations of borehole-resistivity instruments. Numerical results indicate that several measurements (e.g., those obtained with low- and high-frequency solenoids) could be used to assess the thickness of a fracture. However, only low-frequency measurements performed with electrodes and large-spacing between transmitter and receivers (18 m) exhibit the necessary sensitivity to reliably and accurately estimate the length of long hydrofractures (up to 150 m) in open-hole wells. In the case of steel-cased wells, the casing acts as a long electrode, whereby conventional low-frequency short-spaced, through-casing measurements are suitable for the accurate diagnosis of long hydrofractures (up to 150 m in length).

Modeling of Low-Frequency Downhole Electrical Measurements for Mapping Proppant Distribution in Hydraulic Fractures in Casedhole Wells

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 2147-2157 ◽  
Author(s):  
Peng Zhang ◽  
Mrinal K. Sen ◽  
Mukul M. Sharma ◽  
Jeff Gabelmann ◽  
David Glowka
Keyword(s):  
Electrical Potential ◽  
Synthetic Data ◽  
Low Frequency ◽  
Electrical Current ◽  
Hydraulic Fractures ◽  
Single Fracture ◽  
Electrical Measurements ◽  
Multiple Fractures ◽  
Electrically Conductive ◽  
Simulation Results

Summary A tool concept using downhole electrical measurements for mapping electrically conductive proppant in hydraulic fractures is presented in this paper. The method relies on direct excitation of the casing, which is expected to overcome the severe limitations of induction tools in casedhole wells. An array of insulating gaps is installed and cemented in place as a permanent part of the casing string. The envisioned electrical measurements are performed by imposing a voltage across each insulating gap, one at a time, before and after hydraulic-fracture operations. The voltages across other insulating gaps near the transmitter gap are recorded. The proposed tool's response to the geometry of a single fracture was modeled by solving for the electrical potential with a finite-volume method. Previous simulation results have shown that the electrically conductive proppant alters the path of the electrical current in the formation, and this is recorded as differential signals by the string of insulating gaps surrounding the source gap. The simulated differential signals are highly sensitive to a fracture's location, length, and orientation, and less sensitive to the fracture's aspect ratio. However, to enable the implementation of such a practical system, various aspects of the tool concept must be investigated further through simulations. Following our previous work, this paper focuses on the forward modeling of the tool's response to multiple fractures, which demonstrates the influence of these fractures on the signals, and provides important guidance for inverse modeling. Parametric inversion of fractures from synthetic data, generated by exciting various insulating gaps, is solved with very fast simulated annealing (VFSA). Simulation results show that, when multiple hydraulic fractures are present, the voltages measured at the receiver gaps are determined primarily by the fracture that is in direct contact with the excited section of casing. When two fractures touch the same casing section, they induce voltages very similar to those from a single fracture with the same conductivity and volume. Preliminary inversion results that use synthetic data computed from circular fractures indicate that the proposed VFSA can solve for the multiple fractures’ widths and radii at the same time, without requiring numerous forward simulations. Even with noisy synthetic data, VFSA can make good estimates of the fractures’ parameters. This indicates that the VFSA technique is a proper and robust inversion technique for the measured voltages at various receiver gaps.

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