Performance Evaluation of A Horizontal Well with Multiple Fractures Using A Slab Source Function

2015 ◽  
Author(s):  
Daoyong Tony Yang ◽  
Feng Zhang ◽  
John Allen Styles ◽  
Junmin Gao
Keyword(s):  
Performance Evaluation ◽  
Horizontal Well ◽  
Source Function ◽  
Multiple Fractures

Performance Evaluation of a Horizontal Well With Multiple Fractures by Use of a Slab-Source Function

SPE Journal ◽  
2015 ◽  
Vol 20 (03) ◽  
pp. 652-662 ◽  
Author(s):  
Daoyong Yang ◽  
Feng Zhang ◽  
John A. Styles ◽  
Junmin Gao
Keyword(s):  
Horizontal Well ◽  
Source Function ◽  
Early Stage ◽  
Pressure Response ◽  
Multiple Fractures ◽  
Fracture Conductivity ◽  
Linear Flow ◽  
Type Curves ◽  
Semianalytical Method ◽  
Reservoir Simulator

Summary A novel slab-source function was formulated and successfully applied to accurately evaluate performance of a horizontal well with multiple fractures in a tight formation. More specifically, such a slab-source function in the Laplace domain has assigned a geometrical dimension to the source, whereas pressure response of a rectangular reservoir with closed outer boundaries can be determined. A semianalytical method is then applied to solve the newly formulated mathematical model by discretizing the fracture into small segments, each of which is treated as a slab source, assuming that there exists unsteady flow between the adjacent segments. The newly developed function was validated with numerical solution obtained from a reservoir simulator and then its application was extended to a field case. The pressure response together with its corresponding derivative type curves was reproduced to examine effects of number of stages, fracture conductivity, and fracture dimension under various penetration conditions. The fracture conductivity is found to mainly influence early-stage bilinear-/linear-flow regime, whereas a smaller conductivity will force more fluid to enter the toe of the fracture than its heel. The penetrating ratio will impose a significant impact on the pressure response at the early stage, forcing the bilinear/linear flow to become radial flow.

Performance Evaluation of A Horizontal Well with Multiple Fractures Using A Slab Source Function

2015 ◽  
Author(s):  
Daoyong Yang ◽  
Feng Zhang ◽  
John A. Styles ◽  
Junmin Gao
Keyword(s):  
Horizontal Well ◽  
Source Function ◽  
Early Stage ◽  
Pressure Response ◽  
Multiple Fractures ◽  
Fracture Conductivity ◽  
Linear Flow ◽  
Type Curves ◽  
Reservoir Simulator ◽  
Adjacent Segments

Abstract A novel slab source function has been formulated and successfully applied to accurately evaluate performance of a horizontal well with multiple fractures in a tight formation. A semi-analytical method is then applied to solve the newly formulated mathematical model by discretizing the fracture into small segments, each of which is treated as a slab source, assuming that there exists unsteady flow between the adjacent segments. The newly developed function has been validated with numerical solution obtained from a reservoir simulator and then extended its application to a field case. The pressure response together with its corresponding derivative type curves has been reproduced to examine effects of number of stages, fracture conductivity, and fracture dimension under various penetration conditions. The fracture conductivity is found to mainly influence early-stage bilinear/linear flow regime, while a smaller conductivity will force more fluid to enter the toe of the fracture than its heel. Penetrating ratio will impose a significant impact on the pressure response at the early stage, forcing the bilinear/linear flow to the radial flow.

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.

Performance Evaluation of Long-Horizontal-Well Solvent-Assisted SAGD in Rising Stage

2020 ◽  
Author(s):  
Hao Liu ◽  
Yuan Wang ◽  
Linsong Cheng ◽  
Shijun Huang ◽  
Xiao Chen
Keyword(s):  
Performance Evaluation ◽  
Horizontal Well

Optimized Model of Slotted Liners Completion Parameters in Horizontal Well

2012 ◽  
Vol 616-618 ◽  
pp. 804-811
Author(s):  
Quan Tang Fang ◽  
Wei Chen ◽  
Rong Wang
Keyword(s):  
Point Source ◽  
Line Source ◽  
Flow Resistance ◽  
Horizontal Well ◽  
Source Function ◽  
Geometric Model ◽  
Superposition Principle ◽  
Evaluation Index ◽  
Flow Convergence ◽  
Optimized Model

The transient flowing model of slotted liner completion was established by superposition principle based on the geometric model of slotted liners, with the point source function and the single slotting equal to line source, and then the optimized model of slotted liner completion parameter was established with the skin factor of slotted liners completion as evaluation index. After analyzing the parameter sensitivity with cases, the slot density is confirmed as the main reason leading to flow convergence and additional flow resistance. Furthermore, the optimization principles of slotted liners completion of horizontal well are determined. These results are significant in optimizing the slot distribution pattern and parameter allocation.

scholarly journals Pressure behaviour of a horizontal well sandwiched between two parallel sealing faults

2020 ◽  
Vol 39 (1) ◽  
pp. 148-153
Author(s):  
A.V. Ogbamikhumi ◽  
E.S. Adewole
Keyword(s):  
Horizontal Well ◽  
Source Function ◽  
Solution Method ◽  
Productivity Index ◽  
Production Potential ◽  
Dimensionless Length ◽  
Vertical Permeability ◽  
Dimensionless Pressure ◽  
Reservoir Geometry ◽  
Diffusivity Equation

Generally, reservoir fluid flow is governed by diffusivity equation and solution to this equation helps to investigate pressure behaviour under certain reservoir and wellbore boundary conditions. In this paper however, the analytical solution method of Green and Source function is deployed to determine the performance of a horizontal well located between two parallel sealing faults, assuming simple rectangular reservoir geometry. Also, the dimensionless pressure and derivative approach is applied for all computations as it prevents the problem of unit conversions, reduces longer expressions and it helps to handle numerical values. The pressure expression derived from this work reveals that a maximum of two flow periods occur for the stated reservoir model. It was found out that an inverse relationship exists between dimensionless pressure and dimensionless length while pressure increased with thickness. Also high vertical permeability shortens the effect of the early radial flow period experienced by the horizontal well, thereby increasing productivity index. Finally, it was discovered that increased perforation length reduces the production potential of the horizontal well. Keywords: Dimensionless pressure, pressure derivatives, heterogeneity, pressure performance, reservoir and wellbore characterization.

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.

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