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Permeability is an existential property in oil and gas reservoir production. Its value becomes even more important for the design of hydraulic fractures, in very wide use in the industry. Optimization of fracture geometry depends greatly on the permeability value. Methodologies such as the Unified Fracture Design cannot be applied properly in the absence of a reliable value of permeability. Massive amounts of income ride on the optimum deployment of fractures. While core and log-derived permeability values are often employed, they are usually unreliable and irrelevant to the forecast of well performance. Well-test-derived permeability is far superior but it suffers because of two reasons: 1) the well may not be flowing at all because of very small permeability and near-well damage and, 2) the test in an e.g., 0.1 md reservoir may require a week of duration, at least, just to reach infinite acting radial flow, whose appearance is necessary, for interpretation. The recent activity in shale formations has lowered the permeability values by orders of magnitude, towards nanodarcy (0.000001 md). This makes well tests even more unattainable. We are proposing here an alternative approach, the use of a fracture injection test (Minifrac) whose pressure falloff interpretation can lead to the traditional Nolte analysis providing the leak-off coefficient and closure pressure. However, because the overwhelming majority of DFIT fluids in low permeability formations is water with little if any polymer, the viscosity controlled and filter cake controlled components of the leak-off coefficient are non-existent. This suggests that only the compressibility controlled leak-off component dominates. This leak-off coefficient is directly proportional to the square root of reservoir permeability, whose calculation becomes readily available. In some ways what the energy of the minifrac does is to shock the formation, forcing back a rapid response, one that a well test cannot. Application of the technique to dozens of wells has led to very realistic permeability values which subsequently were corroborated by production data analysis. The technology and approach presented here can fill a major gap in proper fracture design and reservoir exploitation.
Permeability is an existential property in oil and gas reservoir production. Its value becomes even more important for the design of hydraulic fractures, in very wide use in the industry. Optimization of fracture geometry depends greatly on the permeability value. Methodologies such as the Unified Fracture Design cannot be applied properly in the absence of a reliable value of permeability. Massive amounts of income ride on the optimum deployment of fractures. While core and log-derived permeability values are often employed, they are usually unreliable and irrelevant to the forecast of well performance. Well-test-derived permeability is far superior but it suffers because of two reasons: 1) the well may not be flowing at all because of very small permeability and near-well damage and, 2) the test in an e.g., 0.1 md reservoir may require a week of duration, at least, just to reach infinite acting radial flow, whose appearance is necessary, for interpretation. The recent activity in shale formations has lowered the permeability values by orders of magnitude, towards nanodarcy (0.000001 md). This makes well tests even more unattainable. We are proposing here an alternative approach, the use of a fracture injection test (Minifrac) whose pressure falloff interpretation can lead to the traditional Nolte analysis providing the leak-off coefficient and closure pressure. However, because the overwhelming majority of DFIT fluids in low permeability formations is water with little if any polymer, the viscosity controlled and filter cake controlled components of the leak-off coefficient are non-existent. This suggests that only the compressibility controlled leak-off component dominates. This leak-off coefficient is directly proportional to the square root of reservoir permeability, whose calculation becomes readily available. In some ways what the energy of the minifrac does is to shock the formation, forcing back a rapid response, one that a well test cannot. Application of the technique to dozens of wells has led to very realistic permeability values which subsequently were corroborated by production data analysis. The technology and approach presented here can fill a major gap in proper fracture design and reservoir exploitation.
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.
Due to the frequent application of hydraulic fracturing technology (HF) on oil and gas fields, there is a large amount of statistical information about the operations carried out. It is possible to make a conclusion about the efficiency of the hydraulic fracturing, consider the design changes and make recommendations on the basis of results of data processing. However this task becomes complicated because conduction of pressure transient analysis on fracking wells reveals that the values of the fracture parameters, in particular the half-length, significantly differ from those planned for design. This paper is devoted to the investigation of the possible reasons of this discrepancy by using dimensionless variables, which allows analyzing of information about the performed fracturing operations. The nondimensionalization of the basic equations using for the hydraulic fracture modeling made it possible to obtain the dependence of the dimensionless half-length of the fracture on the dimensionless volume of the injected liquid, and also to obtain an empirical formula for estimating the half-length of the fracture. Also, the analysis provides a possibility to exclude the influence of different factors that could make a significant contribution to the existing discrepancy. As a result of the analysis, limitation of PTA models, related, for example, to the non-uniform fracture conductivity and the lack of interflow between layers with different properties, as well as the fracture design errors associated with incorrect closing ratios are identified among the most probable causes of the fracture length difference.
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