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Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Unconventional Resources Conference-USA, April 10–12, 2013

Paper Number: SPE-164534-MS

... suggests that there may be other fracture sequencing strategies for accomplishing this as well. Roussel hydraulic fracturing Upstream Oil & Gas stress shadow spe annual technical conference closure pressure fracture spe 164534 Exhibition

**fractured****well**fracture closure Texas unpropped...
Abstract

Hydraulic fracturing in shale formations induces microseismic events in a region we refer to as the microseismic volume. Many of these microseismic events are signatures of failure in the formation that are believer to be a result of induced fractures, beyond the primary propped fracture. Aerially extensive microseismicity may be evidence that these induced, unpropped fractures occur and extend spatially beyond the propped fracture in many unconventional reservoirs. To illustrate these effects, microseismic and radioactive tracer data is presented for four laterals drilled and fractured from a single pad. Our simulations show that the opening of these induced, unpropped fractures results in significant temporary changes to the stress field in the rock. One consequence of this is that later fracture stages tend to propagate into the open fracture networks of induced, unpropped fractures created earlier due to stress reorientation. This can lead to inefficient usage of time, fluid, proppant, and capital since the region being stimulated has already been stimulated by the previous stage. By analyzing the net pressure, radioactive tracer and microseismic data from the four-well pad, we show that these induced, unpropped fractures close over time (over a period of hours) as the fracture fluid leaks-off. This relaxes the stresses and subsequent induced fractures are no longer subjected to the significantly altered stresses, allowing for more efficient fracture network coverage by subsequent fractures in a horizontal well. Based on the data presented and computer simulations, we propose the idea of establishing a minimum time between fracturing in the microseismic volume of a recently fractured region. The time required for the induced unpropped fractures to close can be calculated from our models and varies based on the reservoir and fluid properties but is typically on the order of hours. One example of how this is accomplished in practice is zipper fracs. However, our work suggests that there may be other fracture sequencing strategies for accomplishing this as well.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Gas Technology Symposium, April 30–May 2, 2002

Paper Number: SPE-75715-MS

... Abstract The paper describes a systematic study of the effect of the turbulence on productivity (or injectivity) of

**fractured****wells**. It extends significantly beyond previous work, and shows its limitations. A new correlation has been developed, based on over 2,000 high-accuracy numerical...
Abstract

Abstract The paper describes a systematic study of the effect of the turbulence on productivity (or injectivity) of fractured wells. It extends significantly beyond previous work, and shows its limitations. A new correlation has been developed, based on over 2,000 high-accuracy numerical solutions for vertically fractured well for a simple geometry. The base correlation was developed for fully penetrating fracture and it is applicable to liquid and high-pressure gas systems. The general correlation for fully penetrating fracture is a function of the two dimensionless parameters and two other parameters, which can be chosen as fracture conductivity and permeability. Additional results are provided for the effect of partial perforations on a fully penetrating fracture. As a limiting case, this scenario can represent also transversely fractured horizontal well. The final correlation therefore involves 5 variables. The results show that the conventional notion that turbulence is important only in high rate gas wells is often false. Turbulence effect on productivity or injectivity can be significant for liquid flow in high permeability formations, with limited perforations and especially in transversely fractured horizontal wells. Introduction Non-Darcy (turbulence) effects have been traditionally studied primarily for gas wells. The work of Guppy 1,2 showed that the effect of turbulence can be expresses as an "apparent conductivity" and a solution was obtained which correlates the ratio of the apparent to true conductivity with dimensionless rate Q D and dimensionless fracture conductivity C fD . More recently, turbulence has been shown to reduce productivity in high-rate oil wells. Smith et al. 3 have shown that for typical "indirect" fracture completions in the Cook formation of the Gullfaks field, that turbulence can reduce well productivity index (PI) by up to 40%. Approximate analytical method, as well as numerical simulation, was used to obtain those results. Settari et al. 4 have applied similar modeling techniques to the investigation of productivity of gas condensate wells. Their results also indicated reduction of PI of 30–40% due to turbulence, both in single phase, and multiphase flow conditions. Stark et al. 5,6 conducted a numerical study of turbulence in gas wells. The study introduced the concept of a "neutral skin" whereby the negative skin due to fracturing would negate the positive skin from turbulence such that the well PI would be equal to that of an unfractured well without turbulence. The work showed that in many cases fracturing could not even restore the well to the neutral skin. These studies indicate that evaluating the effect of turbulence is important in many more situations than previously thought. Similar results would be expected in high-rate water injection wells, which have been converted from fractured producers. The paper describes a systematic study of the effect of the turbulence on productivity (or injectivity) of fractured wells. It extends significantly beyond the previous works, and shows the limitations of the Guppy correlation. The study was performed in two parts. In the first part, the correlations for a fully penetrating fracture were developed. In the second part, the effect of partial perforation was studied and added to the correlation. Additional work is ongoing to verify the applicability for parameters, which have not been varied in this work.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE/CERI Gas Technology Symposium, April 3–5, 2000

Paper Number: SPE-59758-MS

... permeability fracture conductivity procedure upstream oil & gas spe 59758 hydraulic fracturing permeability

**fractured****well**pressure transient analysis reservoir effective permeability cosh production performance evaluation Copyright 2000, Society of Petroleum Engineers Inc. This paper was...
Abstract

Abstract A detailed analysis procedure for obtaining estimates of the reservoir effective permeability, fracture effective half-length, and average fracture conductivity using the bilinear to formation linear transition regime duration production performance data is presented in this paper. A combination of fractured well diagnostic analyses and history-matching with analytic solutions are used to obtain reliable estimates of the average fracture properties and reservoir effective permeability. The transient performance models reported in this paper include the practical reservoir effects of dual porosity, reservoir permeability anisotropy, and fracture face skin effect. Introduction A rate-transient based diagnostic analysis procedure for the production performance of fractured wells has been reported by Poe et al . 1 which permits the rigorous evaluation of the reservoir effective permeability and average fracture properties using the production performance of a fractured well. The production performance of the well is simply considered to be an extended duration drawdown transient with a varying sandface flowing pressure history. This is a good first step toward developing a general production data analysis procedure for fractured wells. A complimentary approach to the diagnostic analyses is the use of production performance history-matching. Finite-difference reservoir simulation models can be used to history match the production performance of fractured wells. These models may often be cumbersome to use and often require enormous amounts of data preparation, simulation, and analysis time to obtain reasonable matches of the production performance of a fractured well. Agarwal et al 2 have followed a somewhat similar approach in that they have used a combination of decline curve analysis and fractured well type curve matching to extract estimates of the reservoir effective permeability and average fracture properties. In this study, the fractured well production performance has been evaluated using a combination of the previously reported diagnostic analysis procedures 1 and history-matching with semi-analytic solutions of the transient performance of a fractured well, given in Appendix A. The use of both of these analysis procedures to evaluate estimates of the reservoir effective permeability, average fracture conductivity, and effective fracture half-length has greatly improved the accuracy, uniqueness, and reliability of these estimates from production data analysis. Extension of Diagnostic Analysis Procedures The diagnostic analysis procedures given in Ref. 1 were developed for fully exhibited flow regimes. Often a significant portion of the production performance data exhibits only partial ranges of the flow regimes or the end of the formation linear flow regime may be difficult to identify clearly. An example is a fractured well which exhibits bilinear flow, a transition regime, and only the start and part of the formation linear flow regime without the end of the formation linear flow regime being exhibited. In this example, the slope of the bilinear flow regime provides a reliable estimate of the product of the reservoir effective permeability and the square of the average fracture conductivity. When the end of the bilinear flow regime is observed in the data, an estimate of the product of the reservoir effective permeability and square of the effective fracture half-length can be obtained for dimensionless fracture conductivities greater than or equal to 10. For smaller values of dimensionless fracture conductivity, somewhat different products of the reservoir effective permeability and effective fracture half-length can be derived.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Gas Technology Symposium, April 28–May 1, 1996

Paper Number: SPE-35595-MS

... Abstract This paper presents new performance type curves for hydraulically

**fractured****wells**. The new curves are similar to the Fetkovitch curves for decline curve analysis, but have been developed specifically for**fractured****wells**with linear flow instead of conventional wells with radial flow...
Abstract

Abstract This paper presents new performance type curves for hydraulically fractured wells. The new curves are similar to the Fetkovitch curves for decline curve analysis, but have been developed specifically for fractured wells with linear flow instead of conventional wells with radial flow. Hydraulically fractured wells exhibit different flow regimes than conventional wells, including a skin-dominated period during clean-up, bilinear flow, linear flow, pseudo-radial flow, and boundary- or interference-affected flow. The type curves were constructed in Laplace domain for constant reservoir properties, and were then inverted numerically. The effect of varying reservoir properties was incorporated using an average compressibility determined from material balance. The type curve methodology provides a new tool for the reservoir engineer to perform rapid analysis of reservoir properties (kh), fracture effectiveness (Xf), and well drainage area (A) for fractured wells. The impact of skin on performance is considered, along with the effect of reservoir geometry (alternative length-to-width ratios) that enable these type curves to be used on lenticular formations. The type curves also include variable compressibility and viscosity that are missing in prior work. More than 1000 tight gas wells in the Green River and Piceance basins have been analyzed using the type curves, and relevant examples from these two basins are presented. Introduction Rate-time decline curve extrapolation is one of the most frequently used tools in the petroleum industry. In the classical formulation by Arps, based on work dating back to 1908, these curves were purely empirical, and the methodology was generally limited to exponential and hyperbolic decline curve analysis. Although not generally recognized in the industry, a sound theoretical basis for exponential decline curves was presented in 1937 by Muskat, whose solution of the rate equation for a closed circular reservoir with constant rock and fluid properties consisted of a series of exponential functions of time. After the second and subsequent terms decay, the first term leads to the usual exponential decline. Other investigators found that changes in fluid properties (non-constant compressibility and viscosity) could cause a hyperbolic decline, as could gravity drainage. The introduction of log-log performance type curves by Fetkovitch in 1973 greatly simplified the selection of the appropriate hyperbolic decline exponent, and made decline curve analysis easier and faster. The majority of the work performed prior to 1968 involved radial flow cases. Even when a fractured well was considered, it was usually handled as an equivalent radial flow case with improved productivity index or increased effective wellbore radius. The recognition that different flow regimes could develop grew out of pressure transient analysis of fractured wells. As stimulation treatments grew larger, and progressively lower permeability reservoirs were exploited, linear flow during well tests was recognized by MilIheim and Cichowicz in 1968. The complete transition from linear flow to pseudo-radial flow during well tests was presented by Gringarten and Ramey in 1974 for infinite conductivity and uniform flux fractures, and by Cinco-Ley, et al. in 1978 for finite conductivity fractures. In 1979, Kucuk and Brigham derived the pressure and rate response for an infinite conductivity fracture in an infinite reservoir using elliptical flow considerations. Because these works were primarily focused on pressure transient response rather than production rate analysis, they are not readily usable for estimating alternate recovery, future gas rates, or well drainage. Other investigators used simulators to evaluate production rate and transient tests for vertically fractured wells. Locke and Sawyer simulated type curves for an infinite conductivity fracture in infinite and closed reservoirs.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Gas Technology Symposium, January 22–24, 1991

Paper Number: SPE-21512-MS

... simulation representation reservoir

**fractured****well**permeability rectangular reservoir precision fracture element simulation heterogeneous reservoir simulation system analytical solution drillstem testing upstream oil & gas pressure interference test grid finite element solution numerical...
Abstract

SPE Members Abstract Today reservoir engineers are faced with the challenge of evaluating well tests in heterogeneous, complex reservoirs which may include fractures. For such reservoirs analytical methods are not available so numerical simulation is required. We present a finite element simulation system for gas well test analysis in such reservoirs. An automatic finite element grid generation technique provides grid refinement only in regions where it is needed. In this way wells and fractures are rigorously represented. Also wellbore storage and skin effects can be included in the model. Analytical coupling of fracture flow equations with reservoir flow equations, and nonlinear treatment of gas viscosity and compressibility, make the model ideal for gas well testing in fractured reservoirs. Also included in this 2-D model is the capability of simulating multi-layer, 2-D reservoirs with crossflow only at the wells in a numerically efficient way. The model has been validated against analytical solutions for liquid flow in homogeneous media and has been shown to he correct to high order accuracy. Introduction Analytical solutions to linearized approximations of the equation of flow for single phase flow in reservoirs have been exploited for many decades in the design and evaluation of transient pressure well tests. These, by definition, can be exploited by pressure well tests. These, by definition, can be exploited by the principle of superposition, for example, to represent variable flow rate histories [Collins, Earlougher, Lee]. Clearly, these are only approximations to reality and severely limit the types of physical systems that can he represented. Even the semi-analytic physical systems that can he represented. Even the semi-analytic method, based upon superposition of simple solutions obtained in the LaPlace transform domain using inversion by numerical techniques, is limited to linear forms of flow problems [Gringarten et al., Heber et al., Kucuk and Brigham]. Thus one must turn to numerical solutions if the more realistic, non-linear formulations for single phase flow are to he treated, especially for flow of real gases. Now it is true that an almost-linear differential equation for flow of a real gas is obtained if one introduces the real gas pseudo pressure [Dake] pressure [Dake] ...............................................(1) as the dependent function in lieu of pressure. Specifically this is ...............................................(2) where non-linearity still arises in the dependence of u and ct on P, or m. Furthermore, even if one accepts the linear P, or m. Furthermore, even if one accepts the linear approximation of K, ,u and Ct, all independent of variation in P, or m, analytical, or semi-analytical, solutions can be obtained P, or m, analytical, or semi-analytical, solutions can be obtained only for cases of reservoirs having very simple geometry and uniform properties. Thus numerical solutions must still be invoked for complex, heterogeneous reservoirs. As one turns to numerical solutions there are two options, finite difference methods or finite element methods. In block-centered finite difference techniques a well representation is required [Aziz and Settari]. Usually well models are based on the approximation of pseudo steady-state flow near the well; this causes error in well pressures. Furthermore, the common use of rectangular, orthogonal grids introduces grid limitations on the representation of reservoir geometry and the configuration of reservoir heterogeneities. An even greater difficulty arises in the use of finite difference techniques for reservoirs with heterogeneities in permeability; significant grid refinement is required in the neighborhood of any large discontinuity in permeability. Local grid refinement is possible permeability. Local grid refinement is possible [von Rosenberg] but is generally impractical in finite difference methods. Thus the finite element method is preferred. Now one might well ask, why require numerical solutions of great accuracy? The answer is that if one wishes to exploit the high precision of modern pressure gauges then one requires solutions as precise as analytical solutions. P. 317

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Gas Technology Symposium, June 7–9, 1989

Paper Number: SPE-19093-MS

... analytical reservoir flow models for

**fractured****wells**. Cinco and Samaniego-V studied the effects of wellbore storage and damage on the transient pressure behavior of vertically**fractured****wells**. However, these models do not consider a finite reservoir with a finite-conductivity fracture. A finite-difference...
Abstract

Abstract A new analytical solution for the pressure response of a well intercepting a finite-conductivity fracture is presented. We examine the effects of fracture conductivity, fracture height, drainage boundary size, wellbore storage and phase segregation on the pressure response of such wells. Example applications of the model for history matching of actual buildup examples are presented. We demonstrate that fracture length will be underestimated significantly if a type curve for an infinite-conductivity fracture with wellbore storage is used to analyze wellbore storage distorted data from a well with a finite-conductivity hydraulic fracture. Introduction The evaluation of massive hydraulic fracture treatment performance with pressure transient tests has been of great interest to engineers for several years. Increased activities in developing tight gas sands through hydraulic fracturing have generated considerable interest in these evaluations. The existence of substantial quantities of natural gas in these unconventional, low permeability reservoirs has generated a considerable effort from researchers to develop numerical and analytical tools to evaluate fracture treatments and to predict future performance of such reservoirs. Transient pressure analysis methods for wells intercepting a hydraulic fracture have been investigated by several researchers. These methods are based on either finite-difference or analytical techniques. Cinco published a survey of numerical and analytical reservoir flow models for fractured wells. Cinco and Samaniego-V studied the effects of wellbore storage and damage on the transient pressure behavior of vertically fractured wells. However, these models do not consider a finite reservoir with a finite-conductivity fracture. A finite-difference model, rather than analytical method, were also presented. Bennett et al. recently presented both numerical and analytical solutions for vertically fractured wells in layered reservoirs. Their model can handle finite-conductivity hydraulic fractures, but does not consider wellbore storage effects. Their model also assumes that the reservoir extends only to the tip of the fracture in the x-direction, and assumes an infinite (rather than a finite) reservoir. Lee and Brockenbrough presented an analytical model for estimating fracture parameters with real time and Laplace space parameter estimation. They assumed a trilinear flow model in describing the reservoir-fracture flow. However, their solution applies only to an infinite reservoir and assumes fracture height is identical to formation thickness. Neither of the above analytical model described above nor any of the earlier numerical work considers the combined effects of wellbore storage and phase segregation on pressure transient behavior in a fractured well. This paper presents a new analytical solution for the pressure response of a well intercepting a finite-conductivity fracture in a finite rectangular reservoir. The model includes the effects of wellbore storage and phase segregation in the wellbore. Solutions are presented to demonstrate the effects of parameters such as fracture conductivity, fracture height, drainage area, wellbore storage and phase segregation. We present an application of the model to buildup test data from tight gas wells of the Eastern Devonian Shale and East Texas using an automated parameter estimation approach. P. 363

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Unconventional Gas Recovery Symposium, May 16–18, 1982

Paper Number: SPE-10826-MS

... approximately the same, while as expected, average foam frac pressure is higher because of lower hydrostatic head. After stimulation, foam

**fractured****wells**are allowed to blow back through a one-quarter inch orfice until the wells are flowing only natural gas. This process usually takes from one to two days. At...
Abstract

The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA, May 16–18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, TX 75206. Abstract Stimulation of the Upper Devonian Benson Formation of Central West Virginia has lead to the use of various types of treatments. The following is an investigation of one of the more recent techniques, Foam/Nitrogen Fracturing, as it compares to the conventional Water Frac methods. The Benson is a shallow water turbodite deposit with thicknesses variable up to 30 feet. It is a brown siltstone which characteristically becomes commercially productive only after stimulation. Over the past three years stimulation of Union Drilling Benson wells in Upshur and Barbour Counties has been exclusively Foam Frac or Water Frac, with few exceptions. Foam Fracs were used initially for three reasons: to keep large volumes of water out of the formation in order to prevent clay swelling, to aid in well clean-up, to allow better sand placement through increased carrying quality of foamed Nitrogen. The ultimate goal of the Foam treatment is to increase gas flow from the wells. Methods of investigation include records kept of (1) volumes of water used for treatments, (2) cleanup and service rig time and efficiency (3) open flows from foam frac and water frac treated wells, an indication of the sand placement abilities. Conclusions based on open flow results indicate that lower volumes of water, quicker well clean-up, and improved sand placement are desirable for the Benson Formation. Introduction Beginning in 1979, Union Drilling, Inc. embarked upon a foam fracturing program for the Benson "sand" in Central West Virginia. Historically, Benson treatments have involved only water fracturing methods. The foam fracturing program was instituted for three basic reasons: To keep large volumes of water out of the formation in order to prevent clay swelling; To aid in well clean-up; and To allow better sand placement through increased carrying quality of foamed Nitrogen. The ultimate goal of the foam fracturing program, of course, was to increase gas flow from the wells. A total of twenty-nine wells were fractured using foam between June of 1979 and October, 1981. Each was perforated and fractured in the Benson "sand". Several wells were completed in both the Benson and Riley but, for the purposes of this report, only single stage Benson stimulations are investigated. This paper will examine the results of the foamed wells verses the results of basic water fracturing methods used on forty-nine single stage Benson wells completed by Union Drilling between August of 1969 and June of 1978. The investigation was conducted in the following manner: General Geology of the Benson "sand" –– a description of the Benson and its characteristics. General Procedures –– a summary of the stimulation and testing procedures used for both types of wells. Open Flow Analysis –– statistical analysis of the resulting openflows after frac. Production Analysis –– preliminary analysis of in line production. Economic Analysis –– comparison of average cost of the two treatments. Conclusions and Summary –– conclusions based on data presented, including a discussion of parameters which cannot be measured, and pitfalls associated with each analysis. p. 305

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Unconventional Gas Recovery Symposium, May 16–18, 1982

Paper Number: SPE-10842-MS

... N. Central Expwy., Dallas, TX 75206. Abstract A systematic approach is presented for generating transient inflow performance relationship curves for finite conductivity vertically performance relationship curves for finite conductivity vertically

**fractured****wells**. A semi-analytical model was...
Abstract

The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA, May 16–18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, TX 75206. Abstract A systematic approach is presented for generating transient inflow performance relationship curves for finite conductivity vertically performance relationship curves for finite conductivity vertically fractured wells. A semi-analytical model was developed to simulate dimensionless wellbore pressure drop and dimensionless pressure loss through the fracture vs. dimensionless time at constant-rate of production for wells intercepted by a finite-conductivity vertical fracture. Flowing bottom hole pressure can be predicted at any time period using these dimensionless variables. System average pressure at any stage of production can be obtained through material balance calculations. production can be obtained through material balance calculations. A straight line reference curve was observed at all times provided that the real gas pseudo-pressure function is used to plot m (p wf(t))/m(pR (t)) vs. qg (t)/ q gmax (t). The advantage of normalizing the dimensionless variable in terms of pseudo-pressure function is that only one straight line relationship is obtained throughout the entire production life of the reservoir. This provides a more simple means for performance prediction purposes. prediction purposes. The major contribution of this paper is the provision of a valuable tool to study the sensitivity of fracture design parameters on ultimate well performance. The economic benefits of this approach can be substantial. Introduction Hydraulic fracturing has been recognized to be an effective means for improving well productivity from low permeability reservoirs. During the past decade, a large amount of energy and effort has been given to the past decade, a large amount of energy and effort has been given to the determination of transient pressure behavior of the well intercepted by a vertical fracture. As a result, three basic solutions along with analysis method have been presented. They are uniform-flux, infinite-conductivity and finite-conductivity solution for vertical fractures. Type-curve matching has been proposed as an interpretation technique to determine reservoir properties and fracture characteristics from pressure transient test data. The contributions of these works have provided the practicing engineer with a better understanding of the fractured reservoir performance. performance. In 1968, Vogel presented a correlation to generate inflow performance relationships (IPR) curves for solution-gas drive wells based on the assumption of steady-state Darcy's law. The application of IPR curves in the analysis of total production systems are well recognized. Recently exploitation of low-permeability or tight gas reservoirs has required more advanced well stimulation techniques, such as massive hydraulic fracturing (MHF). Unfortunately, the transient IPR curves for wells intercepted by a finite-conductivity vertical fracture has not been investigated until now. It should be realized that pseudo-steady state pressure behavior for a tight gas reservoir is rarely seen in the early production life of the wells. Therefore, a systematic approach for generating transient IPR curves is one important objective of this work. Several questions have been asked quite often among production engineers. How can a frac job be designed for tight gas wells? what is the optimal fracture half length? What are the tubing and surface facility constraints? Can production rate vs. fracture half length be predicted before the fracturing operations? To answer the above questions, we should look at the total system performance, i.e.; both reservoir and tubing capacity performance. The model developed in this work will allow production engineers to make a judgement using production rate vs. fracture production engineers to make a judgement using production rate vs. fracture half length relationship as a criterion in designing a fracture job. The objectives of this work include: The utilization of type curves to predict transient reservoir performance (IPR curves) under different fracture characteristics. The sensitivity of tubing capacity performance under different conditions. Combining tubing capacity performance with reservoir performance to predict production rate vs. fracture half length relationships. p. 491

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Unconventional Gas Recovery Symposium, May 18–21, 1980

Paper Number: SPE-8961-MS

... hydrocarbon Upstream Oil & Gas West Virginia viscosity

**fractured****well**low permeability fracture SPE 8961 SPE FOAM FRACTURING: THEORIES, PROCEDURES AND RESULTS by J. S. Gaydos and P. C. Harris, Halliburton Services C Copyright 1980, American Institute of Mining, Metallurgical and Petroleum...
Abstract

Abstract For the past several years, foam has been used in many treatments as a fracturing fluid. Although many different types of reservoirs have been stimulated with foam, the primary zones of interest in Eastern Kentucky and Southern West Virginia have been the Berea Sandstone and the Devonian Shales. Due to the nature of these formations, i.e. low permeability, low bottom-hole pressure and water sensitivity, foam pressure and water sensitivity, foam fracturing has been a successful technique. This paper presents the basic background theory of foam and presents several basic treatment designs which have been used successfully in the Devonian Shales and Berea Sandstone. Production histories for up to two years on a number of wells fractured with foam are compared to production histories of offset wells which were conventionally fractured with gelled water. In all the side -by-side comparisons, foam fracturing was found to give production results either as good as, or better than, conventional fracturing with gelled water. Introduction In the decade of the 1970's, foam fracturing was established as a tool for stimulating the production of hydrocarbons from low pressure, low permeability wells. In the past several years, foam fracturing has also been applied to the Devonian Shales of West Virginia and Berea Sandstone of Eastern Kentucky for stimulating production of natural gas. The Devonian Shales typically have low natural reservoir pressure, with low permeability, natural fracturing, and tendencies permeability, natural fracturing, and tendencies toward fluid sensitivity and frac fluid retention. Foam, as a fracturing fluid, has inherent advantages for use in the initial stimulation of such formations. But the real value of foam stimulation must be reflected in the hydrocarbon produced. This paper presents the results for foam fracturing presents the results for foam fracturing treatments, as indicated by production histories up to two years, in comparison with the results of conventional gelled water fracturing treatments. THEORY A fracturing fluid often is a high viscosity fluid which is utilized to create a fracture and to transport propping agent and place it in the fracture. Efficient fracture place it in the fracture. Efficient fracture extension requires good fluid loss control. For greatest production benefit, the frac fluid must cause minimal damage to the formation and then return to the surface with maximum efficiency. Conventional aqueous fracturing fluid systems use gelling agents, such as polysaccharide gums, to yield fluids with polysaccharide gums, to yield fluids with high viscosity. The ability of the fluid to support proppant is partially dependent upon the concentration of the gelling agent in the fluid. High gelling agent concentrations also aid in fluid loss control; however, additional particulate fluid loss additives are often particulate fluid loss additives are often needed for full fracture extension. Return of the broken gelled water to the surface depends on various fluid properties as well as pressure within the reservoir. If the reservoir pressure is low, the return of fluid must be assisted by swabbing the well before the benefits of the frac treatment can be realized. Foams, which are mixtures of a gas phase a liquid phase and a surfactant, meet all the basic requirements for a good fracturing fluid; however, the fluid properties of foam are derived from a structure different from that found in gelled water.