Fracture Flow Capacity Research Articles

On the influence of matrix flow in the hydraulic permeability of rough-walled fractures

Fractured porous media models may account for the influence of matrix flow in fracture permeability estimates through the slip boundary condition effect, i.e. permeable walls allow fluid to flow along them without viscous resistance. However, matrix flow may also create fluid pathways that unlock further fracture flow capacity, thus increasing its overall apparent permeability. We investigate this effect through numerical experiments by simulating fluid flow in a single fracture-matrix system with varying matrix permeability and calculating the apparent fracture permeability. We observe a consistent increase in fracture permeability with matrix permeability, which is yet underestimated by analytical models that factor in slip boundary conditions. Our study highlights the critical role of the surrounding porous matrix in accurately determining fracture permeability to prevent underestimations of the flow capacity of fractured porous media.

Dynamic Pressure Analysis of Shale Gas Wells Considering Three-Dimensional Distribution and Properties of the Hydraulic Fracture Network

A major challenge in transient pressure analysis for shale gas wells is their complex transient flow behavior and fracturing parameters. While numerical simulations offer high accuracy, analytical models are attractive for transient pressure analysis due to their high computational efficiency and broad applicability. However, traditional analytical models are often oversimplified, making it difficult to capture the complex seepage system, and three-dimensional fracture characteristics are seldom considered. To address these limitations, this study presents a comprehensive hybrid model that characterizes the transient flow behavior and analyzes the pressure response of a fractured shale gas well with a three-dimensional discrete fracture. To achieve this, the hydraulic fracture is discretized into several panels, and the transient flow equation is numerically solved using the finite difference method. Based on the Langmuir adsorption isotherm and the pseudo-steady diffusion in matrix and Darcy flow in the network of micro-fractures, a reservoir model is established, and the Laplace transformation is adopted to solve the model analytically. The transient responses are obtained by dynamically coupling the flow in the reservoir and the discrete fracture. The precision of the proposed model is validated using the commercial numerical simulator, Eclipse. A series of transient pressure dynamic curves are drawn to make a precise observation of different flow regimes, and the effects of several parameters on transient pressure response are also examined. The results show that the shale gas well testing interpretation curves comprise nine flow stages. The pressure drop of shale gas reservoirs is lower than that of conventional gas reservoirs due to the replenishment of desorbed gas. The artificial fracture flow capacity, fracture length, and height are the main engineering factors affecting the pressure responses of shale gas wells. Maximizing the degree and scope of reconstruction can enhance the gas well production capacity during fracturing construction. The research results also indicate that our model is a reliable semi-analytical model for well test interpretations in real case studies.

Study on formation process and reservoir damage mechanism of blockages caused by polyacrylamide fracturing fluid in production wells

In the process of the large-scale hydraulic fracturing development in oil and gas fields, reservoir damage caused by polymer fracturing fluid is inevitable. The real oil and gas field reservoir conditions make the causes of reservoir damage more complicated, and few reports have provided an in-depth analysis of the composition and structure of actual blockages generated in production wells after hydraulic fracturing. In this work, we innovatively obtained reservoir blockages from production wells after fracturing in oil and gas fields, analyzed their physical and chemical properties by SEM, XRD, IR and other methods, then reproduced the blockages formation process in the laboratory through ampoule aging experiments, and evaluated their impact on the reservoir damage rate and fracture flow capacity by core flow physical simulation experiments. The results indicate that the blockages primarily consist of polyacrylamide and iron ions complexes. For the formation process of blockages, the gel breaker solution will release iron ions after reacting with iron calcite existed in the reservoir. The carboxyl group of polyacrylamides and Fe3+ ions can further form highly stable -(COO)3Fe bonds. The physical simulation results revealed that the generation of Fe3+ ions significantly enhanced the extent of reservoir damage and reduction rate of fracture conductivity associated with polyacrylamide fracturing fluid. In addition, after complete gel breaking, the weak interactions between the short-chain molecular groups and Fe3+ ions result in limited molecular flocculation and entanglement, leading to the reduction in reservoir damage. By identifying the specific formation causes of blockages, we revealed the reservoir damage mechanism from a novel perspective, which is of great significance for guiding the development of low damage fracturing fluid system and further improving oil and gas recovery.

Concept and key technology of “multi-scale high-density” fracturing technology: A case study of tight sandstone gas reservoirs in the western Sichuan Basin

There are abundant tight sandstone gas resources in the Sichuan Basin, which are the important objects of reserve and production increase and large-scale development. Due to their discontinuous sandbody distribution, narrow channels, and strong horizontal and vertical heterogeneity, however, conventional fracturing technologies cannot achieve the ideal stimulation effect here. In order to address this difficulty, this paper dissects the geology engineering characteristics of tight sandstone gas reservoirs in the western Sichuan Basin. Starting from the seepage mechanics theory, the concept of “multi-scale high-density” tight gas fracturing technology is put forward by fully referring to the experience of previous multi-round reservoir stimulation in the western Sichuan Basin and the idea of unconventional volume fracturing technology. In addition, its conceptual connotation, key technologies and implementation effects are illustrated. The following research results are obtained. First, the seepage characteristics make it necessary for the efficient production of tight gas reserves to increase fracture density and stimulated reservoir volume (SRV). Second, the “multi-scale high-density” fracturing technology emphasizes the rationality of high-density hydraulic fracture creation and the matching of multi-scale fracture flow capacity, and aims at establishing a multi-level fracture system with effective and steady gas flow in tight reservoirs through fracturing. Third, the “wide, dense, support, stable, and precise” fracturing technology is applied to improve single well production and estimated ultimate recovery (EUR). Fourth, the engineering practice of “multi-scale high-density” fracturing technology in the tight reservoirs of Jurassic Shaximiao Formation and Triassic Xujiahe Formation in the ZJ Gas Field realizes the average single well production rate of 15.6 × 104 m3/d, which is 1.96 times higher than that before the stimulation. Obviously, it provides powerful support for the operation of the ZJ Gas Field into a giant gas field with the reserves of 100 billion cubic meters. In conclusion, the formation of the concept and key technologies of “multi-scale high-density” fracturing technology effectively supports the efficient development of tight gas in the western Sichuan Basin and points out the following research direction of tight gas reservoir stimulation. The research results provide reference and guidance for the large-scale benefit development of tight gas in China.

A Review of Flow Mechanism and Inversion Methods of Fracture Network in Shale Gas Reservoirs

The pore structure of shale gas reservoirs has strong heterogeneity, and the flow mechanism in multiscale media is complex. The fracture network of hydraulic fracturing is significantly affected by reservoir in situ stress, rock mechanical properties, and natural fracture distribution. At present, there is no efficient and accurate inversion method for fracture networks. Accurately describing fracture network morphology and flow capacity distribution of induced fracture is an important basis for production analysis, fracturing evaluation, and production plan. This article focuses on the hot issues of shale gas development, from three aspects: flow parameter characterization method of organic/inorganic matter, multiscale mass transfer simulation of shale gas reservoir, and inversion method of fracture network morphology and flow capacity, to introduce relevant research progress in detail. At the same time, the advantages and shortcomings of current related researches are compared and analyzed. Based on this, the key scientific problems existing on flow mechanisms and inversion method of fracture network in shale gas reservoirs are proposed, which can provide guidance for further research.

Productivity Prediction Model for Stimulated Reservoir Volume Fracturing in Tight Glutenite Reservoir Considering Fluid-Solid Coupling

At present, the main development mode of well + volume is adopted in the tight glutenite reservoir. Due to the existence of conglomerate, the seepage characteristics are more complex, and the production capacity after volume fracturing is difficult to predict. In order to solve this problem, a dual media unstable seepage model was established for matrix seepage and discrete fracture network seepage when considering the trigger pressure gradient. By considering the Poisson's ratio of stress sensitivity in an innovative way, the coupling model of permeability and stress is improved, and the production prediction model of volume fracturing horizontal well in tight glutenite reservoir based on the fluid-solid coupling effect is formed. The finite element method is used to numerically solve the model, and the fitting verification of the model is carried out; the impact of stress sensitivity, producing pressure difference, fracture length, number of fracture clusters and fracture flow capacity conductivity on productivity is analyzed,, which has certain guiding significance for the efficient development of volume fracturing in tight glutenite reservoir.

Optimization workflow for stimulation-well spacing design in a multiwell pad

A flow mathematical model with multiple horizontal wells considering interference between wells and fractures was established by taking the variable width conductivity fractures as basic flow units. Then a semi-analytical approach was proposed to model the production performance of full-life cycle in well pad and to investigate the effect of fracture length, flow capacity, well spacing and fracture spacing on estimated ultimate recovery (EUR). Finally, an integrated workflow is developed to optimize drilling and completion parameters of the horizontal wells by incorporating the productivity prediction and economic evaluation. It is defined as nested optimization which consists of outer-optimization shell (i.e., economic profit as outer constraint) and inner-optimization shell (i.e., fracturing scale as inner constraint). The results show that, when the constraint conditions aren't considered, the performance of the well pad can be improved by increasing contact area between fracture and formation, reducing interference between fractures/wells, balancing inflow and outflow between fracture and formation, but there is no best compromise between drilling and completion parameters. When only the inner constraint condition is considered, there only exists the optimal fracture conductivity and fracture length. When considering both inner and outer constraints, the optimization decisions including fracture conductivity and fracture length, well spacing, fracture spacing are achieved and correlated. When the fracturing scale is small, small well spacing, wide fracture spacing and short fracture should be adopted. When the fracturing scale is large, big well spacing, small fracture spacing and long fracture should be used.

A Trilinear Flow Model of Vertical Fractured Dual Porosity Media Considering the Quadratic Gradient Term

Based on the mass conservation principle and the Darcy's law, a double porosity media-trilinear flow model is established, including the effect of the quadratic gradient, wellbore storage and skin coefficient. The quadratic gradient term is eliminated by using logarithm transformation and different schemes are built and solved by Newton method. The effect of double porosity parameters, fracture flow capacity, the quadratic gradient term and skin coefficient on dimensionless pressure is discussed. The plots of typical pressure curves are given, and the results can be applied to well test analysis of fractured dual media.

An Analysis of Elastic Exploring in a Large-scale Fractured-vuggy Reservoir With Bottom Water

For the large-scale fractured-vuggy reservoir with bottom water, based on elasticity theory and flow in porous media theory, a physical model of different volume of the bottom water is established. According to the theoretical analysis, a relationship equation of cumulative production and cumulative pressure drop is deduced, and the feature and influencing factor of cumulative production and cumulative pressure drop curve are analyzed. Then, using physical modeling experimental method, the validity of the theoretical analysis is verified. The results show that cumulative production and cumulative pressure drop curve has a feature of straight-line at first, late upturned, and finally straight-line again. The straight-line segment reflects the size of the main vug, and the upturned segment is synthetically affected by the size of the main vug, the size of the bottom water, and the fracture flow capacity. Fracture permeability and the volume of the bottom water are important factors affecting the curve.

Pressure Variations Inside the Hydraulic Fracture and Their Impact on Fracture Propagation, Conductivity, and Screenout

Summary Field measurements of fluid pressure inside hydraulic fractures have shown rapid pressure declines along the fracture length. The consequence of this pressure profile is rapidly tapering fracture width. This means that a disproportionate volume of fluid and proppant injected inside hydraulic fractures remains near the wellbore, thus creating excessive near-wellbore and substantially less far-field fracture conductivity. This explains why history matching of oil well production figures yields much lower effective fracture lengths than when the same exercise is performed for gas wells, as oil wells require higher fracture flow capacity because of their higher permeability. The rapid tapering of the fracture width also restricts the movement of the proppant inside the fracture, causing its accumulation near the wellbore. As the treatment progresses, and if sufficient proppant volume has been injected inside the fracture, the near-wellbore segment of the fracture can begin to fill with proppant, thus reducing the open width available for further movement of the fluid. Essentially, accumulation of proppant near the wellbore reduces the fracture width available for fluid flow, which then results in higher frictional pressure losses inside the fracture, further skewing the pressure distribution and eventually leading to screenout.

Influence of temperature, effective stress and non-Darcy flow on the fracture flow capacity of propped fractures : Whitney, D D; Evans, R D Proc International Symposium on Rock at Great Depth, Pau, 28–31 August 1989V2, P947–954. Publ Rotterdam: A A Balkema, 1989

Influence of temperature, effective stress and non-Darcy flow on the fracture flow capacity of propped fractures : Whitney, D D; Evans, R D Proc International Symposium on Rock at Great Depth, Pau, 28–31 August 1989V2, P947–954. Publ Rotterdam: A A Balkema, 1989

Case History: Use of a Multiwell Model To Optimize Infill Development of a Tight-Gas-Sand Reservoir

The ability to predict incremental rates and reserves reasonably from infill development drilling in tight-gas reservoirs is enhanced through use of a three-dimensional (3D), multiwell, dry-gas model. Single-well (two-dimensional (2D)) and multiwell (three-dimensional (3D)) input and results are compared, and examples of both are presented. Measured initial reservoir pressures on an eight-well infill program compared favorably with the 3D model predictions.

The Practical Application of Economic Well Performance Criteria to the Optimization of Fracturing Treatment Design

SPE Members Abstract Low permeability reservoirs are currently being propped with sand, resin coated sand, intermediate density proppants and bauxite. This wide range of proppant cost and performance has resulted in the proliferation of proppant selection models. Initially, a rather vague relationship between well depth and proppant strength dictated the choice of proppant. More recently, computerized models of varying complexity have become available which utilize net present value calculations. The input is based on the operator's performance goals for each well and specific reservoir properties. Simpler, non-computerized approaches also being used include cost/performance comparisons and nomographs. Each type of model, including several of the computerized models, will be examined. Utilizing these models and net present value calculations, optimum fracturing treatment designs have been developed for low permeability reservoirs such as the Prue in Oklahoma. Typical well conditions are used in each of the selection models and the results are compared. The computerized models allow the operator to determine, prior to fracturing, how changes in proppant type, size, and quantity will affect post-frac production over time periods ranging from several months to many years. Thus, the operator can choose the fracturing treatment design which best satisfies his economic performance goals for a particular well, whether those goals be long term or short term oriented. INTRODUCTION: In the design of a hydraulic fracturing treatment, one of the primary considerations is the fracturing fluid - its temperature stability, proppant transport capability, and possible interactions with the formation. However, the only part of the fracture treatment which remains and controls long term productivity from a well is the proppant which is placed in the fracture. As a result, placement of the correct type, size, and amount of proppant for the given reservoir and producing conditions is of primary importance. Before the correct proppant can be selected, it is first necessary to optimize the propped fracture length based on the reservoir conditions. Theoretically, fracture flow capacity is optimized such that a dimensionless conductivity of at least 10 is obtained. The theory and application of dimensionless conductivity has been well documented in the literature. In reality, fracture length is influenced to a great extent by operator budgets, common area practices and fluid properties. Based on these considerations and reservoir properties, penetration distance and proppant concentration profile are obtained using fracture design programs. A dimensionless conductivity of 10 cannot always be economically or operationally obtained. To complicate matters, there are now a variety of proppant types and sizes available, some of which vary greatly in cost, and most of which have overlapping application ranges. The purpose of the computerized proppant selection model is to determine how post-frac productivity will be affected by changes in proppant type, size, and quantity. Net present worth calculations are then applied so that the technical choices are expressed in economic terms. This allows the operator to choose the fracturing design which best fits his economic performance goals for the well. DESCRIPTION OF REPRESENTATIVE MODELS The simplest methods of proppant selection are in the form of graphs and nomographs. P. 83^

Analysis of Short-Time Buildup Data for Finite-Conductivity Fractures

Summary A finite-conductivity vertical fracture intersecting a well is considered. The well is produced at a constant rate or at a constant pressure and then is shut in. The pressure response during the buildup period and the pressure or rate response during the production period are obtained from a numerical model. In this work we discuss the analysis of pressure buildup data following a short flow period. We present a buildup type curve to analyze pressure buildup data when the pressure (or rate) response is influenced by only the bilinear flow period. This type curve can be used to estimate the fracture flow capacity and a lower limit for the fracture half-length. It will be useful when the equivalent-time or the equivalent-drawdown concepts cannot be used. We discuss strengths and limitations of the equivalent time method proposed in the literature. The theoretical basis for this procedure is provided. Introduction Virtually all type curves available in the literature are intended for analysis of drawdown data and thus can be used to analyze buildup data only if the producing time before shut-in is significantly longer than the buildup time. Although this limitation is stated in the literature as far back as 1970, the consequences of using the drawdown type curves to analyze pressure buildup data measured after a short flow period were documented only recently. Buildup type curves that take into account the influence of producing time also are presented in Ref. 1. More recently, attempts have been made to bypass the buildup type curves and to use the drawdown curves directly. Raghavan et al. Suggests that buildup data can be converted to drawdown data and thus that the drawdown type curves can be used directly. This is the most accurate procedure available since it involves a minimum number of assumptions, but it does require that drawdown data be available unless Delta t/t less than 0.1 or Delta t/t >1. The principal advantage of the method is that it allows analysis of buildup data when Delta t >t. This is extremely important if the producing time before shut-in is small. An alternative procedure suggested by Agarwal involves a modification of the time scale and is known as the equivalent-time method. Theoretically, the method is valid only if plane radial flow prevails. However, Agarwal was able to demonstrate empirically that this technique applies to fractured wells. The principal objectives of this paper areto show that the normal form of the drawdown type curves for finite-conductivity fractured wells is inadequate to analyze buildup data following a short flow period,to present a modified version of these curves to analyze short-time data (drawdown or buildup),to present a buildup type curve suitable for analyzing data measured after a short production period,to discuss the strengths and limitations of the equivalent-time method, andto establish a theoretical basis for this procedure and to explain the empirical findings of Agarwal. 3 The buildup type curve presented here can be used to analyze tests in fractured wells when the response during the flow period is dominated by the bilinear flow regime. The type curve should prove useful when the other two methods suggested in the literature cannot (or should not) be used. Definitions All results given in this study are presented in terms of dimensionless variables. The dimensionless variables are defined in the following equations. JPT P. 2413^

Pressure Buildup From a Vertically Fractured Low-Permeability Formation(includes associated paper 12938 )

Summary Buildup theory for a vertically fractured gas well was reexamined assuming planar flow against constants and face pressure. The resultant pressure buildup is an arcsine function of a time group. If this relation is used to analyze buildup, it is possible to calculate the product of permeability and fracture half-length squared. This analysis gives better agreement with a set of field data and numerical simulation as compared with that from constant-rate theories using a Homer plot and atande msquare-root time plot. Introduction Pressure buildup data for a vertically fractured well can be analyzed by the usual Homer method, provided that the drawdown has reached pseudo steady state. For low-permeability reservoirs, the entire well test may lie within the initial flow period. The flow behavior of aportion of this period can be predominantly planar. Millheim and Cichowicz showed that the pressure buildup varies as a tandem square root of time. One ofthe assumptions they used was the constant-ratedrawdown, which usually is not valid for low- permeability reservoirs. In fact, it generally is accepted that as soon as a well is opened to flow in these reservoirs, the sand face pressure drops rapidly to a constant. This boundary condition has been recognized as valid fora large number of well tests. All these papers considered cylindrical radial flow. Agarwal et al. evaluated numerically the drawdown behavior of avertically fractured well under both constant-rate and constant-pressure boundary conditions. However, the rate/time type curves they generated for the drawdown against the constant-pressure case cannot be used to analyze buildup. The appropriate formulation considers the pressure buildup analysis of a vertically fractured well when the drawdown is against a constant sand face pressure. The buildup is derived by use of Duhamel's integrals withthe variable rate being the drawdown rate and the subsequent shut-in rate of zero. The integrand reduces to a simple form at the fracture face. The resultant closed form expression enables the pressure/time data to be plotted into a straight line, the slope of which is characterized by the initial reservoir pressure and the sand face drawdown pressure. Alternately, this slope can be expressed in terms of the last flow rate and the other reservoir/fracture parameters. One of them is the product of the formation permeability and the fracture half-lengthsquared. Without other information, it is possible to calculate only this product and not its individual components. Application of the derived equation to one example gave a result in good agreement with drawdown analysis and numerical simulation. The effects of wellbore storage and fracture damage also were shown to be negligible. Planar flow Period The geometry of the fracture plays an important role in the early-time flow data. Cinco-L. and Samaniego-V. divided the entire flow into four periods. Initially there isa fracture linear flow period in which the flow inside the fracture is the dominant factor. As the fluid from the formation starts its contribution, the flow enters the bilinear flow period. If the fracture is highly conductive, then there will be a period when planar flow from the formation into the fracture is a good approximation. Eventually, pseudo radial flow takes over in any fracture/formation system of sufficient extent. In analyzing a set of well test data using the plan arapproximation, care must be exercised to ensure that these data points fall within the planar flow period. It turns out that the determining factor in each of the early periods is the fracture flow capacity. JPT P. 917^

Foamed Acid An Effective Stimulation Fluid

Ford, William G.F., SPE, Halliburton Services Summary Dynamic laboratory testing of foamed acid on limestone cores has established the effectiveness of foamed acid as a stimulation fluid. The effects of foam quality, foam stability, and chemical compatibility on fluid loss and fracture flow capacity were investigated. Recommendations are presented for deriving maximum benefits from a foamed acid treatment. Field results are presented that show the effectiveness of foamed acid in the stimulation of both oil and gas wells. Introduction The use of foam in fracturing treatments has gained widespread acceptance in the past few years. Low liquid content, good fluid loss control, and quick cleanup are just a few reasons why foams are being used. The fluid loss properties of foam as a fracturing fluid and the flow of foam through porous media have been investigated by several authors. The use of foamed acid in fracture acidizing has been reported to give the same benefits as foam in hydraulic fracturing treatments. This paper describes work where fluid loss of foamed acid has been measured directly and the effect of foamed acid on fracture conductivity has been studied. This paper presents laboratory data describing the effects of foam quality, foam stability, chemical compatibility, formation permeability, and pressure differential on. fluid loss and fracture flow capacity with foamed acid on limestone. Apparatus and Test Procedure Fluid Loss Tests The system used to study foamed acid fluid loss is illustrated in Fig. 1. The liquid and gas portions of the foam were maintained at a constant volume by separate control mechanisms. A 1,500-mL volume Ampcoloy floating piston cell was used to hold the acid solution. The driving fluid for this cell was supplied by a positive displacement Jaeco pump. Flow rates were set mechanically on the pump and tested to be 20 mL/min at 1,500 psi. The flow rate of nitrogen at 1,500 psi was measured with an integral orifice meter equipped with a digital readout supplied by Fisher Porter with a No. 2 orifice. The meter was calibrated for various nitrogen flow rates at 1,500 psi through the use of a GCA/Precision Scientific wet test meter. The pressure of the system and nitrogen flow rates were adjusted manually by the use of a back pressure regulator for coarse settings and a needle valve for fine settings. Once pressure and flow rate were stabilized at the start of the test, very little adjustment was needed to maintain the proper pressure and flow rate.The foam generator consists of a 180-mL volume Ampcoloy cell and impeller driven at a speed of 2,200 rpm. This type of foam generator was chosen over the wire screen in a pipe type because of the reactive nature of the test solution. With time, the acid would react with and erode the screen, thus limiting the chances of reproducing a foam with the same texture (bubble size) and consistency from test to test.Foamed acid was generated and allowed to pass through two visual flow cells and out to the waste trap through a high-pressure backpressure regulator. The visual flow cells were used to check the condition of the foamed acid before the fluid loss test began, with uniform small bubbles and no gas pockets conditional to a stable foam. Once this condition was reached, a portion of the foamed acid was allowed to flow into the fluid loss cell while continuing to flow foamed acid through the system to the waste trap. JPT P. 7^

Analysis of Pressure Data From Vertically Fractured Injection Wells

Abstract This study investigates the flowing and shut-in pressure behavior of a fractured well located in a square drainage region with the outer boundary at a constant pressure. The fracture plane lies on one of the diagonals of the square. The report shows how to analyze pressure data for a five-spot pattern when the fracture orientation is most favorable (from the viewpoint of sweep efficiency). Comparisons are made with studies in the literature that assume an unfavorable fracture orientation. Fracture orientation must be considered in the analysis of pressure data for the following conditions: (1) small fracture-penetration ratios, (2) large flowing times prior to shut-in, and (3) large values of fracture flow capacity. Insights into the application of type-curve analysis to estimate drainage volumes are presented. Claims in the literature regarding the determination of the drainage volume by type-curve matching appear to be unrealistic.

Fracture Acidizing In Carbonate Rock

Abstract Fracture acidizing has an application in carbonate formations to improve the productivity of low-permeability reservoirs and for to overcome deep formation damage. If the acid solubility is less than 65% a viscous fingering technique is usually recommended. An ideal fracture would cover the productive interval vertically have a length equal to the drainage radius and have adequate/low capacity. Several/actors influence the geometry and development 0/fractures generated with acid. The effects of density, acid penetration fracture flow capacity, temperature acid concentration velocity or injection rate, viscosity and fluid loss are discussed. Computer-designed acid treatments and how they help select treatment volumes and predict production improvements are reviewed, The well data and the results of fracture acidizing seven Western Canadian wells are presented. Introduction Most acid pumped iota carbonate rock moves through fractures, either natural or created. If natural fractures do not exist, then by injecting acid at a high enough rate to develop the pressure required, one or more fractures can be created in the formation. In the late thirties and early forties, Clason(l) suggested that, based on Muskat's work, it would be impossible to get the production increases which were observed by merely increasing the size of the wellbore or through radial penetration of acid. According to Clason, crevices must be present and only through crevice enlargement and/ or removal of drilling fluid or other deposits from crevices or fractures could the large increases in productivity be explained. He was a little ahead of his time. About 10 years later, it was discovered that fractures or crevices actually could be created and fracturing theories began to be developed. Since that time, great strides have been made in fracturing both with and without propping agents. The use of acid to create and etch fractures has gone through several stages of development in the last 25 years(2), but remain something of a black art until Nierode and Williams (3, 4, 5) presented a kinetic model for the reaction of hydrochloric acid with limestones. They used this to predict acid reactions during fracturing operations and to design fracture acidizing treatments. This work has carried forward mainly by Roberts and Guin(6, 7, 8). Fracture Acidizing Initially, fractures were considered to be in a horizontal plane rather than most being vertical or inclined, as present theory suggests. Naturally fractured zones do exist and the' treating fluid will leak off into these natural fractures, as they represent the primary permeability. Laboratory tests show that when fractures are created they will propagate through naturally occurring fractures without regard to their orientation and are perpendicular to the least principale stress(9). Fracture acidizing has application in carbonate rock: limestone, dolomite and mixtures. If the formation has less than about 60% solubility in hydrochloric acid, then the possibility of a successful fracture acidizing job is greatly reduced unless the soluble portion is lining the fractures or the viscous fingering technique is used. Two primary reasons for fracture acidizing are: (1) low formation permeability, which prevents the well from producing by radial flow at an economic rate;

Criteria For Fracturing Low-permeability Water-sensitive Hydrocarbon Producing Formations: A Review

Abstract Many sandstone and limestone formations contain large amounts of water-sensitive clays. These clays may swell and reduce the size of flow channels, causing a decrease in permeability when contacted by untreated water. Fine particles may be released which could migrate and cause plugging of the small pore channels. Water may also soften the formation and cause a reduction in flow capacity of the created propped fracture. The fracturing water may be treated with certain salts to reduce clay swelling. Organic polymers have also been successfully used in water for this purpose. Foam, alcohol and oil-base fluids are used in severe cases of extremely water-sensitive formation. Examples of cases where these chemicals and base fluids have been successfully used to fracture water-sensitive formations are given. Selection of the base fluid formation should be based on laboratory tests on formation cores, when available, and field results. Selection of the amount of fluid-loss additive may be important, even in low-permeability formations. Comparison of fluid loss tests on formation cores both with and without fluid-loss additives reveal the importance of using additives in these formations. Some comparisons are given in the paper. Selection of the proppant and its required concentration can be determined by fracture flow capacity data and calculated propped fracture geometry. A computer program can be used to calculate the propped geometry. This paper provides insight to usage of suitable processes. materials and techniques to obtain better stimulation results for fracturing low-permeability, water-sensitive formations. Introduction Clays are usually present in most oil and gas-bearing formations and their presence can cause problems in the production of hydrocarbons, particular where stimulation processes are used. The clays most commonly present in producing formations are smectite, illite, a mixed layer (illite-smectite, chloritesmectite), kaolinite and chlorite. These clays exhibit a negative charge on the surfaces and are attracted by the positive charge of the hydrogen ion in water. Smectite has the greatest attraction to water and the highest cation-exchange capacity of these clays. The cation-exchange capacity is an indication of the degree or" clay swelling which occurs in the presence of water. especially untreated fresh water. The cation-exchange capacities of several clays are listed in Table 1(1). It depends on the substitution of magnesium and or ferrous iron for aluminum in the clay structure. This substitution results in a net negative charge on the faces of the clay mineral. The broken bonds on the edges of the clay crystals develop a small net positive charge. Swelling of clay in water is due to hydration of the cation attached to the clay and to hydrogen bonding. The degree of swelling depends on the cation attached to the clay and the amount of salts dissolved in the water contacting the clay. The hydration number represents the number of water molecules that can be associated with each cation. Table 2(1) lists the hydration numbers of several cations. Aqueous Treating Fluid Requirements for Fracturing Most formations have interstitial water that contains appreciable amounts of dissolved salts.

Evaluation and Performance Prediction of Low-Permeability Gas Wells Stimulated by Massive Hydraulic Fracturing

This paper discusses how to analyze past performance and predict futureperformance of tight gas wells stimulated by massive hydraulic fracturing (MHF)using finite fracture flow-capacity type curves. The limitations ofconventional pressure transient analysis and other methods of evaluating MHFtreatment are discussed. A set of constant well-rate and wellbore-pressure typecurves is presented. Introduction Because of the deteriorating gas supply situation in the U.S. and theincreasing demand for energy, the current trend is to consider seriously theexploitation and development of low-permeability gas reservoirs. This has beenpossible because of changes in the economic climate and advances in wellstimulation techniques, such as massive hydraulic fracturing (MHF). It nowappears that MHF is a proven technique for developing commercial wells inlow-permeability or "tight" gas formations. As the name implies, MHF isa hydraulic fracturing treatment applied on a massive scale, which may involvethe use of at least 50,000 to 500,000 gal treating fluid and 100,000 to 1million lb proppant. The purpose of MHF is to expose a large surface area ofthe low-permeability formation to flow into the wellbore. A low-permeabilityformation is defined here as one having an in-situ permeability of 0.1 md orless. Methods for evaluating a conventional (small-volume) fracturing treatmentare available, but the evaluation of an MHF treatment has been a challenge forengineers. To evaluate the success of any type of fracture stimulation, prefracturing rates commonly are compared with postfracturing production rates.These comparisons are valid qualitatively if both pre- and postfracturing ratesare measured under similar conditions (that is, equal production time, samechoke sizes, minimal wellbore effects, etc.). Unfortunately, to evaluate thesuccess of different kinds of fracturing treatments, pre- and postfracturingproduction rates often are measured pre- and postfracturing production ratesoften are measured and compared using not only the same well tested underdissimilar conditions, but also the same kind of comparisons between differentwells that may even have different formation permeabilities. Thus, resultsoften are invalid and may cause misleading conclusions. Moreover, suchcomparisons do not help predict long-term performance. To predict long-termperformance for MHF wells, reliable estimates of fracture length, fracture flowcapacity, and formation permeability are needed. Pressure transient methods for analyzing wells with small-volume fracturingtreatments are based on the concept of infinite or high fracture flow capacityand are used to determine the effectiveness of a stimulation by estimating thefracture length. Our experience indicates that these methods are not adequatefor analyzing wells with finite flow-capacity fractures. Such methods provideunrealistically short fracture lengths for MHF wells provide unrealisticallyshort fracture lengths for MHF wells with finite flow-capacity fractures.Furthermore, fracture flow capacities cannot be determined. Includes associated paper SPE 8145, "Type Curves for Evaluation andPerformance Prediction of Low-Permeability Gas Wells Stimulated by MassiveHydraulic Fracturing."