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."

The economic viability of a shale play is strongly dependent on permeability which is often on the order of nanodarcies. Permeabilities are measured on core plugs or crushed samples using unsteady state techniques. However, the resultant permeabilities are the sources of controversy, because of the inconsistency in the permeability values produced with different techniques and different laboratories. In this research we evaluated the experimental factors which could influence permeability measurements with the GRI technique, and also present some permeability measurements on shale plugs. To evaluate the GRI permeability measurement technique on crushed rock, we investigated the effect of particle size, sieving of the crushed samples, pore pressure, different gases, and initial state of the measurement apparatus. The measured crushed shale permeabilities display a dependency on all these parameters. However, the particle size and the pore pressure appear to be the more important factors. This makes the reported values strongly dependent on the exact measurement procedure. This study was complemented by the imaging of crushed shale samples with a micro-CT scanner. These images showed the presence of microcracks even in samples as small as the recommended GRI particle size (~0.7mm). The permeabilities of several Devonian and Ordovician age shale plugs were measured with a pressure build up technique using nitrogen as flowing gas. A permeability decrease by an order of magnitude was generally observed for the Ordovician shale plugs with an increase of confining pressure from 1000 to 5000 psi. For the same Ordovician shale, the permeability anisotropy was found to be close to 2 orders of magnitude.The permeability of the Devonian shale plugs decreased by a maximum of 3 orders of magnitude over the range of confining pressure. For most shales, the confining pressure dependency of permeability is driven by cracks which is confirmed by a fit to Walsh's crack permeability model. However, we also noticed that it is possible to close the cracks contained in some plugs and obtain a value more representative of matrix permeability.

This paper presents a newly developed pressure transient analysis method for analyzing the injection well test pressure data from a well-reservoir system with multiple fluid banks. This new method should enable engineers to calculate the mobility profile in the reservoir, fluid bank radii during the falloff period and the pressure distribution in the reservoir at the instant of shutin. The utility and application of the new analysis procedure have been discussed and demonstrated by means of simulated cases and field examples.

I. AbstractIn recent years, a need has been recognized to develop pressure transient technology for slanted wells in single and multiple layered systems. To date, none of the published results pertains to the pressure transient response of a slanted well in a layered system. Moreover, the published pressure transient response of a slanted wellbore for single layered systems is based on a uniform flux assumption along the wellbore surface. Therefore, a 3-D finite element numerical model utilizing the infinite conductivity wellbore assumption was developed to study the pressure transient behavior of slanted wells in both single and multiple layered systems.The purpose of this paper is to present pressure transient responses for a variety of cases using the finite element and the analytical solutions. The slanted wellbore cases include the effect of partial penetration, wellbore storage, and reservoir heterogeneity for single layered systems, and typical pressure transient responses for multiple layered systems. The important parameters which influence the pressure behavior of slanted wells in a layered reservoir, with and without interlayer crossflow, will be presented. In addition, the response of a slanted well in a naturally fractured (dual porosity) system will be discussed. Finally, the pressure transient analysis of the data using field examples will be shown to demonstrate the usage of the developed model.The present study of the pressure transient responses of slanted wells in both single and multiple layered systems should enhance our understanding and add to our capability to design and analyze well tests. II. IntroductionIn real life, slanted wells usually exist when a vertical well penetrates a dipping formation, or when a directionally-drilled well penetrates a horizontal formation. The effect of the slanted well was first investigated by Roemershauser and Hawkins. 1 They developed and used an electrical analogue to study the steady-state flow of a fully penetrating well in a circular finite reservoir. References and illustrations at end of paper. 677There is very limited published pressure transient work available on the slanted well. The only compreh,:nsive studies published in the litera~ure were done by Cmco etaz.2 and Abbaszadeh etal. s Cmco etal. 2 derived an analytical solution to study the transient pressure response created by slanted wells. This solution was de~ived using the point source solution as a starting pomt and assumed that the fluid withdrawal/injection along the wellbore is uniformly distributed (uniform-flux solution). This assumption leads to a nonuniform pressure at the wellbore surface. Therefore, in order to obtain an infinite conductivity wellbore solution or uniform pressure at the wellbore surface, the wellbore pressure as a function of time is computed at a special point on the well face. The study by Abbaszadeh presents analytical solutions for the pressure response of a slanted limited entry well in an infinite reservoir subject to a gas cap or bottomwater drive or a com...

Use of type curves based on the dimensionless pressure and its logarithmic derivative has become a standard method for analyzing well tests data. Recently, a new procedure for constructing type curves using a dimensionless pressure group which involves the ratio of the dimensionless pressure and its derivative was developed and reported in the literature. This paper extends the preceding concept not only to the pressure variable but also to the time variable. That is a new dimensionless time group is introduced for type curv~ construction. The major advantage of this is that the matching procedure requires the movement of the field data only in the horizontal direction. This improvement not only facilitates the type curves match but also increases the reliability of the analysis results.New type curves are presented for wells in radial systems with wellbore storage and skin, and vertically fractured wells with uniform-flux, infinite-conductivity and finite-conductivity fractures. Field examples are included to illustrate the utility of the new type curves and the analysis procedure. The possible application of this method to heterogeneous systems such as naturally reservoirs are also discussed.