Summary This study is a comparison of hydraulic fracture models run using test data from the GRI Staged Field Experiment No. 3. Models compared include 2D, pseudo-3D, and 3D codes, run on up to eight different cases. Documented in this comparison are the differences in length, height, width, pressure, and efficiency. The purpose of this study is to provide the completions engineer with a practical comparison of the available models so that rational decisions can be made as to which model is optimal for a given application. Introduction Hydraulic fracturing, one of the most important stimulation techniques available to the petroleum engineer, is being used extensively in tight gas sandstones,1–5 coalbed methane,6 high-permeability sandstones in Alaska,7very weak sandstones off the U.S. gulf coast,8horizontal wells in chalks,9–10 and many other applications from waste disposal to geothermal reservoirs. Because of this diversity of application, hydraulic fracture design models must be able to account for widely varying rock properties, reservoir properties, in-situ stresses, fracturing fluids, and proppant loads. As a result, fracture simulation has emerged as a highly complex endeavor that must be able to account for many different physical processes. The petroleum engineer who must design the fracture treatment is often confronted with the difficult task of selecting a suitable hydraulic fracture model, yet there is very little comparative information available to help in making a rational choice, particularly on the newer 3D and pseudo-3D models. The purpose of this paper is to help provide some guidance by comparing many of the available simulators. The Fracture Propagation Modeling Forum held Feb. 26-27, 1991, near Houston provided the origin for this paper. This forum, sponsored by the Gas Research Inst. (GRI), was open to all known hydraulic fracturing modelers. Participants were asked to provide fracture designs based on the Staged Field Experiment (SFE) No. 3 fracture experiment. After the fracture designs presented at this meeting were compared, a final, revised data set was given to all participants. The results presented in this paper are derived from that data set. To publish the results, a four-member committee (the authors) was chosen from forum participants. In assembling this comparison, committee members purposely attempted to avoid judging the relative values of the different models. Only the results and quantifiable comparisons are given. Background—Basic Modeling Discussion In recent years, fracturing simulators used in the oil industry have proliferated. This proliferation was intensified by the availability of personal computers and the need for fast design simulators for use in the field. Applying these models as "black boxes," without knowledge of the underlying assumptions, may lead to erroneous conclusions, especially for unconfined fracture growth. Hydraulic fracturing is a complex nonlinear mathematical problem that involves the mechanical interaction of the propagating fracture with the injected slurry. Several assumptions are commonly made to render the problem tractable:plane fractures, symmetric with respect to the wellbore; elastic formation;linear fracture mechanics for fracture propagation prediction; power-law behavior of fracturing fluids and slurries; simplification of fracture geometry and its representation by few geometric parameters; etc. Ref. 11 gives a detailed description of the governing equations. Although the models predict "trends" of treating pressure behavior, they may not always reliably predict the observed behavior for a given treatment. This discrepancy has been attributed to many complex interactions between the injected fluids and the formation that are not well understood. An attempt to characterize phenomenologically some of these complex processes occurring within the fracture (e.g., multiple fractures and increasted frictional losses) and near the fracture tip (e.g., nonlinear formation behavior, microcracking, formation plasticity, dilatancy, and plugging) was made in various simulators by the introduction of additional ad hoc parameters ("knobs"). The choice of values for these parameters is based only on the modeler's experience. These knobs, used to match model predictions with field-observed behavior, result in the lack of a standard model response for a given physical problem. This issue was addressed in the forum by having different participants (discussing several different models) simulate common test cases derived from the actual SFE No.3 fracturing treatment. These models can be categorized in order of decreasing complexity as follows.Planar 3D models: TerraFrac of TerraTek Inc.12-16 run by Arco and HYFRAC3D by S.H. Advani of Lehigh U.17GOHFER, a unique finite-difference simulator by Marathon Oil Co.18,19Planar pseudo-3D models."Cell" approach: STIMPLAN of NSI Inc., ENERFRAC of Shell20,21 and TRIFAC of S.A. Holditch& Assocs. Inc.Overall fracture geometry parameterization: FRACPRO of Reservoir Engineering Systems (RES) Inc.22-25and MFRAC-ll of Meyer & Assocs.26-29Classic Perkins-Kern-Nordgren (PKN) and Geertsma-deKlerk(GDK) models30-35: PROP of Halliburton,34-36 the Chevron 2D model, the Conoco 2D model, the Shell 2D model, and pseudo-3D models run in constant-height mode. A discussion of the basics of these models is given to provide some insights on the model assumptions and their expected effect on results. Planar 3D Models. The TerraFrac12–16 and the HYFRAC3D17 models incorporate similar assumptions and formulate the physics rigorously, assuming planar fractures of arbitrary shape in a linearly elastic formation, 2D flow in the fracture, power-law fluids, and linear fracture mechanics for fracture propagation. Their difference is in the numerical technique used to calculate fracture opening. TerraFrac uses an integral equation representation, while the Ohio State model uses the finite-element method. Both models use finite elements for 2D fluid flow within the fracture and a fracture-tip advancement proportional to the stress-intensity factor on the fracture-tip contour. Planar 3D Models. The TerraFrac12–16 and the HYFRAC3D17 models incorporate similar assumptions and formulate the physics rigorously, assuming planar fractures of arbitrary shape in a linearly elastic formation, 2D flow in the fracture, power-law fluids, and linear fracture mechanics for fracture propagation. Their difference is in the numerical technique used to calculate fracture opening. TerraFrac uses an integral equation representation, while the Ohio State model uses the finite-element method. Both models use finite elements for 2D fluid flow within the fracture and a fracture-tip advancement proportional to the stress-intensity factor on the fracture-tip contour.

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Reservoirs with bottomhole temperatures in excess of 250°F are commonly encountered in the ever-expanding search for hydrocarbons. Successful completion of these wells often requires the use of Massive Hydraulic Fracturing (MHF) treatments. The fracturing fluids used in MHF treatments are frequently subjected to excessive shear and prolonged exposure at high bottomhole temperatures. Early fracturing fluids proved unsuitable for these MHF treatments due to a rapid loss of viscosity at high temperatures. As a result, narrow fracture widths, excessive fluid loss and poor proppant transport occurred. Cool-down pads, increased polymer concentrations and delayed polymer hydration systems were employed in an attempt to improve the MHF treatment success ratio. A laboratory investigation was undertaken to develop a more efficient high temperature fracturing fluid. Rotational and pipe viscometers were used to evaluate thermal and shear stabilities at reservoir conditions. Fluid loss testing measured the control of fluid leakoff to the formation. Fluid breakout testing ensured a controlled loss of viscosity and rapid cleanup. As a result of this study, a more efficient high temperature fracturing fluid was developed. This paper presents laboratory data comparing the thermal stability, shear stability and fluid loss control of the High Temperature Gel (HTG) with those of a conventional titanate crosslinked gel. Field case histories are presented to demonstrate the efficiency with which HTG has been used to successfully stimulate wells with bottomhole temperatures in excess of 250°F.

Reservoirs with permeabilities of less than 1 md and bottomhole temperatures in excess of 250°F are commonly encountered in the continuing search for hydrocarbons. Successful completion of these wells often requires the use of Massive Hydraulic Fracturing (MHF) treatments. The fracturing fluids used in MHF treatments are frequently subjected to excessive shear and prolonged exposure at high bottomhole temperatures. Early fracturing fluids proved unsuitable for these MHF treatments due to a rapid loss of viscosity at high temperatures. As a result, narrow fracture widths, excessive fluid loss and poor proppant transport occurred. Cool-down pads, increased polymer concentrations and delayed polymer hydration systems were employed in an attempt to improve the MHF treatment success ratio. A laboratory study was undertaken to develop a more efficient high temperature fracturing fluid. Rotational and pipe viscometers were used to evaluate thermal and shear stabilities under reservoir conditions. Fluid loss testing measured the effectiveness of fluid leakoff control. Fluid breakout testing ensured a controlled loss of viscosity and minimal proppant pack gel residue. As a result of this study, a more efficient high temperature fracturing fluid was developed. This paper presents laboratory data comparing the thermal stability, shear stability and fluid loss control of the High Temperature Gel (HTG) with those of a conventional titanate crosslinked gel. Field case histories axe presented to demonstrate the efficiency with which the HTG system has been used to successfully stimulate low permeability gas wells with bottomhole temperatures in excess of 250°F.

Summary Problems associated with massive hydraulic Problems associated with massive hydraulic fracturing (MHF) jobs seem varied and infinite. However, they may be grouped into two large categories--logistical and operational. Logistical problems involve the physical preparation of the well problems involve the physical preparation of the well and wellsite to accommodate the proposed treatment in an efficient and safe manner. Some jobs are destined for failure or at least a compromise of what is desired because requirements were not defined thoroughly and planned accordingly. Operational problems are those which occur during the actual problems are those which occur during the actual performance of the MHF treatment. Most performance of the MHF treatment. Most commonly, these include such things as pressure variations and equipment failures or malfunctions. Proper identification of the causative agent will allow Proper identification of the causative agent will allow a determination of the severity of the situation as well as the best alternatives for action. Early detection of the problems allow more flexibility for corrective action and possibly the difference in success or failure of the job. Introduction Many problems are encountered when planning and performing an MHF treatment. No one paper can performing an MHF treatment. No one paper can deal with all the possibilities, and that is not attempted here. With ever increasing complexity, the need for careful and detailed planning is vital. The intent of this paper is to identify some major areas of difficulty and some possible alternatives for avoiding them or at least minimizing their effect. Some topics are dealt with in a cursory manner, not because they are to be considered lightly but as a reminder for them to be a consideration in the overall process. Other areas are discussed in more detail because often they are less familiar and more subjective. The intent of this paper is to share what has been helpful in preparing for and performing MHF treatments in hopes that it will be useful to others who have this responsibility. Logistical Problems Wellsite Preparation Many times this area receives little attention. The key consideration is adequate size and accessibility. A location should be large enough to accommodate comfortably the required equipment and fracture tanks. Crowded conditions slow the preparation process by allowing only one phase of the job to process by allowing only one phase of the job to performed at a time. When time is being lost, the performed at a time. When time is being lost, the natural tendency is to hurry and take short cuts to get back on schedule. However, this usually leads to additional problems, time delays, and often a sacrifice in job quality. The best method is to resist the time pressure and do the preparation as correctly as possible because the investment is substantial and the consequences too important to be jeopardized even by a loss of several days.Sometimes equipment placement and material handling are made awkward or impractical by items left on location from the drilling operation or the premature installation of product equipment such as premature installation of product equipment such as tank batteries, separators, flare pits, etc. These often become obstacles that result in improper placement of equipment and materials and/or limit the size of the job. It also may create an unsafe condition by crowding the pumping equipment too close to the wellhead. An effort should be made to keep the location as unobstructed as possible until MHF operations are complete.While preparing the location, it is beneficial to raise the portion of the pad that will accommodate the fracture tanks (Fig. 1). JPT P. 1189