Visco-Elastic Surfactant (VES) fluids are polymer-free fluids that generate viscosities suitable for fracturing operations without the use of polymer additives. VES fluids do not form polymer filter-cake, and thus, viscous resistance of the fluid flowing through the rock matrix primarily governs fluid loss. This has historically limited the application to fracturing reservoirs with low permeabilities. A new VES fracturing fluid has been developed for use in high permeability reservoirs and successfully pumped in the Gulf of Mexico. The fluid exhibits enhanced fluid efficiency while still maintaining the high proppant pack conductivity associated with the lack of polymer damage. In this paper, laboratory test results for the new fluid are presented along with three high-permeability case histories. The estimated reservoir permeabilities were as high as 167 mD and reservoir heights ranged from 30 -90 feet. In all cases the entire propped fracture design was successfully placed. Introduction Visco-elastic surfactants have been used in oil and gas wells for fracturing stimulation for over ten years1. During this time the technology has evolved from a niche application in gravel packing2 to a mainstream range of applications where clean proppant packs and gravel packs are desired3. In the latest form presented here, a VES fluid utilizing a new surfactant has been formulated and optimized for high permeability operations. Fluid Rheology Viscosity of a VES fluid is created by self-assembly of surfactant molecules in an aqueous solution. Hydrophobic tails of surfactants associate and orient to create rod shaped structures commonly referred to as micelles. Entanglement of these flexible micelles imparts viscosity to the solution as shown in Figure 1. A variety of surfactant types can be used for formulating VES fluids, including anionic surfactants, cationic surfactants, and zwitterionic surfactants4. The new VES fluid presented here utilizes a specially formulated zwitterionic surfactant that creates stable micelles with unusual high-temperature stability. Figure 2 presents the fluid rheology as a function of temperature for different levels of surfactant package concentration. The surfactant package creates useful rheology within concentrations ranging from 3.5% to 6%. The exact surfactant concentration depends on the bottom hole temperature and desired fluid viscosity. Fluid Breaker The VES fluid can break to water-like viscosity by exposure to liquid hydrocarbons or dilution with reservoir brines. Additionally, a new encapsulated breaker has been developed for the zwitterionic VES described here. The encapsulated material uses a polyelectrolyte to disrupt the surfactant micelles and lower the fluid viscosity even in dry gas wells where there is neither brine nor liquid hydrocarbon to assist the breaking process. The effectiveness of this breaker has been measured in a series of proppant pack conductivity tests demonstrating greater than or equal to 95% retained proppant pack permeability. Laboratory Fluid Loss Measurements To model the fluid loss properties, the VES system was injected into 12-inch long sandstone cores at a constant driving pressure of 1000 psi. The cumulative fluid volume flowing into the core was measured as a function of time and the total fluid loss coefficient vs. permeabilities was plotted in Figure 3. Also shown in Figure 3 is the typical trend for total fluid loss coefficient of crosslinked polymer fluids. The results indicate that the fluid loss coefficient for the VES system is comparable to that achieved with crosslinked polymers.

Summary The theory describing a pseudo-three-dimensional (pseudo-3D) hydraulic fracturing model that solves the coupled fluid-flow and elastic-rock-deformation problem associated with a fracture propagating into a zone composed of three or more layers is presented. The fracture is initiated in the center layer. Fracture growth is formulated from the critical-stress-intensity-factor criterion, and fracture width is obtained from plane-strain elasticity solutions. Fluid fronts and proppant settling during fracture closure are tracked during the treatment. Fracture parameters obtained by this model show excellent agreement (6% maximum difference) with the solution given by a 3D simulator. Also, designs of hydraulic fracturing treatments depicting ways to minimize fracture growth and to optimize proppant distribution are described. The explicit expressions developed for modeling the fracture growth and fracture opening have reduced the complexity of the formulation and the computational effort. Introduction The coupled problem of fluid flow and elastic rock deformation associated with hydraulically induced vertical fractures in hydrocarbon-bearing reservoirs has been considered by many authors. Earlier work was based on lateral extension of fixed-height fractures. Constant-height models, particularly of the Perkins and Kern formulation, were subsequently extended to include vertical growth prediction. These models are known as the pseudo-3D simulators. Most of these models assume one-dimensional (1D) fluid flow in the direction of the length (no pressure drop in the vertical direction). This assumption is consistent with fractures in which the length is significantly greater than the height. Other models assume a modified pressure drop in the vertical direction on the basis of the pressure drop in the lateral direction. Three-dimensional hydraulic fracturing simulators were introduced in the literature during the last 9 years. Computational time for 3D modeling is comparable to a two-dimensional finite-element problem of equivalent mesh density, but run times become substantially high for elongated fractures (fractures with height-to-length ratios much smaller than one). Pseudo-3D formulation on the other hand, provides a significant reduction in computational effort and results in good agreement with 3D formulation for elongated fractures. The theory describing a pseudo-3D model including applications is described below. Hydraulic Fracturing Model The pseudo-3D formulation presented here models the fracturing phenomenon under the following assumptions. 1. All rock formations are assumed to behave as isotropic linear elastic materials. 2. Dominant fluid flow is in the direction of the length. 3. Modulus and stress contrasts between the pay zone and barriers are allowed. 4. Proppant settling during closure is considered. The linear-elastic-response assumption permits application of the principle of superposition to determine the combined effects of the stress contrasts, fluid pressure gradients, and formation pressure gradients in the fracturing mechanism. This principle is valid when the rock deformation caused by the fracture does not affect the magnitude of the far-field in-situ stresses (limited pumping times). Dominant fluid flow in the direction of the length is consistent with fractures that have height-to-length ratios smaller than one. For these fractures, the pressure drop in the lateral direction is much greater than that in the vertical direction. A vertical pressure drop estimated from the lateral pressure drop is used to prevent unstable vertical growth in fractures with height-to-length ratios approximately equal to one. The elastic solution for a crack crossing an interface 16 is used to determine the effects of modulus and Poisson's ratio contrasts. This effect is significant only for soft formations bounded by stiffer formationsi.e., coal formations bounded by higher-modulus sand-stones or shales. High-viscosity fluids have shown small settling velocities during pumping. Depending on the permeability of the formation, however, settling during closure can be significant. Settling velocities are computed with Novotny's equations. Description of the Fracturing Process. The injection of high-pressure fluids into the reservoir leads to fracture initiation followed by fracture propagation into the reservoir and, in most cases, into the bounding formations. This formulation models the fracture propagation process caused by localized failure of the near-crack-tip region. The extent of the fracture migration depends on fluid-induced pressures, the volume of fluid pumped, and the in-situ stress contrasts provided by the bounding layers. Fracture-Propagation Criterion. One fracture-growth criterion that describes rock failure states that fracture propagation occurs as the stress-intensity factor, K, at the propagating front (Mode 1 considered here) equals the critical stress-intensity factor. Kc. Vertical growth is calculated on the basis of this criterion. Lateral fracture growth is obtained by advancing the fracture in steps of constant length increments at variable times. The time increment is obtained on the basis of the volume-balance equations. Governing Equations. The equations defining pressure drop, vertical fracture growth, fracture width, fluid loss, volume, and mass balance for a discretized fracture in sections of equal incremental lengths and variable heights (Fig. 1) are described below. Pressure-Drop Equation. The pressure drop along an elliptical cross-sectional fracture for ID flow of a power-law fluid is given by the relation ,..............................(1) where, .............................(2) ,........................(3) p=fluid pressure above reservoir minimum in-situ stress (pf - p) determined at pay-zone center, q1/2=flow rate along length, w max = maximum fracture opening in cross section, fw = width function at x, H = fracture half-height, n' = fluid-flow behavior index, K'= consistency index for fluid, and Fc = factor defining correspondence between parallel plates and elliptical conduits. To prevent unstable, and unrealistic, vertical fracture migration from being predicted, a vertical pressure gradient, gv. is superposed on the lateral pressure to define the drop in pressure for the vertical flow: .........................................(4) SPEPE P. 69^

Summary A procedure to detect and to evaluate fracturing during waterflooding is described. The approach requires (1) use of a radial-flow analysis to detect changes in fluid transmissibility, (2) determination of the in-situ stress changes, caused by pore pressure buildup and temperature decrease, and comparison of the modified stresses with the bottomhole pressure (BHP), and (3) modeling of the fracture by means of a pressure (BHP), and (3) modeling of the fracture by means of a three-dimensional(3D) hydraulic fracture simulator. This procedure is applied to 30-day waterflooding injection into a limestone oil reservoir located in an offshore well within the Idd el Shargi reservoir (Qatar) in which fracture occurrence was suspected. Both the radial-flow analysis and the quantification of stress changes indicated the occurrence of fracture. Finally, the resulting fracture geometry was delimited by simulation of the fracturing process. Introduction Injection of water or other fluids into a reservoir for relatively long periods of time can alter the in-situ state of stress by decreasing the formation temperature and increasing pore pressure. Depending on the injection history and on the injected fluid and reservoir temperature, these changes can have an effect on the in-situ state of stresses that is sufficient to give rise to fracture onset. Perkins and Gonzales and Marx and Langenheim used an energy balance method to determine the reservoir temperature profile and the elasticity theory to quantify the resulting in-situ stress changes. Similarly, the elasticity theory was used to quantify stress changes caused by the pore pressure buildup. With the assumption of a linear elastic model, the stress changes calculated can be superposed on the undisturbed state of stresses to determine the modified closure stresses. Comparison of these stresses with the bottomhole fluid pressures may be used to estimate fracture onset. Alternatively, a radial-flow analysis can evaluate changes in formation transmissibility, kh/mu, relative to the value at the initial stages of injection. Changes in kh/mu would indicate changes in reservoir conditions caused by formation fracturing or formation damage. This work describes the detection of a formation fracture in a 30-day waterflooding experiment. This approach (1) uses a radial-flow analysis to determine changes in fluid transmissibility, (2) determines the changes in insitu stresses caused by changes in pore pressure and temperature and compares the modified stresses with the bottomhole fluid pressures, and (3) models the fracture geometry resulting from the injection of fluid after fracture onset. Description of the Waterflooding Experiment. The waterflooding test consisted of a 30-day filtered seawater injection into two perforated formations defined as Zones A and B of an oil-bearing limestone reservoir located offshore near the west coast of the Persian Gulf (Fig. 1). Zone A is 103 ft [31.4 m] thick while Zone B is 63 ft [19.2 m] thick. The average porosities for both zones were approximately equal ( =27%), while the average permeability for Zone A (k=2.21 md) was higher than for permeability for Zone A (k=2.21 md) was higher than for Zone B (k=0.87 md). Before injection, in-situ stresses were measured at several depths along the wellbore, as shown in Figs. 1 and 2. The injection test was conducted at three levels of constant tubing-head pressures (THP). The initial THP of 990 psig [6826 kpa] was increased to an intermediate step of psig [6826 kpa] was increased to an intermediate step of 1,240 psig [8550 kPa], and finally to a pressure of 1,490 psig [10 273 kpa]. Plots of the recorded injection rates psig [10 273 kpa]. Plots of the recorded injection rates and THP vs. time are displayed in Fig. Recordings of BHP's indicated negligible friction drop. Except for some interruptions (i.e., acid wash and pump malfunctions), pumping was continuous. The injected seawater pumping was continuous. The injected seawater temperature (110 degrees F [43 degrees C]) was approximately 51 degrees F [11 degrees C] lower than reservoir temperature (161 degrees F [72 degrees C]). A comparison of injectivity indices calculated from spinner surveys before test completion with expected injectivity indices obtained from kh values indicated 70% greater-than-expected injectivity for Zone B and 15% smaller-than-expected injectivity for Zone A. These differences led us to suspect the occurrence of a fracture growing predominantly into Zone B and extending into Zone A where the smallest closure stresses were measured. Flow Rate Analysis. The system of concern is a single well with an inner moving seawater bank displacing an outer oil bank. In this system, a radial-flowrate analysis would provide an indication of changes in the kh/mu with changes in the reservoir conditions. JPT P. 1113

Geological and mechanical laboratory experiments were conducted on several core samples in order to characterize the material behavior and generate data for the design of hydraulic fracturing treatments for high-permeability formations. Photomicrographs of thin sections were used to classify the specimens according to their granular constitution and petrographic components.The results of evaluations of fracture toughness, permeability, porosity, static and dynamic Young's modulus and Poisson's ratio are presented. Based on linear regression analysis, correlations relating static to dynamic Young's modulus were derived. The error between the predicted and measured values was minimized by dividing the samples into three porosity groups.References and illustrations at end of paper. 467

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