New Brunswick Canada's first commercial unconventional gas field, the McCully field, is located near the town of Sussex in southern New Brunswick. The field is comprised of low permeability Hiram Brook sandstones as well as the underlying Frederick Brook shale. The McCully field started producing gas from the Hiram Brook in April 2003 from two wells and was followed by full production in June 2007. Currently there are twenty-nine wells producing from the Hiram Brook. The Frederick Brook shale was placed on production in March 2008 and is producing gas from one hydraulically fractured vertical well. Additional wells have been drilled, hydraulically fractured and flow tested to further evaluate the development potential of the shale. Prior to 2009, development of the McCully field has included the use of water based hydraulic fracturing to enhance production. In 2009 a fracture program based on using LPG as the fracture fluid was undertaken. Both the Hiram Brook sands and the Frederick Brook shale have been hydraulically fractured with LPG and the results have been compared to the performance of the water based fractures performed in the past. It has been found that both clean up and initial well performance for these tight sands were significantly enhanced using LPG fracs rather than water fracs. This paper compares the clean up performance and the initial flow performance for wells fractured using the two fracturing methods.

Unconventional gas reservoirs, including tight gas, shale gas and coalbed methane, are becoming a critically important component of the current and future gas supply. However, these reservoirs often present unique stimulation challenges. The use of water-based fracturing fluids in low permeability reservoirs may result in loss of effective frac half-length caused by phase trapping associated with the retention of the introduced water into the formation. This problem is increased by the water-wet nature of most tight gas reservoirs (where no initial liquid hydrocarbon saturation is, or ever has been, present) because of the strong spreading coefficient of water in such a situation. The retention of increased water saturation in the pore system can restrict the flow of produced gaseous hydrocarbons such as methane. Capillary pressures of 10 to 20 MPa or higher can be present in low permeability formations at low water saturation levels. The inability to generate sufficient capillary drawdown force using the natural reservoir drawdown pressure can result in extended fluid recovery times, or permanent loss of effective fracture half-length. Furthermore, use of water in subnormally saturated reservoirs may also reduce permeability and associated gas flow through a permanent increase in water saturation of the reservoir. Secondary costs, such as rig time for swabbing, can add to the negative economic impact. Gelled liquid petroleum gas-based fracturing fluids are designed to address phase trapping concerns by replacement of water with a mixture of liquid petroleum gas (LPG) and a volatile hydrocarbon fluid. Once the well is drawn down for flowback, some of the LPG portion of the fluid may be produced back as a gas, dependent upon temperature and pressure. The remaining LPG remains dissolved in the hydrocarbon fluid and is produced back as a miscible mixture using a methane drive mechanism. By eliminating water and having LPG as up to 80 - 90% of the total fluid system, cleanup is greatly facilitated, even in wells having very low permeability and reservoir pressure. The effects of fracturing fluid retention on gas flow in the fracture face can be as important as fracture conductivity when designing a treatment. It is possible to have a conductive fracture with good half-length in the desired productive zone and still not realize economic or optimum gas production if phase trapping and/or relative permeability effects are restricting gas flow. Description Gelled LPG-based fracturing fluids are a unique hydrocarbon-based fracturing fluid system designed for gas well stimulation. They use up to 100% gelled LPG for the pad and flush. The sand slurry stages use a mixture of up to 90% LPG with the balance of the volume being a volatile hydrocarbon-based fluid. All chemicals and proppant are added to the base fluid at the blender. LPG, which composes the balance of the downhole fluid volume, is injected at the wellhead where it forms one miscible mixture with the base oil. It is important to note that under pumping pressures, this is a single-phase gelled fluid system, similar to gelled oil in rheology, friction pressures, proppant transport and leakoff control.

Summary Point-source perforating has reduced fracture-stimulation expenses in the south Texas Lobo trend. Although the producing intervals frequently exceed 100 ft, the operator typically perforates the bottom 5 ft of the interval. Data collected during perforating are used to design optimized fracture-stimulation treatments. The optimized treatments average 55% less proppant than the jobs designed previously with conventional practices that had perforations across the entire pay interval. The new well's initial production and sustained performance has been higher than conventionally stimulated wells of similar potential. In addition, the point-source-perforated wells have produced significantly less proppant than similar wells with perforations across the entire pay interval. Point-source perforating has reduced the cost of perforating, proppant, fluids, equipment rentals, and cleanup. This case-history paper presents the following.Historical account of previous completion practices (limited entry, multiple-stage fracturing, and full-zone perforating).Discussion of the "perforating for stimulation" fracturing technique currently used.Comparison of production results.Formation-evaluation methods (logs and bottomhole gauges).Perforating methods (phasing, charges, and perforating interval selection).Results from a recompletion confirming that depletion has occurred. Introduction Perforating is a key component to the completion of most wells. Typically, the decision made about where to perforate is based on the location and the extent of the pay. The process of perforating is usually limited to choosing the appropriate gun with the best performance and scheduling the job. In the overpressured, low permeability environment of south Texas, a new perforating philosophy has been adopted, in which "perforating for stimulation" is the practice instead of "perforating for production." This new concept places the emphasis on the best perforation method for stimulation and obtains key fracturing parameters during the perforating stage of the completion. Experience shows that commonly accepted perforating techniques can cause well-designed stimulation treatments to fail. Cost Savings The operator has drilled approximately 150 Lobo wells over the last 5 years in the south Texas counties of Webb and Zapata. The experience gained over this period has reduced completion costs by U.S. $125,000 per well. These savings are derived from an overall change in the stimulation philosophy and the ensuing procedural changes this new philosophy created. Lobo Geology The Lobo formation is a member of the lower Wilcox group and has produced approximately 8 trillion ft3 of gas from two south Texas counties. The Lobo is a low-permeability, geopressured sandstone that was subjected to massive slump faulting at the end of its deposition. This created abundant faulting within the Lobo trend to the degree that individual blocks were created, usually 80 acres or less. This is a significant factor because each well is its own reservoir. Table 1 lists the typical reservoir parameters. Initial Development Consolidated Oil and Gas discovered the Lobo trend in 1973 with the N.H. Clark No. 1.1 Because of the complex structural nature of the Lobo and poor fracturing techniques, its full potential was not immediately realized. A major geological breakthrough occurred with the introduction of 3D seismic in the early 1990s. Two-dimensional seismic was used previously but resulted in a 72% success rate. With the introduction of 3D seismic, the success rate improved to 92%. Also, improvements in fracturing equipment, breakers, completion procedures, and 3D fracturing models have been significant factors in making the Lobo trend economic. Past Practices In the past, completion strategy was based on perforating every productive foot of pay derived from log analysis. Attempts to stimulate entire intervals were accomplished with large pad volumes, low Ottawa sand concentrations, and limited use of effective breakers. After the treatment, the wells were shut in overnight to allow the bottomhole temperature to break the thick, crosslinked gels. In later years, it was realized that all perforated layers were not being stimulated. The use of limited-entry perforating became popular in an attempt to stimulate the entire perforated section. This method limited the number of perforations to create excess perforation-friction pressure. In theory, this would increase the bottomhole treating pressure to greater than the pressure necessary to break down higher-stress zones, thus distributing the stimulation treatment to all perforated horizons simultaneously. The shortfalls of both these methods were recognized when cumulative production did not match predrill volumetric estimations. The next method involved limiting the treatment interval to one of the three primary Lobo sands and performing individual treatments on each sand package. This method showed improvements but still lacked the optimum results. Observations and a New Concept The factors leading to the new concept of "perforating for stimulation" were conceived from production-log results, the lack of success in adding perforations, tracer surveys, and information provided in the advance-stimulation technology work done by Aud, Wright, Holditch, and others.2 In an effort to better understand the completion effectiveness, production logs were run on a selected group of wells. The most revealing information was that the majority of the production usually came from a small interval, which was the best pay. Fig. 1 shows a production log from a hydraulically fractured well with the entire 100-ft interval perforated. More than 90% of the 1,800 Mcf/D was entering from only a 5-ft interval.

Previous studies (1)(2)(3)(4) described the theory and application of CO 2 miscible hydrocarbon fracturing fluids for gas well stimulation. These fluids are ideally suited to gas reservoirs susceptible to phase trapping resulting from high capillary pressures when water-based fluids are used. Gas reservoirs particularly prone to phase trapping are those with in situ permeability less than 0.1 mD, those with initial water saturations less than what would be expected from normal capillary equilibrium (subnormally water saturated) and those that are under pressured. Such reservoirs represent a growing proportion of the market. This, combined with increased gas prices, creates a strong need for an optimized gas well fracturing fluid system.Hydrocarbon-based fracturing fluids present an ideal solution to phase trapping concerns associated with water-based fluids provided the hydrocarbon fluid can be effectively and quickly removed from the formation after the fracturing treatment.This paper investigates in more depth what constitutes an ideal hydrocarbon-base oil for this application. This involves consideration of many factors including cleanup mechanisms, safety, cost and capability to be gelled and broken.In order to meaningfully evaluate fluid clean up, regained core permeability evaluations must be conducted by accurately duplicating downhole conditions. This paper presents testing methodologies designed to achieve this goal.To illustrate the need for these methodologies, the applicable phase behaviour and fluid displacement mechanisms by which these fluid systems operate are discussed. Topics covered will include:• Methane drive fluid recovery mechanism involving the use of CO 2 with hydrocarbons and resulting effect on interfacial tension (IFT). • Secondary recovery mechanism based on vapour pressure of light hydrocarbons resulting in their being produced back in the gas phase with methane. • Application of these concepts to address phase trapping in low-permeability gas reservoirs and how these effects are accentuated in formations that may be subnormally water-saturated, have low reservoir pressure or have low permeability.

Previous publications(1–4) described the theory and application of CO2 miscible hydrocarbon fracturing fluids to gas well stimulation. The fluids are ideally suited to gas reservoirs susceptible to phase trapping due to high capillary pressures when waterbased fluids are used. Reservoirs particularly prone to phase trapping are those with low permeability (less than 0.1 md), those that are subnormally water-saturated, and those that are under pressured. In order to conduct meaningful rheological evaluations for etermination of fluid properties and required chemical concentrations, it is essential that downhole conditions be accurately duplicated. The most fundamental requirement is that the gelled hydrocarbon and liquid CO2 be combined and homogenized below the critical temperature of CO2 (31 °C) and at a pressure above the bubble point of the resulting fluid mixture to ensure one miscible phase. This normally requires a minimum initial pressure f at least 20 MPa. Temperature is increased to the bottomhole static temperature of the well under consideration as the test progresses. This requires that the rheometer have a pressure rating high enough to withstand the increased pressure caused by expansion. This paper presents several different testing methodologies designed to provide representative rheology vs. time with all chemicals present, and to provide varying insights into fluid behaviour. The first utilizes a conventional bob and sleeve configuration in a heated pressure chamber rated to 102 MPa and 204 °C(5). This allows one to gather shear stress vs. shear rate data as a function of time. Normal Power Law n' and k' parameters are calculated and are in turn used to calculate apparent viscosity vs. time. Secondary mixing is provided by a helical fin attached to the outside of the sleeve, which creates a rotational flow pattern in the rheometer. The second methodology utilizes a capillary tube viscometer allowing for precise and accurate control of the shear rate. The capillary tubes used are capable of 68 MPa at 204 °C and are sized according to the expected viscosity range and range of desired shear rates. The fluid of interest is displaced through the tube using a push-pull system of two positive displacement syringe (Ruska) pumps?one in injection and one in extraction mode to keep the system pressure at the desired level. Varying the injection rate allows one to vary the shear rate as desired. Shear stress vs. shear rate data are collected as a function of time, again allowing normal power law parameters as well as apparent viscosity to be calculated. The third methodology uses an oscillating (sinusoidal) strain. The resulting stress has an elastic component and a viscous component. G' is the elastic component and can be thought of like a spring constant. A Newtonian liquid has no storage modulus (G'). Elastic behaviour is important for suspending proppant at low shear rates. This methodology therefore provides insights into fluid behaviour that complement those obtained using shear stress vs. shear rate measurements.