TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractHigh performance foamed fracturing fluids are required to enhance cleanup during applications in low permeability, low pressure gas reservoirs and mature, depleted hydrocarbon reservoirs. Moreover, accurate foamed fluid rheological properties, obtained under field conditions, are necessary to enable complex fracturing treatments to be executed successfully. Standard laboratory tests used to evaluate properties of foamed fluids include the foam half-life measurement and the characterization of the water-based polymer fluid rheology that serves as the external aqueous phase of the foam. These tests are generally limited by the absence of CO 2 . In addition, the rheology tests are commonly performed with the pH of the water-based fluid adjusted with acid to a value consistent with that expected for CO 2 foam under reservoir conditions. This study evaluates the relevance of conventional laboratory tests in indicating the performance of CO 2 foam fracturing fluids formulated with linear and zirconate crosslinked carboxymethylhydroxypropyl guar (CMHPG) polymer. Specifically, the effects of the water-based polymer fluid pH, crosslink delay and corresponding shear sensitivity, temperature, and foam quality are evaluated under typical conditions encountered in a fracture.Relatively new capabilities to measure pH in the presence on CO 2 under highpressure (up to 1,500 psig) and high-temperature (up to 280 o F) indicate pH values in the range of 3.5 to 4.1 for CO 2 foam under down hole conditions. Results demonstrate that the common practice of performing Model 50 rheology tests with water-based polymer fluids adjusted to low pH to simulate the effects of CO 2 are not indicative of CO 2 foam fluid performance, as the foam viscosity was not dependent on the crosslink delay or crosslink pH. Furthermore, standard shear history tests with zirconate-crosslinked CMHPG fluids did not correlate well with foam performance at qualities greater than 52% CO 2 . This work demonstrates the conditions under which CO 2 foam rheology is dominated by foam properties versus water-based polymer fluid properties.

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Hydraulic fracturing treatments in unconventional (coalbed and carboniferous shale) natural gas wells have been successful in stimulating gas production. However, the wells often do not perform up to potential following the treatments for various reasons. Some of the factors that can contribute to the relatively poor performance include low coal or shale permeability, complex cleating and natural fracture networks, gas content and adsorption characteristics, water content, and fracturing fluid interaction with formation surfaces. Fracturing fluid damage in coal formations has been shown to cause significant reductions in permeability, and whole gel leakoff into the cleat networks can further impair production. The same damage mechanisms can impair the production of carboniferous shale formations. To avoid the damage associated with polymer-based fluids, a coal/carboniferous shale-compatible solids-free (CCSF) fluid was developed for unconventional natural gas well applications. The CCSF fluid is a nitrogen-foamed fluid that was designed to be environmentally friendly to minimize risk to ground water that could be contacted during fracturing treatments. This study investigates the effects of various hydraulic fracturing fluids including conventional polymer-based fluids, water containing friction reducers, and a coal/carboniferous shale-compatible solids-free fluid on coal and shale pack cleanup. Laboratory coal pack cleanup tests demonstrate a significant reduction in retained permeability with polymer-based fluids. In addition, a high cleanup factor (a parameter introduced to provide a measure of the pressure and time required for cleanup) is required to establish only marginal flow conditions with brine injected in the production direction. Even water containing low concentrations of friction reducer may result in less than 50% retained permeability. The CCSF fluid provides 70 to 100% retained permeability and a low cleanup factor for effective coal pack cleanup with coal samples from seven coal basins in North America. Similar improvements were observed with carboniferous shale pack cleanup tests. Field case histories in coal and carboniferous shale formations are consistent with laboratory observations and demonstrate a dependence of fracture cleanup on retained permeability and the cleanup factor measured in the laboratory. Production results demonstrate a 30 to 60% increase in production with the CCSF fluid compared to conventional fracturing fluids in coal and carboniferous shale basins in the United States. Introduction Unconventional natural gas reservoirs include coalbed natural gas (CBNG) and carboniferous gas shales (GS). The commercial extraction of methane from subsurface coal seams and fractured carboniferous shales through rotary-drilled wellbores has entered its third decade. Worldwide estimates of unconventional natural gas reserves from CBNG and GS range from 3,500 to 9,500 Tcf, and anywhere from 1,000–3,000 Tcf likely exist in North America alone (Figure 1). From these estimates, it is easy to postulate that CBNG and GS could be a significant source of clean-burning energy. There are two main differences between conventional sandstone formations and unconventional CBNG and GS formations. First, unlike conventional sandstone formations, where natural gas can be trapped and stored in the pore spaces within the matrix, CBNG reserves are adsorbed onto the coal surfaces. That is, coal does not require a structural or stratigraphic trap to store natural gas. The gas remains adsorbed in the coal surfaces unless the surrounding pressure is decreased below a critical point. As a result, the potential natural gas storage capacity of coal can be as much as five times higher than that possible in sandstone formations, especially when the formation pressure is below 2,000 psi.1,2

Acid fracture conductivity experiments provide information valuable to effective design of acid fracture stimulation treatments in carbonates. They are complex tests, and a number of procedural details must be taken into consideration in order to upscale results to an adequate representation of well-scale acid fracture behavior for well productivity predictions. This paper focuses on a study performed on analog, quarried limestone core samples and a small number of reservoir core samples from the Unit 2 formation of Kazakhstan's Tengiz field to understand the impact of different acid fluid systems and procedural steps on acid fracture conductivity. The physical structure of the etched channels is observed to be impacted by the nature of the fluid and has a strong impact on the conductivity. The quality and uniformity amongst the core samples has a critical impact on the measurements and is assessed. The residence time of the acid in the acid-etched experimental channel is small, and the equivalency of acid volumes injected at the experimental scale to the large acid volumes injected into a well-scale fracture channel is considered. Special consideration is given to the procedure of applying stress to and measuring conductivity of the experimental acid fracture channel which may result in large-scale mechanical failures of the core sample, preventing a high-quality measurement of conductivity following injection of a closed fracture acidizing stage. This body of work discusses the design options and challenges which play a role in defining the testing strategy for an acid fracture conductivity study. Results demonstrate that with selection of appropriate fluid systems, acid fracture conductivity can be retained up to a closure stress of 6,000-7,000 psi in the Tengiz Unit 2 reservoir. A modified stress ramp-up procedure to improve closed fracture acidizing conductivity testing results obtained through the testing program is presented.