Summary The use of CO2 as an energizer in hydraulic fracturing fluids has increased dramatically in the past few years. The history of CO2 usage for this application is discussed briefly, and CO2 is compared with the other commonly used energizer, N2. The design considerations for using CO2 in a fracturing treatment, both as a minor (energizer) and a major (foam) component, are presented. Special consideration is devoted to CO2 foam because CO2 is pumped as a compressible liquid that changes to a gas downhole. This paper presents the calculations required to estimate the surface liquid CO2 volumes and injection rates needed to obtain the desired downhole foam properties. Also, the instrumentation required to meter the liquid CO2 safely and accurately is discussed. Field results further evidence CO2's utility in hydraulic fracturing. This discussion includes a comparison of fracture stimulation with and without CO2 as an energizer as well as treatments that compare CO2-energized fluids with N2-energized fluids. Economic considerations of pumping CO2 vs. N2 vs. no energizer are discussed. Conclusions suggest pumping CO2 vs. N2 vs. no energizer are discussed. Conclusions suggest what further study is required to help improve design techniques and when CO2 should be considered as a component of a fracture stimulation treatment. Introduction The practical use of CO2 in stimulation fluids was developed in the early 1960's. In 1962, Bleakley reported the results of 50 successful fracture treatments that contained CO2 and described the operating procedures required to handle CO2 safely. These early treating fluids were foams and CO2 commingled with water. As carbonated fracturing fluids gained popularity, researchers began studying the properties of these fluids to improve treatment designs. An early investigation to characterize CO2 base fluids was conducted by Niel et al., who reported the following:foaming additives with CO2 gives better recoverability than with N2;no measurable corrosive effects were produced by fluids that contained CO2;CO2 buffers the pH of aqueous systems to about 3.5, which helps control swellable clays; andfluids containing CO2 exhibited greater leakoff. Several teams of investigators have studied the fluid properties of foams. An early work by David and properties of foams. An early work by David and Marsden proposed a practical rheological model for foam. The laboratory setup required for the evaluation of dynamic fluid properties for foams was discussed by Wendorff and Earl. Reidenbach et al., compared the actual properties of N2 - and CO2 - based foams and concluded that these fluids exhibit very similar laminar rheologies. Also, Harris demonstrated that N2- and CO2-based foams exhibit similar dynamic fluid-loss properties that can be enhanced by the addition of polymers to the aqueous phase. To predict surface treating pressures accurately, Blauer et al. studied the friction loss of foams in laminar, turbulent, and transitional flow regimes in tubing. Their investigation revealed that foam behaves as a single-phase pseudoplastic fluid whose effective viscosity must be used pseudoplastic fluid whose effective viscosity must be used to calculate pressure loss for flowing foam. The friction loss for any foam may be determined as for a single-phase fluid with conventional Reynolds numbers and a Moody diagram. The use of CO2 in fracture stimulation treatment yields several benefits. CO2 provides faster and increased load recovery; helps control clay swelling by buffering aqueous fracturing fluids to a pH of 3.5; replaces some of the water in the treatment, thus reducing the volume of water to be recovered; can be used to formulate highly efficient fracturing fluids that effectively transport proppants; and can be metered accurately. Although the in-situ properties of carbonated fracturing fluids are well documented, little work has been performed regarding the surface handling of CO2 so that the desired downhole concentrations are attained. The actual pumping and metering of CO2 is somewhat more complex than N2 because of its different phase behavior and chemical activity. A method for accurately metering the liquid CO2 at surface conditions and conversion to in-situ volume are discussed. Also, some specialized instrumentation that supports these processes is presented. First, however, a review of the physical presented. First, however, a review of the physical properties of CO2 is in order. properties of CO2 is in order. Physical Properties of CO2, Physical Properties of CO2, At ambient conditions, CO2 exists as a colorless, nontoxic, dense gas. when the gas is compressed and cooled, a stable liquid is formed. CO2 is delivered to the oil field as a liquid in 20-ton [18-Mg] loads at temperatures of 0 to -20F [-18 to -29C] and pressures of 200 to 300 psi [1.38 to 2.1 MPa]. Fig. 1 is a phase diagram that shows the pressure and temperature conditions at which CO2 exists as a solid, liquid, or gas. SPEPE P. 351

controlled-release matrix form has successfully prevented paraffin deposition.. Paraffin-related problems occur in almoet all oil producing areas throughout the world. These

The Morrow formation is one of the main targets of the drilling activity in Southeast, New Mexico. This paper presents background information including formation lithology derived from X-Ray diffraction data and scanning electron micrographs. Formation rock characteristics such as frac gradients, permeability, porosity and formation water properties are also presented. Completion techniques such as cementing practices, casing programs and perforating programs are reviewed. The stimulation fluids, volumes, injection rates, and types of proppant used are presented to provide an optimum completion program.

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The effect of sand handling equipment on the quality of propping sand has been investigated. Early results have indicated that sand size is not significantly changed on its trip from the supplier to the wellhead. In addition, conductivity tests on 20/40 prop sand indicates some particle size variation from current specifications can occur without causing significant reduction in conductivity. Introduction In recent years, the quality of propping sand has become increasingly important. The search for adtional oil and gas reservoirs has caused the industry to explore deeper horizons and expand the development of marginal producers. Both have had an important impact on increasing the use of proppants. Production from deeper zones has taxed the ability of Production from deeper zones has taxed the ability of sand to serve as a prop, resulting in higher strength materials, such as bauxite, being used in critical wells instead of sand. However, sand can be used successfully for propping fractures in wells of moderate depth, provided it is high quality sand. Reservoirs that were considered marginal producers a few years ago are commercial producers today due to the improvements have greatly increased the amount of prop sand used per well. With significantly larger treatments, higher flow capacity of the fracture is needed to give effective drainage. Again, larger amounts of high quality sand have been necessary to achieve this goal. The search for high quality prop sand has resulted in the production of sand from two sources. The first source is the St. Peters sandstone, which underlies second source is the Hickory sandstone underlying areas of Central Texas. The majority of sand used in propping fractures has come from these two formations. propping fractures has come from these two formations. The quality of sand loaded into rail cars and trucks has long been required to meet minimum specifications. These specifications control particle size within narrow limits and insure freedom from nonquartz contaminants. While the quality of sand at the supplier has been known and controlled for years, the quality of sand at the well site has recently been under closer scrutiny because of the greater need for high quality sand. This has led to several questions: How should sand be sampled so that samples are truly representative? How is prop sand affected by the handling and transportation it is subjected to prior to injection into the well What effect do these changes have on the fracture conductivity of the prop sand? In order to answer these questions, we followed rail car and truck loads of sand from the supplier to the well site. Samples of sand were taken at each transfer point and analysis of the samples were made to show any changes in particle-size distribution. While the field-sampling program was underway, fracture conductivity testing was done to study the effect particle-size distribution has on sand permeability at increased overburden stresses. permeability at increased overburden stresses. A statistical approach was used in which a baseline particle-size distribution was developed by sampling sand as it was loaded into several rail cars and trucks from a single supplier of 20/40 Hickory sand, Rail cars and trucks from the same supplier were sampled as they were unloaded into sand sites at several different districts storage sites. Districts were chosen which received sand from only one supplier. The last samples were taken as the sand was transferred from the transport into the blender at the well. SAMPLING AND SIEVE ANALYSIS In all cases, samples were taken from a moving stream of sand. The scoop and sampler shown in Fig. 1 and described in ASTM C-429-72 were used for sample collection. Both were sufficiently large to collect samples from the full width of the sand stream.