High-quality emulsion of carbon dioxide (CO2) in aqueous alcohol-based gel (CO2 emulsion) was introduced into the Western Canadian Sedimentary Basin (WCSB) as a fracturing fluid in 1981. Since that time, the use of the fluid has been very successful, particularly in low-pressure, tight gas applications. The fluid has all the advantages of conventional high-quality CO2 foams/emulsions, with the added advantage of minimizing the amount of water introduced into the well. The present paper will discuss a fluid that is an emulsion of liquid carbon dioxide in a base fluid of aqueous methanol. The discussion will include chemistry, rheological evaluations, and successful field utilization of these fluids in the Western Canadian Sedimentary Basin over the last decade. Introduction With ever-increasing need for resources world wide, the industry continues its trend to exploit gas reservoirs with ever-lower permeabilities. Very low-permeability reservoirs are typically in a state of capillary under-saturation, where the initial water and sometimes hydrocarbon saturation is less than would be expected from conventional capillary mechanics for the pore system under consideration (1). These formations are also called desiccated or dehydrated formations and have been known to exist all over the world. Introducing an additional immiscible phase, or increasing the existing phase saturation within porous media, can substantially damage permeability and relative permeability to hydrocarbons. This phenomenon is commonly described as aqueous or hydrocarbon phase trapping, depending on the situation underconsideration. The most common technique for preventing these problems involves eliminating the use of water-based fluids. Even fluids with very low fluid loss (to minimize invasion depth into the formation) may be susceptible to countercurrent spontaneous imbibition effects in desiccated reservoirs. The most successful means of mitigating these effects has been to use interfacial tension-reducing agents (e.g., mutual solvents or surfactants), or miscible gases such as carbon dioxide or LPG. When translated to fracturing fluids, this involves developming fluids that utilize the above mentioned agents in a non-damaging way. The use of CO2 as an energizing medium for fracturing fluids is an old concept (2). The concept of high-quality foam as fracturing fluid has also been previously reviewed (3). Bennion has discussed the use of methanol and CO2 to minimize and remove damage in low-permeability gas reservoir (4). Thus, a natural extension of these concepts is to combine all the benefits of these fluids, i.e., develop an emulsion fluid that uses high-quality CO2 (80 Mitchell quality or higher) with 40% methanol in place of water in the external gel phase. Properties of Methanol and use in Fracturing Fluid Formulations Methanol has some attractive properties that make its use in fracturing fluid formulations attractive (5). Using 40-% methanol in water lowers the surface tension of water from 72 dynes/cm to around 40 dynes/cm, the freezing point from 0 oC to -40 oC, the specific gravity from 1 to 0.95. At the same time, the vapor pressure of water is increased from 17.5 to 46.5 mm of Hg at 20 oC and from 150 to 300 mm of Hg at 60 oC, which helps in recovering the fluid. Likewise, the fluid viscosity goes up by 60% when methanol is added to water at a concentration of 40%. A 40% methanol-containing aqueous system can be gelled with several polymers including conventional hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar (CMHPG) and polymers used to viscosify pure methanol (5,6). Figure 1 displays the viscosities of the various polymers in 40% methanol. These gels are compatible with both liquid and gaseous CO2 without precipitation.

Fracture stimulating horizontal wells is challenging using traditional workover methods. Running perforating guns in the horizontal well section, performing a fracture treatment, running a bridge plug, and then pulling or milling all the plugs has shown to be an extremely time consuming and expensive operation. An option using coiled tubing was proposed in China to improve on operational efficiencies.Multiple zone completions using coiled tubing has traditionally used a straddle cup tool. This has proven effective for fracturing multiple zones in shallow environments. The drawback to this method is high pumping friction due to the small inside diameter of coiled tubing. With wells reaching ever greater depths and higher deviations, the multiple zone fracturing method using coiled tubing and straddle cup tools becomes unfeasible. A coiled tubing method using the larger area annulus was investigated and subsequently recommended for performing fracture treatments in deeper and/or horizontal wells.The annular fracturing process involves first perforating by utilizing a coiled tubing sand jetting procedure and then pumping the fracture treatment through the coiled tubing by casing annulus. Following the fracture treatment, an ultra light weight proppant plug provides effective zonal isolation from the lower frac. The process is then repeated from the toe to the heel of the horizontal wellbore for the required number of fracture treatments. A sand cleanout at the end of the last fracture treatment removes sand isolation plugs. The method can quickly fracture stimulate a large number of sections in a horizontal wellbore with an easily removable isolation system.Results to date have been improved well productivity and decreased workover time compared with traditional frac and plug methods in horizontal wells. A field wide case study is examined to discuss design criteria, job execution, improvements, procedures and results. As the world moves to deeper and more complex wellbore trajectories, this technique is a viable method for horizontal or deep well stimulation.

Horizontal completion technology has progressed dramatically over the past decade with the latest single trip ball actuated sliding sleeve fracturing technology becoming widely accepted by the oil and gas industry. These horizontal completions have allowed multiple zones to be fractured and then produced very quickly compared to standard conventional methods. This completion technique isolates and allows specific placement of fracture stimulation treatments at multiple desired intervals along the well. Operational efficiencies have been realized by eliminating cementing, perforating, and by improving stimulation operation efficiency by pumping all fracturing treatments successively (Miller et. al. 2008, Hlidek et al. 2011, Johnson et. al. 2010.Rising natural gas consumption in China coupled with higher depletion rates of new and existing reserves are creating increasing demand. This demand has driven the need to increase exploration and development of low permeability fields. With continued development in these low permeability formations around the world, horizontal wells with continuous stage fracture stimulations have become increasingly used for both unconventional and tight formation reservoirs. Case studies involving four areas of China with a total run history of 79 wells will be examined. These areas include Daqing in Northeast China, Sulige in the Northwest Ordos basin, Sichuan basin, and a tight oilfield in Shandong province. Each field has had separate independent challenges including H 2 S gas, CO 2 gas, reservoir heterogeneity, low and ultra low permeability, low reservoir pressures, and high fracture gradients. Both propped fracture treatments and acid fracture treatments have been executed with the system and the applications will be discussed.

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