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When the word "shale" is included in the name of a formation, a high-rate water frac is often instantly assumed to be the correct choice for hydraulic fracture treatment. This is because high-rate water fracs are the common treatment in the Barnett shale in northeast Texas, and that is the shale reservoir with which industry professionals are most familiar. When a new shale development, such as the Eagle Ford shale in south Texas, is discovered, engineering tends to take a back seat, and a high-rate water frac is often the initial treatment design chosen simply because that is what has been done in the Barnett. Reservoir understanding acquired from core analysis, geomechanical tests, formation evaluation, proppant-embedment testing, stress analysis, and other data are sometimes ignored in the design process.This paper discusses the thought process that engineers are encouraged to follow when deciding what type of completion should be used to fracture stimulate a shale reservoir (water frac, hybrid, or conventional). Considerations, such as the type of hydrocarbon that is expected to be produced, fracture complexity of the reservoir, lithology and mineralogy of the rock, and other reservoir parameters, should be included as part of the completion design. To close the loop, the production also should be evaluated to make good engineering-design changes as the asset is developed. Quantifiable analysis of a stimulation treatment in a horizontal well can be a daunting task because of the complexity and lack of data. Production analyses for several stimulated wells are presented. This application can be directed toward any horizontal completion in low/ultra-low permeability reservoirs and can be performed in a timely manner. The immediate goal of this process is to determine a qualitative measurement of stimulation effectiveness; the eventual goal is a quantitative tool.

Technology Update Horizontal shale wells present the challenge of generating large, high-density fracture networks, reflecting the submicrodarcy permeability of the formations drilled by these wells. The goal is to create the largest fracture network volume to maximize ultimate recovery, because the fracture network volume in these wells has been shown to correlate strongly with the production level. However, as the network becomes too large for a given wellbore access point, the relative benefit of size diminishes. This is because of the low fracture conductivity, which creates large pressure drops within the network and makes it difficult to drain distant portions. And the effect is exacerbated by the inability to move water or liquid hydrocarbon through a large complex network (Mayerhofer et al. 2006). Thus, it is very important to create an optimal number of conductive transverse fractures or access points that intersect the wellbore. Today’s unconventional wells incorporate wellbore planning and completion designs that are based on the reservoir-specific characteristics needed for optimal drainage and field development. The key elements of the design and planning process must be carefully considered. They are well spacing, lateral length, the number of stages, the length of isolated stages, and the number of perforation clusters per stage. The strategies used are based in part on advancements in reservoir simulation, reservoir modeling, and production correlations from trial and error that stem from the initial work in various plays, except the relatively unique Barnett shale. Progress in Shale Completion Designs A good example of this progression toward more reservoir-specific completion designs was seen in the Haynesville shale. The play saw a rapid rampup in activity from 2009 to 2012 with peak completion activity occurring in mid-2011. By November 2011, it had reached its highest production level of 7.2 Bcf/D (EIA 2014). This dramatic rise in production was in part due to the optimization of completion and stimulation designs, particularly the reduction of the isolated length of each stage (plug-to-plug distance) and, thus, an increase in the number of stages per foot of lateral. The average daily gross perforated interval per stage (top perforation to bottom perforation) that Halliburton completed in the Haynesville and Bossier shales from 2010 to 2013 was analyzed. The data encompasses nearly 11,000 stages for more than 30 operators. It illustrates that many operators began to reduce their gross perforated interval per stage across the play by the middle of 2011. In July 2011, it was 272 ft and by mid-2012, it declined to 150 ft, falling at a relatively constant rate as operators increasingly went to a shorter isolated stage interval. This indicates closer stage spacing (plug to plug) or more stages per well, with lateral length remaining relatively constant. These trends continued into 2012 and a dramatic improvement was seen not only in the slope of the projected production decline curve, but also in the estimated ultimate recovery (EUR) for the wells being brought online.

The completion cycle for the development of unconventional resource plays, such as the Eagle Ford shale in South Texas, requires multiple hydraulic fracture stages to be placed in the horizontal section of the wellbore to effectively stimulate the reservoir. Inefficiencies in the completion design caused by conventional "plug-and-perf" (P-n-P) methodologies can increase the costs associated with the delivery of hydraulic fracturing. However, new methodologies have recently been developed to mimic the P-n-P process that allow the operator to fracture stimulate the reservoir in a more economic and time-efficient manner. The Eagle Ford shale in Lavaca/Gonzales Counties, Texas is similar to many high-carbonate-content oil shale formations. In South Texas, the industry has a preference for cementing the lateral section for fracture stage isolation. This case study explores the successful implementation of a cemented multientry point sliding sleeve technology (CMEPT) in the Eagle Ford shale. The combination of these technologies was the first ever of its kind. This study also illustrates some of the lessons learned during the years of development of this integrated service technology. This paper highlights the key well that successfully implemented these technologies. The Kudu Hunter No. 1H well was drilled to a measured depth of 16,302 ft with a lateral length of over 6,000 ft. The integrated service design proposed a hybrid completion design with 2,000 ft of lateral completed by means of a nine-stage CMEPT and the remaining 4,000 ft of lateral completion by means of the P-n-P method. The CMEPT allowed the placement of ~1,840,000 lbm of premium white sand with surface modification agent (SMA) by means of 1,740,000 gal of guar-based hybrid fluid over nine stages in 22 hr, and the remaining 11 stages of P-n-P completion placed ~2,310,000 lbm of premium white sand and SMA by means of 1,940,000 gal of guar-based hybrid fluid in ~80 hr. The stand-alone conventional P-n-P process has become a barrier to the economic delivery of fracture stimulation. This case study illustrates how the adoption of the CMEPT integrated service process provides efficiencies in the completion cycle and maximizes stimulated reservoir volume (SRV) along the well path.

This paper was also presented as SPE 106593 at the 2007 SPE Latin American and Caribbean Petroleum Engineering Conference held in Buenos Aires, Argentina, 15–18 April 2007. Abstract Production of large volumes of water, coupled with production of formation sand and fines from oil and gas wells, often curtails the potential production of hydrocarbon. It is therefore highly desirable to decrease the volume of water and mitigate the solids produced from producing wells. Water and sand control generally have been addressed as separate problems with different treatment solutions. This paper discusses the development, and presents the field testing results, of a 2-step process that combines both water- and sand-control treatments into a single treatment. Laboratory experiments were performed to examine the impact of these combined treatments. The relative permeability modifier (RPM) treatment results in water permeability reduction with little or no reduction in permeability to oil. Treatment with a consolidating agent transforms the unconsolidated formation sand and/or loosely packed proppant into a cohesive, consolidated, yet highly permeable, pack. The combined process has been field tested successfully. Results from field tests have shown that this process helped reduce on average 50% of water production, effectively eliminated the production of formation sand, and allowed the wells to withstand high production flow rates. Introduction Both water production and sand production are a major concern in the petroleum industry because they are the most costly problems affecting hydrocarbon production rates. It has been shown that water production impacts the tendency of sand production.1 A recent study performed by Wu et al.2 showed that the effect of water cut on perforation failure and sand production is most significant for sandstones with high clay content. Many oil wells produce a gross effluent comprising greater than 80% by volume of water. As a result, most of the pumping energy is expended in lifting water from the well, after which, the effluent must undergo an expensive separation process to recover water-free hydrocarbons. Disposal of the remaining water is also a troublesome and expensive process. For these reasons alone, it is highly advantageous to decrease the volume of water produced from oil and gas wells. In addition, however, decreasing the flow of water into the wellbore can help lower the liquid level over the pump in the wellbore and reduce backpressure in the formation to improve pumping efficiency and net daily oil production. Another expensive byproduct that often accompanies oil and gas production is the production of formation sand and fines particulates, which is often preceded by water intrusion. Once water production begins, cementation between formation sand grains can deteriorate, allowing the formation sand and fines to migrate, or produce, with the production fluids. The higher the flow rates, the worse the problem. Fines migration often causes formation damage as pore channels or flow paths become plugged with fine particles. The wellbore can become filled with formation sand, choking off the production flow path and often requiring workovers to remove the sand fills. Formation particulates produced with production fluids can also destroy downhole and surface equipment. These unwanted byproducts of oil and gas production have typically been addressed as separate issues requiring separate treatment solutions. Water control or conformance has been addressed by numerous studies.3–6 Plastic or resins were applied in consolidation treatments for sand control starting in the 1940s.7,8 The system described in this study offers a fresh approach for attacking both water and sand production problems at their source, using a single two-step process. It provides a viable and cost-effective treatment plan for reducing water and solids that can result in significant savings in time and production cost during the life of the well. Water Control Systems The chemical systems that are suitable for reducing or controlling water production in this study are nonsealing systems. They allow the flow of fluids through a porous medium even after the treatment. These non-sealing systems are typically dilute solutions of water-soluble polymers. They reduce effective water permeability by means of a "wall effect" by polymer adsorption onto the formation,9 creating a layer of hydrated polymer along the pore throat that inhibits water flow without substantially reducing the flow of hydrocarbons (Fig. 1).