The Eagle Ford shale in south Texas is the one of the most recent developments in unconventional reservoir exploration. Numerous existing completion methods have been applied in this nano-darcy formation with various degrees of success. The horizontal Eagle Ford wells in the northeast area of the current Eagle Ford play (DeWitt County) require a completion strategy that is reservoir specific. The production in this area has a high liquid/gas ratio and presents different challenges for commercial development than those in the typical “high-rate water frac” completions associated with dry-gas shale stimulation theory. Previous high-rate water frac completions in this area typically associated with the “Barnett-style shale stimulation” achieved poor results. Core analysis shows that a low Young's Modulus (YM) (soft rock), high clay content, and the potential for high liquid-hydrocarbon production require the need for a different completion strategy. Swelling formation clays and proppant embedment were formation issues to consider along with the multiphase hydrocarbon production. Higher conductivity fractures would be required, but various unknowns existed: How many frac stages should be pumped?How much proppant should be pumped on each frac stage?What type of proppant should be used?What mesh proppant should be used?What perforation scheme was needed?What type of completion fluids should be used?What injection rate was needed?How would fracture-injection issues be handled? This paper discusses how a collaborative, engineered approach was applied to the completion of the Eagle Ford shale to deliver a commercial asset. To address the unknowns, the methodology included geologic and reservoir understanding applied to the stimulation design and execution. The stimulation resulted in hydrocarbon production that exceeded expectations. Comparative well results will be discussed.

Summary This paper presents a case study of the implementation of an integrated engineering approach to drill, complete, evaluate, and optimize multiple sets of parallel horizontal wells in the oil segment of the Eagle Ford shale. Two sets of horizontal wells were drilled parallel to each other in the Eagle Ford shale. Chemostratigraphic analysis was used during the drilling process to assist in understanding the placement of the horizontal wellbores with regard to the target pay interval as well as to assess area faulting. This data was used in designing the stimulation-stage intervals and to evaluate surface injection responses during the fracture treatments. Ball-activated fracture valves and plug-and-perforation completion strategies were tested to determine whether one is superior to the other. Oil-soluble tracers were used to understand the efficiency of these different completion strategies and aided in the production comparisons. Downhole microseismic mapping was also used to assist in the completion evaluation. The integration of various engineering data allowed for interesting conclusions about horizontal wellbore placement and the effect it has on the fracture-stimulation treatments, as well as the resulting production from the comparative wells. These insights provide important information for optimizing infill-drilling, well-placement, and fracture-completion strategies in the Eagle Ford shale. The lessons learned were implemented on additional wells in the same field, and all of these results will be discussed.

This paper presents a case study of the implementation of an integrated engineering approach to drill, complete, evaluate, and optimize multiple sets of parallel horizontal wells in the oil segment of the Eagle Ford Shale.Two sets of horizontal wells were drilled parallel to each other in the Eagle Ford Shale. Chemostratigraphic analysis was utilized during the drilling process to assist in understanding the placement of the horizontal wellbores with regard to the target pay interval as well as assess area faulting. This data was used in designing the stimulation stage intervals and to evaluate surface injection responses during the fracture treatments. Ball-activated fracture valves and plug-and-perf completion strategies were tested to determine whether one is superior to the other. Oil-soluble tracers were used to understand the efficiency of these different completion strategies and aided in the production comparisons. Downhole microseismic mapping was also used to assist in the completion evaluation.The integration of various engineering data allowed for interesting conclusions about horizontal wellbore placement and the effect it has on the fracture stimulation treatments, as well as the resulting production from the comparative wells. These insights provide important information for optimizing infill drilling, well placement, and fracture completion strategies in the Eagle Ford Shale. The lessons learned were implemented on additional wells in the same field and all of these results will be discussed.

The industry has constantly struggled to balance proppant supply with demand. With the increasing levels of propped fracture stimulation activity in horizontal-shale developments in North America, alternative solutions might need to be used if the desired proppant is not available to fit the completion timeframe. Operators must continue to drill and complete wells, and suitable proppant availability is key to the process when propped fractures are required to deliver commercial returns. Multiple parameters determine proppant-selection criteria for a fracture completion, such as closure stress, Young's modulus (YM), Poisson's ratio (PR), reservoir pressure, hydrocarbon type, etc. As multistage fracturing in horizontal wells increases, the availability of adequate quantities of suitable proppants has become an issue. Deeper, hotter wells with higher closure stresses typically require man-made ceramics to deliver sufficient fracture conductivity under these extreme conditions. An alternative technology was applied in an Eagle Ford shale completion that provided an economic solution when man-made proppants were not available. An on-the-fly Surface Modifying Agent (SMA) was applied to natural quartz sand substrate and pumped under conditions that normally exceed the useful range of this proppant. An engineering methodology was implemented to determine the risks associated with “pushing the envelope” with this technology and assesses the probability of a successful commercial development. The application of an onsite SMA to proppant during a frac job can provide operators with additional options when the desired proppant is not available. It also allows for varying degrees of flexibility during onsite job redesign and execution. This technology can help keep a completion program on schedule and add additional benefits related to sustained production. The application of an onsite SMA to natural-sand substrates can provide an efficient low-cost alternative to man-made proppant, especially during times of supply shortages.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Wilcox Lobo Trend of south Texas contains vast quantities of natural gas in low permeability formations. Economic production from low permeability gas sands is possible through the use of hydraulic fracturing. Through the years, varying hydraulic fracturing techniques have been used to recover the gas from this trend. The success of fracturing techniques varies and depends on many factors. Several authors have demonstrated the importance of propped fracture conductivity in the production enhancement process. Without sufficient conductivity in the proppant pack, fracture fluid cleanup and adequate hydrocarbon production are difficult to achieve. The work presented in this paper will show the evaluation of these different completion techniques and products used in the Wilcox Lobo Trend by the authors. The work demonstrates the importance of fracture conductivity, supports previous work in other producing regions and presents some additional methods for achieving increased conductivity.The techniques, products and evaluation methods used in this paper can be used to benefit other operators in the Wilcox Lobo Trend as well as those working in other low permeability gas formations.