Improving Completion And Stimulation Effectiveness In Unconventional Reservoirs - Field Results In The Eagle Ford Shale Of North America

Abstract

In an unconventional reservoir, the success of a project is driven by the completion. Unconventional plays have become the primary area of development in the US, and shale formations dominate the current rig activity. Most shale wells are drilled utilizing long horizontal wellbores, and completed using cemented or uncemented casing strings. To be economic, they require large hydraulic fracture treatments in multiple stages along the lateral. Total well costs are driven by the cost of fracturing, often representing as much as 60% of the total well cost. This requires the operator to select the best completion method which includes casing and wellhead selection that is based on stimulation needs. The stimulation is regulated by injection rates, treating pressures, the volume of the stimulation, type of fluid, proppant selection, perforations, and the number of stages. This paper focuses on several areas that are critical in a successful completion such as: casing size and pressure rating, wellhead selection, treatment design, spacing of the perforations and stages, linear verses cross-linked fluid, and the impact of proppant selection. With over 1800 wells completed and stimulated so far, a comparison of successful treatments and the cause of unsuccessful treatments will be provided. A review of actual field applications will be presented where possible, and a method for identifying best completion practices will be discussed. Those working in or considering developments in unconventional plays around the world will be able to compare their current completion techniques to those presented in the paper. In addition, while no two resource plays are the same, the findings in this paper can be used by engineers as a guide for moving up the learning curve more quickly in other unconventional plays.

Assessment of Eagle Ford Shale Oil and Gas Resources

“…To simplify the reservoir model, we assigned the seven layers to either upper Eagle Ford or lower Eagle Ford. Table 4 shows the averaged reservoir properties for all production regions; the numbers in parentheses are the perforated layers, which are in the middle of the lower Eagle Ford formation to have the most surface contact of the organic-rich shale (Pope et al 2012). …”

“…Based on Table 14, a simple calculation assuming oil price of $100/STB and gas price of $4/MSCF shows the lowest mean gross revenue among all the production regions are PR1 with $11.2 million and PR8 with $13 million. For a typical drilling and completion cost of $8 million (Pope et al 2012), the mean gross revenue times a typical working interest of 87.5% is greater than typical well cost for all production regions, so all production regions meet the minimum requirement for commerciality criterion that the cash flow "at least has a positive undiscounted cash flow" under PRMS (SPE et al 2007). The discovery criterion is more challenging.…”

Comprehensive Optimization Methodology for Stimulation Design of Low-Permeability Unconventional Gas Reservoirs

“…5. Small gridblocks are used near each fracture, and larger gridblocks are used away from the fracture system to capture the flow convergence toward the horizontal wellbore at the center (Quicklook 2012):…”

Temperature-Prediction Model for a Horizontal Well With Multiple Fractures in a Shale Reservoir

“…According to several field cases such as the Haynesville shale and Eagle Ford shale, more than 10 stages are completed in order to maximize the exposure to formations for the economic production from shale reservoirs Pope et al, 2012;Thompson et al, 2011). Bazan et al (2010) presented one example of the multistage hydraulic fracturing treatment for the Eagle Ford shale.…”

“…As presented in the above example, in order optimize completion design, it is required to consider several parameters such as number of stages, number of clusters per stage, number of perforations, stage interval, cluster spacing, selection of proppant and injection fluid, injection fluid volume and cementing design (Ketter et al, 2008;Pope et al, 2012;Thompson et al, 2011). Additionally, because the created fractures/clusters change the stress anisotropy in the reservoir (Cheng, 2012), new treatment procedure to enhance near-wellbore and far-field fracture network complexity was presented considering the existence and magnitude of principal stress anisotropy and designing the optimum spacing between fractures with optimum fracture treatment parameters (East et al, 2011).…”