The Eagle Ford Shale in the southern part of Texas is a carbonate-rich, oil-producing, organic shale. Typically, wells are drilled horizontally through the target section of the Eagle Ford shale formation. A long string production casing is then run and cemented in place. A plug and perforate completion helps enable hydraulic fracturing of multiple target intervals along the lateral section of the wellbore. Before fracturing the wellbore, pressure testing of the casing string to the maximum fracturing pressure has become an industry best practice. Then, a flow path is created at the toe of the wellbore using tubing-conveyed perforating (TCP) guns run into the wellbore on coiled tubing (CT). With the constant drive to improve efficiency and lower completion costs, pressure-activated toe sleeves (PATS) have rapidly replaced the TCP CT run to create the initial fluid flow path. The PATS is run as part of the completion casing and cemented in place. Internal casing pressure is then applied to open the PATS and create the flow path. However, to accomplish a casing pressure test, the first generation PATS design must have the activation pressure set higher than the testing pressure. The casing test pressure must then be exceeded to open the PATS which is not ideal operationally for a variety of reasons. This paper reviews a case study where a new, second generation PATS was used in an Eagle Ford shale well to allow a true casing pressure test and provide the initial flow path. The paper discusses the subject well, design, and operation of second generation PATS technology, and presents the results of the application. The positive economic impacts are also reviewed. The paper draws conclusions based on the results from the subject well, operation of the new PATS tool, and the economic impact experienced.

During the past several years, the oil and gas industry has increased the development of unconventional resource plays which are expected to hold the future for energy development in many parts of the world. In order to maximize these new reservoirs, horizontal wellbores are typically drilled, and multiple hydraulic fractures must be created to provide enough stimulated reservoir volume (SRV) to produce the wells economically. A traditional plug and perforate completion methodology has been employed to perform multi-stage fracture treatments, gain wellbore access, and isolate fracture stages. This process contains inefficiencies that can significantly impact economics. When the plug and perforate method is used prior to running perforating guns and a frac plug to depth, a flow path must be created at the toe of the wellbore. Typically, this is achieved by using tubing-conveyed perforating guns (TCP) deployed on coiled tubing (CT) or by a wireline tractor pulling perforating guns deployed on electric wireline (E-line). Although necessary, this process is one of the major plug and perforate inefficiencies noted in the above completion method. While it does allow casing pressure testing (either government-mandated or part of the operator’s well construction "best practices") prior to fracturing operations, it significantly impacts economics. To address the inefficiencies, new technologies that seek to eliminate these problems, and thus, improve well economics are being developed. This paper explores an innovative pressure-actuated toe sleeve, which can eliminate running TCP on CT or perforating guns on E-line for initiating a flow path but still allows a casing pressure test to be run. Additionally, the pressure-actuated toe sleeve enables this casing test to be completed without having to exceed the casing test pressure to establish the flow path. The design, testing, and use of the toe sleeve will be discussed in the paper.

During the last decade, swellable packer technology has been accepted more readily, and its usage is increasing as a viable method for zonal isolation in the oilfield. During this time, swellable packers have shown a new side to their versatility, as they are now being used in many other applications. These newer applications are requiring that swellable packers provide an anchoring point for the casing or tubing string, and the swellable technology is accepting this challenge by being used to provide this requirement in applications such as casing repair, liner tieback, corroded casing, and multi-stage fracturing.This paper will review case histories and testing in order to illustrate procedures for developing, simulating and validating swellable-packer anchoring forces that will enable swellable packer technology to be applied in new oilfield applications. This testing and information will show that when the application and well conditions are understood, swellable packer technology can be a viable alternative to cementing of casing strings or expandable casing patches for providing anchoring points and isolation. This application often allows larger IDs to be considered and costs of workover operations to be reduced. Critical aspects such as the swelling fluids, pressure requirements, production/stimulation scenarios, well conditions and goals, and other concerns of the engineering and design process will be discussed. The impact of these parameters will be explained as well as how each is important in designing the swellable packer to meet any oilfield application. Other job design aspects such as simulating the swellable packer behavior and performing necessary laboratory testing to validate the simulation will also be compared to case history results.Finally, the paper will conclude how swellable packer technology can be used for many applications requiring anchoring forces. IntroductionSwellable packer technology has been used for a variety of oilfield applications, both on and offshore. Having already proven itself as an effective zonal isolation and pressure containment method for applications such as annular gas migration, water shutoff, and hydraulic fracturing etc., swellable packer technology is being adapted for other oilfield purposes. Many of these new applications require that the swellable packer provide an anchoring point for the tubing or casing string. By using swellable packer technology in new ways, wells that had been destined for plug and abandonment (P&A) have become productive, workover operations have been made easier, and fracturing of wellbores has been made possible in cases previously designated as not feasible.In the following sections, this paper explores the modeling that is required to enable many of these new applications to be performed. Focus will be on modeling software that is available and how meaningful results can be generated from these programs. Additionally, the critical factors that testing has shown to dictate the capability for swellable packers to provide an anch...