Deepwater wells using fracpack stimulation are progressively moving to ultradeep water depths and total depths; the bottomhole pressures (BHPs) and temperatures of future reservoirs could exceed 20,000 psi and 250°F. To safely perform deepwater fracpack treatments, the following pressure and tubular limitations should be considered:• Maximum surface tubing pressure because of pipe limitations and gravel pack assembly component ratings.• Maximum surface annulus pressure because of blowout preventer (BOP) ratings.• Maximum allowable tubing movement while pumping to help prevent premature job cessation.• Maximum allowable downhole slackoff and overpull because of well path, pipe, pipe connections, and downhole component ratings.Depending on the well depth, pressure, temperatures, and BOP type (subsea or dry-tree), various pipe, connection, or equipment limitations might be exceeded during multistage fracpack stimulation operations. Initial pipe loading as well as pre-fracpack stages, such as the pickle, acid treatment, or minifrac calibration treatment, will alter the pipe failure and movement conditions and must be accounted for in the final completion design.Because of these concerns, a workflow process has been delineated to evaluate the maximum allowable treating pressures, tubing movement, and tubular limits for deepwater subsea and dry-tree fracpacks across four components:• Input component to consolidate well and stimulation data for further workflow analysis.• Surface treating pressure evaluation component to analyze certain treating pressure limitations.• Commercial wellbore, casing, and tubing simulator to evaluate work string safety factors, tubing movement, and downhole forces. • Commercial torque and drag simulator to evaluate surface slackoff requirements and allowable work string overpull.A description of the variables, range of values, and other considerations for each of these four components is discussed, and the benefits of using this process to evaluate fracpack stimulation are shown. Well case histories are also used to support this process.

Much has been written about the deepwater Lower Tertiary Wilcox trend in the Gulf of Mexico, which spans hundreds of miles from Alaminos Canyon to Keathley Canyon to Walker Ridge (as well as adjacent areas). The estimated ultimate recoverable oil from these reservoirs is significant: 3 to 15 billion barrels. However, significant technical and reservoir challenges remain because of the water depth (typically greater than 5,000 ft), reservoir depth (typically greater than 20,000 to 30,000 ft below the mud line (BML)), and high pressures (greater than 20,000 psi bottomhole pressure (BHP)). Combining these issues with the thick, low permeability reservoir intervals (more than 1,000 ft thick in the tens of mD) requires new tools as well as new planning and optimization methods. These new planning tools require system-wide (holistic) integration across multiple domains and completion software applications to produce a truly optimized completion. This type of integration is provided by an automated software workflow. Previous papers have provided details about the benefits derived from the automation of operations, engineering, and production workflows in general. Lower Tertiary Wilcox reservoirs were deemed good candidates by a major service company to implement the automated workflow concept, given the reservoirs’ low productivity index (PI), high-cost wells, high pressure/high temperature (HPHT) technical challenges, and production uncertainty. This specific workflow seeks to optimize hydraulic fracture design within Lower Tertiary Wilcox reservoirs by stipulating the maximum net present value (NPV) that satisfies all well, completion, and reservoir constraints. Hydraulic fracture design is an example of what is largely a manual process that requires interaction with several software applications to obtain fracture geometry, production constraints, production sensitivity criteria, and NPV scenarios. When the goal is an optimized fracture design, the process is especially arduous because it requires iterative interactions with reservoir simulators, nodal programs, economics models, well tubular design systems, and stimulation design tools to arrive at a suitable design. Enabling coupled simulations technology, this fracture workflow provides a unique holistic combination of tools, which are linked to reflect the actual economic values.

Hydraulic fracture design is an example of what is largely a manual process that requires interaction with a number of different software applications to obtain fracture geometry, production constraints, production sensitivity criteria, and NPV scenarios. When the goal is an optimized fracture design, the process is especially onerous, as it requires iterative interactions with reservoir simulators, nodal programs, economics models, drilling-well design systems, and stimulation design tools to arrive at a suitable design.Previous papers have detailed the benefits that can be derived from the automation of operations, engineering workflows, and production workflows in general. A major service company was able to quickly provide workflow automation benefits to an East Texas field with the aid of its workflow automation software. In the East Texas field, the service company was able to preserve the provided business service, yet change many of the connections with other software applications that were used to deliver the business benefit, as well as the engineering methods used to optimize the design.The GoM Lower Tertiary Wilcox Sand Field was also deemed a good candidate by a major service company to operational and production workflow automation, given its low PI, high-cost wells, HPHT tech challenges, and production uncertainty. This fracture workflow uses a unique holistic combination of tools, which are coupled in a way as to reflect the actual economic values of various fracture scenarios.With the Microsoft Upstream Reference Architecture (MURA) initiative, Microsoft, along with several of its E&P partners, prescribes this approach, which focuses on achieving a level of interoperability between software solutions used by the industry.

The frac-pack completion has become one of the prominent completion types for deepwater formations throughout the world. The vast majority of frac-pack stimulation treatments are pumped through complex sand control tools in wells with large gravel pack assemblies. The forces created by these stimulation treatments have increased as treatment size, water depth, and total depth have increased offshore. To plan appropriately for these deepwater completions, engineers expend a significant amount of effort to ensure that the tools are robust enough to accommodate the treatment demands. This planning and simulation can be a very time consuming process; moreover, it may evaluate only a limited range of potential frac-pack scenarios. To reduce time and limit uncertainty, a novel tubing movement workflow has been developed. A commercially available workflow software suite was used to connect a commercially available fracture design component and a commercially available casing and tubing simulator. This workflow uses formation parameters and a wellbore input file to process hundreds or thousands of stimulation injection schedules to determine tubing movement, pipe forces, and weight transmitted downhole. The entire process is completed within a significantly shortened time span, depending on the computer speed and the number of iterations desired. The results of the workflow enable the determination of optimal workstring and service tool characteristics. A sample case study is included.