Hole enlargement while drilling (HEWD) is an important technique in both deepwater and onshore drilling. Drilling interbedded formations is a difficult HEWD application. Two extreme cases can occur. One case is when the reamer drills in soft formation while the bit is in a harder formation. The other more difficult situation is when the reamer is in a hard formation while the bit drills ahead in soft formation. The latter creates an enormous challenge for the reamer to drill the harder formation without inducing large lateral and torsional vibrations which is detrimental to the reamer and other BHA components. An overall HEWD operating parameter management approach can greatly reduce probabilities of tool damage and unnecessary tripping while dramatically reducing drilling costs. A state-of-the-art BHA dynamic analysis program that allows modeling the reamer and bit in different formations plays a vital role in the overall HEWD management process. Before any planned HEWD operation, various possible operating scenarios can be virtually simulated through the BHA dynamic analysis program to evaluate the effect on BHA components of lateral and torsional vibrations. An optimized BHA configuration can be specified through these analyses and a set of optimal operating parameters for the chosen BHA can be developed. This paper presents an excellent case study of HEWD through severely depleted interbedded formations in the Gulf of Mexico. Previous offset wells had required multiple runs to HEWD this section due to reamer cutting structure damage. Models were constructed to compare performance with a range of BHA, WOB/WOR and RPM combinations. A set of optimal operating parameters and a road map were established for managing these parameters on the rig. Most importantly, the analyses recommended operating conditions that were substantially different from the accepted HEWD operation of increasing weight on bit (WOB) in harder formations. The analyses indicate that overall BHA performance was dramatically affected by weight on reamer (WOR). With a small sacrifice of ROP in the harder, more abrasive formations the HEWD system can effectively drill through the entire section without tripping due to component failure. This approach achieved excellent overall cost effective performance saving the operator $1.89 million on an offset well. Introduction The operator announced its field discovery in the Gulf of Mexico's Mars Basin in September, 2002. It is in 3,000ft of water, and is located approximately 88 miles southeast of Port Fourchon, Louisiana (Figure 1). During recent field development, the operator experienced problems with a BHA component. Specifically, the reamer 1,2 was suffering cutting structure damage driving up field development costs and slowing time to production. This paper will present the application challenges and resulting tool issues in addition to the problem analysis and engineering design changes to the reamer and operating parameters intended to solve the problem(s). Finally, the authors will present the results of applying the new technologies and operating parameters on the WELL #3 and how they saved the operator $1.89 million compared to costs incurred drilling the offset WELL #2.
With the world's dependence on hydrocarbon-based energy sources driving global demand, new drilling opportunities require technological innovation to increase efficiencies and optimize production. Some newer drilling operations, particularly in the deepwater arena, involve extreme environments such as ultra-high pressures and demand different approaches to ensure flawless execution. This paper presents the variety of challenges, critical success factors, and lessons learned when drilling these ultra-high pressure wells in the Gulf of Mexico's demanding waters. With downhole pressures approaching 30,000 psi and escalating rig costs, the need for dependable rotary steerable systems (RSS) along with advanced formation evaluation technology is needed now more than ever. With well depths surpassing 30,000 ft below the mudline and increasing water depths, ultra-high-pressure requirements present a new and challenging frontier for both operators and service companies. These new environments demand advances to existing technologies' operational limits to endure such pressure extremes, while also accurately positioning the wellbore in the reservoir and obtaining critical geological information as the well is drilled. A recent example in this pressure regime in the deepwater Gulf of Mexico will be reviewed. In cases, pressure limits of the currently available technology are extended while successfully meeting drilling and evaluation goals. Emphasis is placed on the need for operators and service companies alike to focus on thorough pre-job planning while paying close attention to complete system pressure ratings, high-pressure tool inventory management and detailed reviews. As always, communication is one of the critical success factors to ensure success. The drilling and evaluation technologies delivered real-time formation pressure and geological information, along with continuous directional control, allowing operators to make vital decisions while drilling. This real-time decision-making capability reduced the time required to execute casing point selection and subsequent sidetrack plans. Additionally, by following an application-based philosophy to technology selection, critical drilling and evaluation questions were answered in real time, reducing risks for nonproductive time (NPT) in these extreme environments. The case results showcased the ability to set a new performance standard, extend the conventional operating envelope, and deliver answers while drilling. Introduction The deepwater environment and the potential for large hydrocarbon discoveries have driven technology innovation for a substantial period of time. Advances in rig design, downhole tools, data communications and dozens of others have all rested on the challenges associated with pushing and extending limits. Considering only the drilling of a deepwater well, the associated problems are quite substantial. Throw in a variety of additional complications: a large volume of salt, geologic uncertainty, directional work in excess of 25,000 ft TVD, and a final TVD in the area of 33,000 ft, and one has an extensive set of obstacles to overcome (Fig. 1). It is critical to determine how to effectively surmount these problems rather than adopting an attitude of resignation and concluding that "it can't be done." How does one push the limits of technology while managing the known risks, extend the limits of technology and mitigate the "suspected" risks, and build a model for success?
Determining the optimal location for a new platform in offshore deepwater environments is one of the more challenging and complex exercises that an operator must negotiate. Engaging multidisciplined stakeholders, who often have disparate objectives or constraints in determining an ideal site location, can easily become a time-consuming and inefficient process. To be effective, numerous scenarios must be modeled in a rigorous and efficient manner to determine the optimal location. For one such complex task, Shell elected to use the latest technologies in well planning and visualization. To ensure a successful project, the definitive solution needed to accelerate the well planning process while considering information from all necessary disciplines.This project had its own particular set of challenges, including abundant hazards and obstacles lying on the seafloor, a complex salt body to be avoided, and a wide range and uncertainty of geological targets. All of these challenges were modeled in a visualization system composed of surface maps, geological targets, and geophysical data. Upon completion of the initial model, a collaborative well planning session enabled a quick evaluation of the risks and drivers observed by each discipline. This process led to an understanding across disciplines of the dependent activities that must occur in the correct order, which established the work scope and avoided unnecessary tasks.After this initial meeting, four possible locations were proposed. Using the 3D visualization and well planning software, each proposed surface location was then planned to reach the pre-defined targets. The plans were later statistically analyzed to show the drillability of each location and reviewed by the team. Using the same model and constraints, multiple iterations generated and optimized new plans to a series of updated targets. Approximately 400 potential wellpaths were considered and risked across several scenarios until the final location was determined.This paper describes the procedure used to determine the optimal surface location for the platform using a 3D visualization and well planning application. This application is intended for all personnel (including drilling, completions, and geological and geophysical disciplines) involved in the well planning process and field development projects.
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