As an increasing number of 6000-ft plus deepwater developments come on stream in the Gulf of Mexico (GoM), project economics dictate that fewer subsurface drill centers be used to develop these fields. This in turn requires longer step-out wells, pushing kickoff points higher up the wellbore, often occurring within extensive salt bodies. Salt drilling is still a relatively new practice and presents operators with many drilling challenges that are still not totally understood. Adding a directional component to drilling through salt not only magnifies the issues of traditional salt drilling, but introduces new challenges that require different approaches to ensure successful delivery. This paper will discuss the challenges faced and the lessons learned by two major deepwater GoM operators along with the directional service company in drilling directionally through the salt. Together, these companies have drilled over 100,000-ft of salt in the GoM and are considered pioneers in deepwater salt drilling. They have encountered and managed many of the challenges that extend past the traditional predrill and real-time directional issues, into the post drilling phase with issues such as casing and cement design for managing salt loading and ensuring long term wellbore viability. This paper presents several case studies that investigate and discuss directional drilling through salt, comparing variables such as hole size, bottomhole assembly (BHA) configuration, under-reamer selection, wellbore trajectory and directional control. The importance of geomechanics in the predrill planning of these directional salt wells is also discussed, and its link to casing design and cementing issues will be examined. The paper concludes by identifying critical areas for success in drilling directionally through salt, and will attempt to identify current technical drilling limits for pushing this envelope even further. Introduction The Gulf of Mexico (GoM) is well known for its extensive subsurface salt structures that have aided in trapping much of the hydrocarbons found here. Figure 1 illustrates the extent of the salt coverage, in relation to multiple deepwater discovery wells. As deepwater exploration successes progress into the development drilling phase, and with the increasingly recognized potential of the GoM's Lower Tertiary trend, (much of the 33,000sq mi trend is covered by a thick salt canopy, Figure 2) the requirement for deepwater wells to penetrate salt have become almost mandatory. More information on GoM salt coverage is presented in the OCS Report 2007–021 Deepwater Gulf of Mexico (2007). Over the next several years, successful and efficient drilling of salt will play an increasingly major role in achieving many of the area's deepwater drilling objectives. In order to meet this challenge, the ability to directionally drill through salt and to understand and manage the issues this introduces will be a key factor for deepwater operators. This paper will explore in further detail, the drivers for directional drilling in salt, the challenges that it introduces and will discuss the enabling and emerging technology required to execute this relatively new aspect of deepwater drilling. Three case studies from different deepwater GoM operators will be reviewed, and the lessons and recommendations derived from these presented. The paper will draw upon these and other GoM salt drilling experiences to formulate a comprehensive package of the requirements for the planning and drilling directionally through salt.
This paper presents a case history of drilling automation system pilot deployment, inclusive of wired drill pipe on an Arctic drilling operation. This builds on the body of work that BP (the operator) previously presented in 2017 related to the deployment of an alternate drilling automation system. The focus will be on the challenges and lessons learned during this deployment over a series of development wells. Two major aspects of technology were introduced during this pilot, the first being a drilling automation software platform that allowed secure access to the rig's drilling control system. This platform hosts applications that interpret the activity on the rig and issue control setpoints to drive the operation of the rig's top drive, mud pumps, auto driller, drawworks, and slips. The second component introduced was a wired drill string, which provides access to high speed delivery of downhole data from a series of distributed downhole sensors, providing an opportunity to improve both automated control and real-time interpretation of downhole phenomena. The project team identified several key performance indicators both at the project level and for each well. The project level key performance indicators (KPIs) were designed to give the operator an understanding of the reliability and robustness of the hardware and software components of the automation system. The KPIs for the well were designed to assess the impact of the technology on drilling efficiency through aspects of invisible lost time reduction (connection and survey times). The well level KPIs also fed into the project KPIs by capturing uptime, reliability, and repeatability of the hardware and software components of the system. The paper describes several specific examples of where the benefits of the technology were realized as related to the KPIs above and describes some of the technical challenges encountered and fixes employed during the pilot campaign. The paper also gives an insight into some of the non-technical challenges related to deployment of this system, around human behavioral characteristics. It discusses how focused collaboration and communication from all the stakeholders was managed and directed towards a successful deployment. The work delivered on this project incorporates several technological innovations that were deployed for the first time on an active drilling operation. Delivery of these were important milestones for both the operator and the automation technology provider as part of their collaboration to increase the capability and reliability of these systems. The operator believes that this effort is key to allowing its drilling operations to realize longer term and sustainable benefits from automation.
In 1919 the world record for the deepest well was broken by the Hope natural gas company with a total depth (TD) of 7,579 ft. Although it took over 3 years to reach TD, only 325 days were spent actually drilling. Today in deepwater operations, the water depth alone can exceed this record, and operators have drilled past 30,000 ft in just 4 or 5 months. Technology and procedures have evolved extensively as operations that appeared impossible a decade ago are now considered routine. Today, operators are being pushed more than before, not just to explore deeper prospects, but also to get there efficiently. The future of the industry depends on it. Now there are new questions the industry is asking about deep water: What is different about drilling deep in deepwater operations? What does it actually take to drill the deepest wells in the world today? Currently, there are only a handful of personnel with the knowledge and experience to execute these wells. This paper will discuss the challenges of planning and drilling directional wells in excess of 30,000 ft true vertical depth (TVD) and will also look at lessons from some of the major deepwater Gulf of Mexico (GoM) operations that have successfully drilled wells beyond this mark and are continuing to push the envelope further. These wells have held, at one time or another, records for deepest wells drilled in many categories in recent years. IntroductionMany of the deepest wells in the world have been drilled in the GoM, and many have been in deep water. Fig. 1 illustrates the trends in total TVD of the wells for the GoM. Fig. 2 illustrates the trend in increasing water depths with time for wells in the GoM. The direction that the industry is heading in is deeper: deeper water and deeper wells. The technology exists to take us there. However, there are critical factors to consider when planning these wells.
This paper describes a collaborative effort between an operator, a drilling contractor and a service company to introduce specific aspects of automated technology to a major drilling operation. The application of automated technologies to the process of well construction is emerging as a key lever to improve the overall efficiency of drilling performance. Though not yet mainstream, several recent applications have demonstrated that the technology maturity is no longer the limiting factor in accelerating the uptake and realizing the benefits that automation can bring to drilling. A major challenge that has emerged in implementing drilling automation is the fragmented and often non-symbiotic business model that exists between key stakeholders. Additionally challenges exist around the lack of inter-operability between various parties' specific hardware and software. This issue extends to the multiple data streams involved, the data's robustness and how to integrate these adequately to drive automated processes. As with any technology introduction, new complications appear and this is no different for implementing automation technologies in drilling. Among the many new challenges are the increased cyber-security risks introduced by exposing the drilling control system to external networks, as well as the human factors challenges associated with changing well established workflows on the rig floor. The sum of these is to manifest itself in improved drilling performance without compromising on the safe operation of the rig. In this particular case, the discussion centers on the application of automation to drilling parameter control as it relates to improving the rate of penetration in hard rock drilling environments. Successful implementation of automation technologies in drilling is a significantly complex endeavor, and the measures of success may not be immediately apparent. Instead, a vision that encapsulates a longer term, strategic view on the potential benefits that automation can bring to well construction is required, with shorter term tactical milestones being well defined, and a systematic plan engaged to achieve them. The paper explores how the above issues were managed over a testing and implementation period of approximately three years covering the transition from an advisory mode system to an automated one. Automated process control applications on drilling rigs will continue to increase in both the number of deployments as well as the breadth of functions covered. The project described illustrates one approach that is unique to date in terms of the technology and the degree of collaboration employed by the stakeholders to successfully deliver the objectives. Early adoption initiatives as discussed here are essential for the technology to evolve. They provide the industry with a series of lessons that help to sustain and direct the future of drilling automation and its role in enhancing well construction capabilities.
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