A modeling tool has been developed that enables drilling engineers to design vibration resistant bottom hole assemblies (BHA's), given tool placement constraints and desired directional objectives. This model can be applied to configurations with the majority of common components, including rotary steerables, bi-center bits, roller-reamers, hole openers, and eccentric mass stabilizers. Modeling results have been validated in large, intermediate, and small hole sizes. In these applications, predicted behavior and field observations have compared well. Redesign has resulted in improved drilling results, including increased on-bottom drilling time, longer tool life, higher Rate of Penetration (ROP), reduced non-productive time associated with tripping, and even better hole quality. As use of the operator's ROP management process has spread through the company (Dupriest, 2005), downhole vibrations have been identified as one of the most significant factors limiting further ROP and footage improvements. Rig site personnel use vibrations data from downhole sensors and Mechanical Specific Energy (MSE) diagnostics to achieve the minimum vibrational levels possible with the existing assembly. The nature of the remaining vibrations is identified, and the BHA is then redesigned in a way that addresses the specific form of vibration that is limiting performance. The field assessment of the vibrational limiter and the redesign process are repeated from well to well. Vibrations mitigation is posed more as a design problem than an analytical one. The model characterizes the lateral vibration, or whirl, tendencies of BHA's, enabling quick and easy comparison of potential BHA design candidates. A BHA can be designed to minimize vibrational tendencies for a given set of operating parameters, or the optimal operating parameters can be predicted for a given BHA configuration. The model has unique displays to support both pre-drill vibrations forecasting and post-drill hind casting. Several case studies are provided to illustrate the value of this technology. Introduction Vibration of drillstrings and bottom hole assemblies has contributed to operational problems since rotary drilling was first invented in 1930. Failure of drillstring components, such as Rotary Steerable (RSS) or Logging While Drilling (LWD) tools, may result in non-productive time while tripping to replace the failed equipment. Downhole components may eventually part so that fishing or sidetracking operations are required. In some situations, equipment failure may also result in well abandonment. In addition to these unplanned events, whirl or lateral vibration causes the cutting action of the bit to be inefficient and ROP may decline significantly. The operator drills approximately four million feet of hole each year, and MSE analysis suggests the performance in over 40% of this footage is adversely affected by whirl. At various times in the past, investigators have focused on certain elements of the drillstring dynamics problem and made some progress, to be succeeded by new theories using generally more complicated models. Critical rotary speed guidelines were included in early editions of the API RP7G drillstring standard (e.g., 1984). One critical speed formula depended on the length of a drillstring, thus identifying a vibrational depth-dependency, but this section was deleted from later versions because it was considered to be insufficiently precise. Dareing (1984) found that the length of drill collars in particular is a key element in the bottom hole assembly (BHA) vibration problem. Mitchell (1987) identified harmonic resonance of the BHA as a major factor in several case studies of BHA failures. Spanos and Payne (1992) used a frequency domain eigenmode analysis to investigate the problem, primarily focusing on the identification of critical modes and corresponding rotary speeds. Critical mode analysis is still of interest in present models (e.g. Chen, 2007).
In 2005, the operator implemented a workflow that ensured that drilling-performance limiters were identified, redesigned, and extended continuously. The use of mechanical-specific-energy (MSE) surveillance to address bit limiters and dysfunction has been published previously. The purpose of this paper is to discuss additional practices that have been developed to extend the nonbit performance limiters, particularly those related to borehole quality.There have been more than 40 nonbit performance limiters identified and redesigned globally. While these are diverse, those with the greatest global impact were found to be tied directly to borehole quality. Consequently, in 2008, the performance-management workflow was modified to increase awareness of borehole quality as a performance limiter. The result was that acceptable borehole quality became defined as that which would not limit footage per day. Quality is now redesigned to the "economic limit of performance" in the given interval. The economic limit of performance is a significantly higher standard than the common industry objective for borehole quality, which is to achieve low trouble time and to run casing successfully.The average drilling footage per day drilled by the 23 operations that have been active since the performance-management process was implemented has improved by approximately 63%. Instantaneous drill rates have typically increased 100-300%. Advances in bit and nonbit limiters appear to have contributed equally, and the majority of the gain in nonbit limiters has come from improved borehole quality. Other gains have come from related limiters, such as an increased understanding of the manner in which cuttings transport and tripping operations are controlled by borehole quality.The paper discusses the technical models that are used to understand the major borehole limiters, the engineering design, and the real-time practices that have been developed, as well as the field results.
Design tools and workflows to mitigate drilling vibrations have been developed, demonstrated, and documented for several field drilling applications. This paper provides two new case studies to illustrate how this vibration mitigation methodology may be applied. Dynamic motions of the bottomhole assembly are known to be highly detrimental to the drilling process, resulting in unplanned trips, reduced rate of penetration, shortened bit and tool life, and MWD failures. The utility of the BHA design tool and the associated workflow will be illustrated in the context of how the methods have worked in conjunction with improved operating practices to achieve better drilling performance. One case study shows how vibrations modeling can be used while drilling is underway to select a better BHA design, when it has been recognized that vibrations are a key performance limiter. Another case study illustrates how the vibrations modeling may be used to choose a preferred BHA design in advance of drilling a well or hole section. This proactive predrill workflow provides for advance planning and alignment with service providers. Both of these case studies illustrate how the method can be used to hindcast field results to understand performance change from one BHA to the next. Vibrations mitigation through BHA design modification, operating parameter selection, and follow-up surveillance is proving to be highly cost-effective in the operator's "relentless re-engineering" process to reduce drilling costs. These technology applications are now being applied on a global scale.
The operator's drilling efficiency program has been expanded to a Limiter Redesign Process that seeks to optimize all rig time, including flat time. As drilling efficiency gains have been achieved, flat time now accounts for roughly 80% of the total rig time and approximately 70% of the total cost of drilling and completions operations; leaving 20% of rig time for drilling. This fact led to the generation of a comprehensive Flat Time Reduction (FTR) program.The Fast Drill Process has become a well-known workflow to identify hole-making limiters and mitigate them through "relentless redesign to the economic limit of performance". Efforts to increase drilling efficiency continue, and this process has yielded a continuous increase in the overall footage per day and a reduction in flat time within individual hole sections.To address operations that do not include drilling of rock, the operator has launched a similar effort and workflow process which focuses on "flat time" portions of the well construction process. This has become a key focal point in the organizations approach to maximize capital efficiency. The Flat Time Reduction process provides an environment in which operations are optimized while further enhancing a workplace where "Nobody Gets Hurt."This process is yielding significant savings globally and has been accomplished through planning, "real-time" recognition and response, collaboration with service providers, and a focus on Non-Productive Time (NPT) reduction while continuously improving safety performance. Field applications of limiter redesign are discussed in this paper. The purpose of this paper is to present the current status and specific approaches being used to reduce flat time and share the workflow process.In 2004, the operator started a pilot program to determine if drilling performance could be improved by analyzing and reacting to trends in Mechanical Specific Energy (MSE) 1, 2, 3 by rig site personnel on a real time basis. MSE is a performance measurement parameter that approximates the bit's drilling efficiency and is a function of the weight-on-bit (WOB), surface torque, bit rotation per revolution (RPM) and the rate of penetration (ROP) for a given hole size. When the bit is drilling efficiently, MSE will be steady and will approximate the rock's confined compressive strength. When dysfunction occurs, MSE increases
This paper discusses the operator's use of pressurized mud cap drilling (PMCD), a form of Managed Pressure Drilling (MPD) technology, to successfully capture reserves in Qatar's North Field that were not accessible with conventional drilling operations. While drilling off one of the platforms, the operator encountered faulting, vugular porosity, and Karst features in one particular carbonate sequence that led to the total loss of returns, which could not be controlled with lost circulation material or cement squeeze operations. After reviewing the drilling alternatives, the operator determined that PMCD was an enabling technology to drill through the problematic lost circulation interval in the 12¼-in. hole section above the reservoir. Risk assessments confirmed that PMCD could be conducted both safely and effectively utilizing a rotating head (RH) rigged up on top of the existing well control package. The North Field platforms are located in the offshore Arabian Gulf and provide unlimited access to seawater. PMCD requires injection of potentially large volumes of fluid down the drillpipe and by the casing / hole annulus. Since seawater was abundant, it was the consensus fluid of choice. A review of the formations drilled in the 12¼-in. hole section confirmed clays were not present and that borehole instability would not be a concern. In addition to reducing operational complexity and trouble time, the use of PMCD in this case was also driven by the operator's drilling performance management process which dictates that performance limiters be identified and extended following a specific process. Consequently, this application of PMCD was structured to maximize footage per day rather than only address the lost returns costs. The paper discusses both the lost returns management and the associated efforts to maximize performance gains. The paper will address PMCD well control and injection equipment requirements as well as the drilling and liner running operations on the first well. The area geology and the field's history with lost returns will also be discussed. Introduction Qatar's North Field is located in the Arabian Gulf and is the world's largest non-associated gas field (see Fig. 1). All drilling operations are conducted with jack-up drilling rigs in water depths that average 225 ft. The stratigraphy and a typical wellbore configuration are shown in Fig. 2. Most wells are quite similar in terms of lithology, hole size, casing configuration, and casing setting points. Aside from one vertical data well at each platform location, all wells drilled by the operator are approximately 60° S-shaped directional wells with an abbreviated drop section into the reservoir. Several horizons are prone to intermittent to complete lost returns due to fracturing, vugular porosity, and Karst features. Karsts are void spaces in rock created by dissolution and / or erosion of the carbonates. The size of a Karst can vary from 1 cm up to the size of a cave. It is quite common for the drillstring to drop 1 ft or more when encountering these horizons, as is the case in similar carbonate sequences around the world. Reducing losses to drill ahead safely using lost circulation material and cement squeeze operations have proven to be expensive, time-consuming, and only partially effective. When deemed necessary, the operator has used floating mud cap drilling (i.e., drilling with a static fluid column in the annulus) for short sections through these problem intervals prior to attempting any lost returns remediation work. Drilling an entire section length with total losses had not been attempted due to the higher risk of mechanically sticking the drillstring from cuttings fallout and the complications imposed on well control management.
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