In high-temperature wells or in high-temperature gas injection wells, casing thermal stress is an important issue that should be considered in well design. Stresses introduced by well temperature changes could be severe and critical, resulting in catastrophic well integrity failure and surface equipment damage if not properly identified. The problem can be more severe when a high-temperature well is constructed in a cold environment; the temperature increase from the equipment's as-installed condition to operation conditions would be even higher. A deepwater well or arctic area well installed in winter needs special consideration for thermal stress. A field example in this paper demonstrates a near miss catastrophic well integrity failure. The incident will be analyzed by using a multistring well thermal growth model to calculate casing thermal stress and wellhead growth. Casing thermal growth and stress is sensitive to the length of free moving casing sections. In this paper casing thermal behavior and wellhead movement will be discussed by analyzing different casing string top of cement (TOC) depths. This paper demonstrates how to minimize thermal force and reduce wellhead thermal growth by optimizing the casing cement level. At given conditions, adjusting surface tension during casing installation can also help counterbalance thermal force. It is important to understand the thermal forces and behavior of all casing strings in a well during its operational life.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe present deterministic pore pressure and fracture gradient prediction techniques simplify the input variables f rom a statistical range of data to a deterministic value, thereby producing over-simplified deterministic pore pressure and fracture gradient results. As a consequence, we lose the ability to quantitatively analyze risks, and we cannot quantify the uncertainties of our pore pressure and fracture gradient prediction. This paper describes a methodology for quantitative risk analysis (QRA) of pore pressure and fracture gradient prediction and shows that applications of QRA in this area will improve the techniques of pore pressure and fracture gradient calculations. In addition, QRA will open a full range of new applications in risk prediction, risks evaluation, risk management, decision making, real-time kick and loss-return risk monitoring, risk control, and casing design.
Wellbore instability is one of the most consequential drilling operation risks. Planning a trajectory without knowing the wellbore instability risk can be costly during operations. It is critically important for engineers to be able to validate wellbore stability coherently when trajectories are planned and be able to adjust and optimize a trajectory to minimize the risk during the planning phase. The risks of wellbore collapse in the buildup sections, if the trajectory azimuth is not optimized with formation stress orientation, could be catastrophic. Due to shale heterogeneity, the horizontal section of the wellbore also has a high risk of wellbore instability. All the wellbore instability issues can lead to non-productive time and increase the cost of well construction. The solution presented in this paper is a cloud-based, coherent trajectory planning solution with wellbore stability validation using a Mechanical Earth Model (MEM). Detailed well planning is required to mitigate all the wellbore instability issues. This cloud-based, coherent wellbore stability validation provides an efficient way to improve trajectories by advising the best azimuth and hole inclinations to avoid wellbore instability risks. The MEM is automatically used to compute the wellbore stability (WBS) on the trajectory design. Mud weight can also be validated in the wellbore stability model based on the mud weight window provided by the MEM. In the cloud collaborative environment, all other well planning workflows, such as BHA, casing design, etc. will be validated with the designed trajectory. A case study of unconventional well planning will be presented to show how to avoid wellbore instability by choosing a different trajectory than original proposal. In the case study, WBS was computed from a MEM whose data are acquired from wireline logging. This study mitigated the risk of wellbore instability in the curve section by changing the dogleg of the trajectory. Simultaneously, mud design, BHA design, and casing design were concurrently validated to ensure safer and better well planning. Non-productive time was avoided because of a better trajectory design and wellbore stability. This new workflow can help operators optimize well trajectory with reduced effort and deliver high quality well planning.
PETRONAS Carigali and Schlumberger IPM have formed an alliance to develop a field in offshore Malaysia. Due to space limitations, a platform extension was installed to accommodate three additional conductor sharing wellheads (CSW). Project challenges include limited CSW pass-through, well collision risk, highly unconsolidated formations in the angle building section, directional control and shallow gas zones. To avoid well-to-well collision caused by poor directional control, a pilot hole must be drilled under the conductor to provide good directional control in the unconsolidated sandstone. The pilot hole must also mitigate shallow gas risk. To achieve the reservoir hole size and accommodate dual gravel-pack completions, the pilot hole must be opened from 8–1/2" × 16" to allow subsequent hole section drilling. The project team had to design a BHA that could efficiently deliver the objectives with minimal rig time. To solve the challenges a new hole opening methodology would be required. The pre-drill analysis included studies in: BHA durability/dynamic stability to ensure good hole quality; hydraulics and fluid dynamics to deliver proper cooling and hole cleaning; optimized combination of hole opening technologies. To reduce reaming runs/bit trips, a dynamic modeling system was employed to quantitatively analyze the interaction of various downhole tools and optimize the BHA configuration/drilling parameters. The modeled dual eccentric PDC hole-opening BHA was run and successfully solved the challenges, mitigated risks and met the required drilling objectives for completing the six CSW wells. A post-drill simulation analysis was performed to analyze the dynamic downhole BHA behavior with the actual operating parameters. The authors will explain how the BHA was developed and successfully used in the field to solve the unconsolidated formation challenge. Survey method and challenges of drilling through the conductor sharing wellhead are also discussed.
With the development of modern drilling technologies, the drilling industry has been pushing the envelope of well trajectory geometrical profile (such as ERD or horizontal wells) and the total number of wells possible from a single drilling location, such as an offshore platform or template. Risks involved in drilling these multiple "difficult" well trajectories have become significantly higher. The risks and difficulties are introduced by wellbore location uncertainty, accumulative wellbore friction, large horizontal step-out, high degree of change in inclination and azimuth, and complexity of well trajectory geometrical profile, etc. There are many ways to place the wellbores for selected targets. However, risk and complexity in trajectory may vary greatly, and could be affected by many factors, such as collision risks, trajectory geometric shape, total measure depth and true vertical depth, change rate of inclination and azimuth, tortuosity, build up rate, and torque and drag. All these factors should be evaluated together during trajectory design. An engineering approach should be used to quantitatively measure the risk and complexity of each trajectory. Only then can the trajectories be optimized with potential for reduced operational risk and cost reduction. This paper presents an engineering methodology and mathematical algorithms to quantify risks involved in different well trajectories, by calculating a Trajectory Risk Index (TRI). For the first time, the method combines collision risks, well geometry profile, tortuosity, and torque and drags factors in one simple measurable factor, to make a complex problem simpler. Applications of this engineering methodology are discussed with results for actual trajectory design data. The relationship of trajectory risk index and well cost is also identified and applications are discussed. Introduction After geologists and reservoir engineers identify drilling targets, it is the drilling engineers job to design the wellbore trajectory for these targets. For the case of drilling multiple wells from a template drilling center, especially from an existing template or platform in a brown-field, there are many risks that need to be considered such as collision, trajectory geometric shape, true vertical depth and horizontal departure, inclination and azimuth, build-up-rate, tortuosity, and torque and drag. Risk level for each wellbore is different. Most of the time reservoir engineers would like to combine multiple targets into one trajectory to save drilling cost, and this will often require the well trajectory to change in both inclination and azimuth. If nearby wells are close to each other, such as drilling from a platform, collision risk will most likely be high; potentially requiring a trajectory designed to build and turn, sometimes aggressively, at shallow depth to avoid collision. On the other hand, even when a trajectory is safe from collision under normal designed operating conditions, any tool failure or human error could increase the ellipse of uncertainty and increase collision risk. When designing a well trajectory, all risks and sensitivities of the risks should be estimated, and trajectory design should be optimized accordingly. After wells are drilled, evaluation and benchmarking drilling performance is also important for learning and future design and operations.
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