Bearing the weight

February 1, 2017

Operating in HPHT conditions have led to thicker, heavier subsea equipment that can hold up to extreme environments. Atul Ganpatye and Kenneth Bhalla, of Stress Engineering, discuss challenges associated with the design of this equipment.

Figure 1: Infl uence of heavier HPHT stacks on wellhead/casing system natural period of vibration. Source: Stress Engineering

Increased demand for energy has driven oil and gas exploration and production into challenging environments that place onerous demands on the equipment used for drilling, completion, and intervention activities. Estimating loads experienced by subsea equipment and assessing whether these systems can operate safely and reliably, becomes an important factor.

An understanding of the predicted loads and equipment capacities is essential in ensuring integrity of the system. This is best achieved through close coordination between various elements of the project, namely, materials selection, global system analysis, local system analysis, detailed component analysis, validation testing, and operational parameters. A coordinated system-level approach can go a long way towards ensuring safe, environment-friendly, and economical operations.

One challenge being addressed presently is drilling into high-pressure, high-temperature (HPHT) reservoirs. In the Code of Federal Regulations, the US Bureau of Safety and Environmental Enforcement defines HPHT conditions as downhole pressures greater than 15,000psi or temperatures greater than 350°F. Primary aspects of HPHT conditions that make engineering design of equipment critical are: higher levels of stored energy due to higher internal pressures, degradation of material properties at high temperatures, and limitations of available equipment needed for testing of critical components, as well as the increased complexity of testing procedures. These aspects raise the stakes for safeguarding life, equipment, and environment from the consequences of failure of HPHT equipment. Consequently, equipment and systems used in HPHT applications are subject to greater scrutiny in their design and increased robustness in their verification and validation processes.

There are two trends with respect to HPHT equipment design (with acknowledgement that design of HPHT components and systems is still evolving):

  1. Subsea equipment is increasing in weight and strength. For example, equipment supported by the wellhead and casing system, such as the subsea tree, tubing head spool, or BOP stack, is becoming larger and heavier due to more demanding requirements for HPHT conditions. Moreover, riser joints and other components in the drilling system are being designed with thicker wall to meet design requirements, leading to higher failure loads on the riser components.
  2. Presently, recommended practices are frequently amended to accommodate new findings and improved understanding with respect to HPHT design. For this reason, it is common to find inconsistencies in how various entities interpret HPHT design requirements. These inconsistencies often lead to each entity pursuing its own goals/objectives for their individual design/result, without adequate consideration of system-level performance. Consequently, gaps in understanding of the loads on the system and what the system can safely withstand (capacity of the system) can arise.

These trends can influence the design of sub-systems that are critically important for ensuring the sealing and structural integrity of HPHT wells; for example, the wellhead/casing systems. In this case the current design trends can manifest into one or more of the following performance characteristics for the system:

  1. Restrictive operability under normal conditions and excessive loads under extreme/accidental conditions due to higher static bending loads on the wellhead/casing system for small vessel offsets from the well center.
  2. Potentially increased fatigue damage at locations of interest in the wellhead/casing system due to longer natural period of the wellhead/casing sub-system when heavier subsea equipment is installed on the wellhead (see Figure 1).
  3. Instability of the wellhead/casing sub-system after the drilling riser has been disconnected (or parted) at a large vessel offset due to heavier subsea equipment being inclined at large angles in the absence of restoring tensions from the riser.
  4. Possible migration of the potential weak point from the drilling riser components to critical systems located below the lower flex joint due to the unintended consequence of increased limiting failure loads for the drilling riser components, which might seem desirable when considering the drilling riser sub-system in isolation.

Furthermore, the integrity of the wellhead/casing sub-system may be a concern if designs of the individual components and the interfaces between them do not work together in addressing the higher strength/fatigue demands of HPHT wells. For example, to design a system that can withstand the higher static/fatigue loads arising from the heavier subsea equipment, one would have to not only address conductor casing size and grade, but also the performance of the connectors, welds, design of internal casing strings, etc.

A less acknowledged consequence of the heavier HPHT subsea equipment installed on the wellhead/casing system is that the peak bending moment along the length of the casing tends to get pushed deeper below the mudline (see Figure 2). This effect is exacerbated when the conductor casing has inadequate stiffness (i.e., OD is too small and/or wall is too thin). This necessitates careful consideration of the type and placement of connectors and the quality of welds along the casing system. Casing connectors are typically characterized by relatively high stress amplification factors and casing welds sometimes do not meet the expected fatigue performance – both can result in reducing the fatigue performance of the system. Thus, when the peak bending moments are pushed deeper in systems in the presence of heavier stacks, it is beneficial to place the casing connectors as far below the mudline as possible to avoid exposing them to high fatigue loads; in the fatigue critical region, the fatigue life of the system can be improved by replacing casing connectors with high quality welds.

Figure 2: Schematic showing the infl uence of heavier HPHT stacks on wellhead/casing system response.

Another consequence of using heavier HPHT equipment is the increased tendency of the wellhead/casing system to be unstable during connected operations of the drilling riser, even when at relatively small vessel offsets (see Figure 2). When these stacks are displaced away from the well center, their eccentric weight induces a large bending moment on the wellhead/casing system. This can lead to toppling of the stack, if the casing system is not adequately designed to withstand the toppling moment. During normal operations, this toppling moment can be mitigated by applying higher tension to the drilling riser. However, for accidental scenarios such as drift-off or drive-off of the vessel, operational mitigation measures may not be available, or may not be sufficiently effective to prevent the stack from toppling. For such scenarios, a comprehensive system-level analysis and a complementary risk assessment may be required to effectively address the optimization of the wellhead/casing system design for safe operations.

At a minimum, the following is recommended to be taken into consideration to ensure wellhead and casing integrity for HPHT applications.

  1. Traditionally, component and system designs have been driven by recommended practice documents (API, ASME, ISO, etc.). At times (or in some instances), these guidelines have been interpreted as “rule books”, at the unintended cost of good engineering judgment. The old cliché of “there is no substitute for good engineering judgment” is especially important for HPHT applications, since recommended practices for this equipment are still being developed and pending industry-wide acceptance.
  2. Operators, vendors, and service providers would all benefit from an integrated design approach with more effective communication on how their design decisions are interconnected between various disciplines. Again, a system-level approach is absolutely essential, since a seemingly benign design change in one component can potentially alter the risk profile for the entire system. An integrated approach would also manifest into cost reduction over a project life cycle by early identification of critical issues and reduction in the design iterations. This is universally true for any design process, but especially pertinent for HPHT applications.
  3. A systemic verification and validation program should be implemented in conjunction with a risk assessment/hazard identification program. An effective verification and validation program would be able to identify loads for normal and accidental conditions, whereas a complementary risk/hazard assessment program will aid in the design efforts in focusing on critical outcomes under such conditions.

Atul Ganpatye is a senior associate at Stress Engineering Services in Houston, specializing in riser analysis, wellhead and casing integrity assessment, and global strength and fatigue analysis. Ganpatye holds a BE in mechanical engineering from Mumbai University and MS in aerospace engineering from Texas A&M University.

Kenneth Bhalla is a principal at Stress Engineering Services in Houston, where he has worked for 19 years, and leads the drilling systems group. Bhalla holds a B.Sc (Eng) and M.Sc (Eng) in aeronautical engineering with fluid and structural mechanics, and mathematics, from Imperial College of London. He also holds a PhD in theoretical and applied mechanics from Cornell University.

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