Deepwater is already an important component of global energy supply security. For example, since 2000 more oil has been produced in the deepwater of the Gulf of Mexico than in shallower water. As onshore and shallowwater developments mature, activity is moving not only into deeper waters, but increasingly into high pressure/high temperature (HP/HT) environments. In these deepwater HP/HT environments, the technologies currently in use for exploration and production may have limited applicability. Indeed, the US Minerals Management Service calls HP/HT development the “greatest technological and regulatory challenge to the oil and gas industry today.” Operators and vendors are jointly faced with the challenge of developing safe, environmentally and economically viable technology solutions for deepwater HP/HT applications that will deliver thermal performance, structural reliability and technical assurance.

Unknown territory?

The territory being opened up is not completely unfamiliar. Generic issues such as flow assurance have been under study, and a range of options has been developed over several years. However, the conditions of HP/HT — which can be defined, in deepwater, as temperatures above 300°F (149°C) and pressures above 10,000 psi (689 bar) — call for the use of new insulating materials, as those currently in use today have maximum operating temperatures of about 250°F (120°C).

Capable of developing at even low levels of axial compression, lateral buckling is a particularly important design consideration in HP/HT lines. (Image courtesy of DeepSea)
Problems may also arise in attempts to deploy drilling and production equipment that has proved satisfactory for HP/HT operations and installations on the seabed. Although such equipment has been designed to cope with excessive heat, it has not had to deal before with such extreme ranges of temperature.

Much of the equipment used in shallowwater HP/HT is standard equipment whose temperature and pressure characteristics have been extended. There must be limits to how far such extensions can be pushed. So a safer and more reliable alternative option may lie in the deployment of new equipment designs.

Managing temperature and pressure

Any system design for HP/HT in deepwater needs to address several factors related to the high temperatures that will be encountered. On the metallurgical front, the design needs to recognize that, when high temperature liquid flows through a pipe in cold water, the yield strength of the pipe is reduced — and along with it the pipe’s ability to withstand high pressures, both internal and external.

Sealing technology presents its own challenges. One of the most obvious is the current widespread use of elastomers, which are sensitive to high temperatures.

Meanwhile, high pressures in deepwater raise issues around the possibility or appropriateness of using a smaller pipe diameter. This would help to counter the need for greater pipe wall thickness to handle pressures that could be as high as 15,000 psi (1,033 bar), and possibly even the need for 20,000 psi rated systems. The reduced hoop stress in a smaller bore pipe would mean wall thickness — and pipe weight — could be of manageable size, from both a pipe production and welding perspective. However, the use of smaller bore pipes potentially increases the complexity of the system interfaces with surface, depending on the flow rate requirements (i.e., the total number of lines required).

Developing the necessary technologies to deal with these and other temperature- and pressure-derived challenges requires significant investment. This in itself poses a further challenge, as the industry is at least partially locked in a “chicken and egg” situation: operators generally feel justified in investing in new technologies from their developer partners only where there is sufficient proof that the technologies will deliver payback, while the developers need financial support to develop, test and compare a range of different options in order to ensure the best ones come to market. Solutions to both sets of issues need to take account of their implications across the lifecycle and the physical extent of the project: for fabrication, installation and surface equipment.

A number of solutions are currently under consideration or development. For example, following the failure of the Erskine HP/HT line in the North Sea because of a number of factors, cooling spools were subsequently considered for some of the future Central Graben North Sea developments. Applying cooling spools in deepwater HP/HT systems for the initial high temperature production period, and then switching to an insulated spool once the production temperature has dropped sufficiently, could allow the use of conventional pipe insulation coatings. An alternative solution could be the use of multiple insulating materials — for example, in the form of a split coating, such that approximately 6.2 miles (10 km) from the well the design can revert to conventional coating.

In a similar way, the use of high integrity pressure protection systems (HIPPS) allows the use of equipment combinations with varying specifications (and costs). HIPPS provides a pressure break between subsea systems and equipment rated to higher pressure and the flowline and riser rated to lower pressure. HIPPS constitutes a promising potential move forward for HP/HT in deepwater, although it has yet to receive full approval from the US Minerals Management Service.

Knock-on effects

Aside from the issues outlined here concerning the properties and specifications of the equipment needed for HP/HT deepwater systems, consideration also needs to be given to the motion and other behavior of this equipment when in operation.

One such behavioral issue is lateral buckling of a pipeline laid along the seabed. This is a temperature effect: a combination of the build-up of temperature-induced compressive force in the pipe and pipe-soil friction. Lateral buckling can develop even at low levels of axial compression; it constitutes a particularly important design consideration in HP/HT lines (and also lines with thick insulation coatings exhibiting low submerged weight). The buckling force is exacerbated by a high-pressure design consideration, as it is directly proportional to wall thickness.

The system designer’s aim should be to encourage and enable the system to expand in a controlled manner: i.e., with high certainty, at regular intervals. Solutions include “snake-laying,” or adding buoyancy at certain places along the pipe’s path to reduce friction locally. It is also possible to decrease lateral friction and reduce the severity of the bending in the buckle by elevating the pipeline off the seabed using sleepers, as in the BP King field in the Gulf of Mexico.

Determining the actual effectiveness of any solution can be elusive. Currently the most commonly used approach to finding out what is happening on the seabed is to take a regular (usually annual) “snapshot” of the pipe via a remote operated vehicle (ROV) survey. An alternative approach would be to deploy a fiber-optic monitoring system running along the line and feeding back continuous real-time distributed strain data, yielding a detailed picture of the effectiveness of the lateral buckling mitigation strategy. The benefits of this approach include ongoing performance assurance for the system; in addition, it provides data that can be used for validation of the design tools used and calibration of the system design.

Monitoring can also help where a decision is needed between the use of clad pipe or standard carbon steel pipe. Clad pipe may be required if the product is or may in later life be “sour,” and therefore have significant corrosion issues. For dynamic applications in deepwater, the quality of the pipe welds needs to be very high. However, welding clad, thick walled pipe to such high quality is both expensive and difficult.

Monitoring riser motions increases certainty levels relating to riser stresses and fatigue, and also assists in design validation. It may provide enough data to make a reliable selection in favor of carbon steel in certain circumstances.

Design for installation

Clearly, design for HP/HT in deepwater needs to incorporate several variables, using several different kinds of data (e.g., reservoir, environmental, geotechnical and geophysical, operational time plan). Deepwater and HP/HT conditions combine to create a requirement for systems with greater strength capacity. As with deepwater alone, this has significant impact on the installation phase, particularly with respect to capable vessel choice and availability, construction complexity and, of course, cost. With typically one-third of a subsea field development’s cost resting with the subsea system, and between 30% and 50% of this being attributable to installation, designing for installation as well as operation can yield significant benefits.

Given the constructability constraints and costs of thick walled lines, greater interaction will be needed between the key disciplines of reservoir engineering, flow assurance and subsea system design to achieve robust, cost-effective developments. Each discipline has a number of highly specialised engineering techniques that are applied (e.g., reservoir modelling, flow models, finite element modeling) for identifying and assessing uncertainties and establishing design margins. However, these techniques tend to be applied in a linear rather than an integrated manner, with the outputs from reservoir passing to flow assurance and then on to the system designer. Improved robustness and cost-effectiveness of a development can be targeted through early identification of key variables, constraints and design input uncertainties, making it possible to formulate a road map for an integrated approach across the relevant disciplines.

It could be argued that one of the most critical success factors in this activity will be the ability to take both an integrated and a holistic approach to design. DeepSea’s experience of applying such an approach — considering the whole system and the entire lifecycle of fabrication-installation-operation-decommissioning — indicates the potential for substantial gains. While an integrated holistic approach makes sense in shallow water, it will be even more important for HP/HT systems in deepwater, not least because of the difficulty and expense of maintaining, repairing and replacing components.

The future of HP/HT production via deepwater subsea systems might therefore be divided into two possible scenarios. In scenario 1, no intervention is made to modify fluid temperature and pressure, thus requiring the development of new technologies capable of operating reliably at these extremes. Scenario 2 sees different pressure and/or temperature design inputs between well and wellhead equipment and the subsea production system; these are achieved via barrier or reduction technologies (such as HIPPS), thereby permitting use of existing deepwater production systems.

While these two philosophies are substantially different, they have one important theme in common: both require substantial development and qualification of new technologies for deepwater implementation.

However closely future HP/HT deepwater systems may conform to this vision, they will inevitably take 2 to 3 years to develop. This reality underscores the importance of good relations and close collaboration between vendors and operators, to ensure that the potential benefits of HP/HT deepwater systems for both the industry and global energy supply security are realized.