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April 2009

Cover Story

Subsea system worries

High integrity pressure protection systems (HIPPS) have been around for years, but industry seeks new version for ocean floor use

By William M. Taggart IV

Why is the offshore oil-and-gas sector struggling with writing a new standard for an old subject?

It has to do with the unique location where these new high integrity pressure protection systems (HIPPS) will locate—subsea.

As the oil/gas industry moves into deeper and deeper waters, the tool of choice is increasingly becoming subsea production.

Locating the classic Christmas tree well head on the ocean floor saves the weight and cost of the pipes required to extend those wellheads to the surface, but it also involves changing the wellhead into something resembling a NASA project.

With subsea wells going in at 10,000 plus feet where ambient conditions are less than 40°F at 4500 psig external pressure, access to the plumbing is only via remote operated vehicles (ROV). ROVs are expensive to operate and in short supply.

Still, why HIPPS?

The answer is many of the newer subsea wells are accessing deeper, higher-pressure reservoirs, which can only deliver product to nearby existing infrastructure (platforms and pipelines, designed for lower pressure fields) to remain an economical venture.

A HIPPS system located downstream of a subsea well provides a barrier (called a “spec break”) between the high-pressure oil/gas reservoirs and the lower pressure infrastructure.

In this case, HIPPS is the only means that would allow tying into the lower rated systems. The costs for a separate high-pressure infrastructure could very quickly result in costs that not only make the development uneconomical, but also would result in expending more energy than would be gathered from the wells.

Along the same lines, there are many reservoirs, which industry has overlooked in the past because they either would not flow or not flow at an economical rate. 

In today’s climate, these wells are receiving more attention, and prospectors are considering options like subsea pumps in order to obtain that higher and economically viable flow rate.  Subsea pumps come with their own set of challenges, one of which includes a potential to over pressure the downstream flow line. HIPPS is one option to mitigate this problem.

Another reason for using HIPPS is as water depths increase, it is becoming harder and harder to lay high pressure piping systems. The very weight of the high-pressure pipe hanging from the rear of the lay vessel is reaching loads, which fewer and fewer vessels can handle, and reaching points where the stress induced by the weight of the pipe is requiring the pipe to be thicker.

Thicker pipe wall not only increases the expense of the project, but thick steel wall requires special welding techniques and post weld treatments, which are having to be done on the back of a pipelay vessel out in the middle of the ocean.

Using a HIPPS system to reduce the design pressure and thereby reduce the wall thickness may be required in ultra deep waters to even allow installation of the flow lines, which tie the subsea wells back to surface facilities.

Unacceptable failures

Six HIPPS systems are at work in the North Sea between the U.K. and Norway. These systems meet different corporate and regulatory standards. The U.S. regulatory body, the Mineral Management Service (MMS) of the Department of the Interior had several concerns with the North Sea designed systems serving in the U.S. jurisdictional waters without additional redundant design safeguards being included.

Recognizing this directive of redundancy to offset a lack of regional operating experience, and wanting to establish a uniform set of rules and requirements for Subsea HIPPS, industry has formed the API 17O committee, with participation from the MMS, to produce a new recommended practice.

A concern of the MMS is that for mandated safety devices (down-hole safety valves, Christmas tree master valves, platform-boarding valves, and the like) frequent testing is required to confirm their efficacy.

Leak testing of valves, which authorities there have waved in some North Sea applications, would not be acceptable to the MMS because of the periodic shut-in of fields due to storms and equipment maintenance.

During a prolonged shut-in, a leaking HIPPS valve would gradually re-pressurize the downstream flow line and infrastructure beyond their design limits with no means to mitigate over pressured conditions.

In addition, MMS required industry consider and plan for a HIPPS failure. While the likelihood of a HIPPS failure is minimal by its very design, field designs of all downstream systems require a hard look to determine where a failure could be tolerated.

Subsea flow lines almost always terminate at manned facilities. A failure at such a location is totally unacceptable; therefore, we design a protective segment to fail an acceptable distance away from the facility prior to overpressure at the facility.

An overpressure event occurring at this location, while causing a hydrocarbon release to the environment, is a lesser evil than a release that may cause fatalities on a manned facility.

Another concern is the formation of a hydrate plug directly downstream of the HIPPS valves that would result in a high pressure before the HIPPS valves could close fast enough to prevent it. This created the concept of the fortified zone, a section of pipe directly downstream of the HIPPS valves, which rates to the same pressure as the upstream section.

We calculate the length of fortified zone based on the reaction/closing time of the valves and the liquid properties. A compressible fluid would require less fortified zone, while an all-liquid non-compressible fluid would require a longer one.

Seafloor and back

The major differences between a surface HIPPS and a subsea HIPPS are the requirement for a lack of physical intervention and the material and design requirements of operating in an immersed cold, high pressure seawater environment with potentially corrosive hydrocarbons. The material requirements are the same that industry has developed from years of experience with subsea wells and comes sometimes through expensive experience with previous failures.

Material specification and inspection requirements are far in excess of what would be necessary for a surface installed HIPPS. That is because the cost to retrieve a failed system from the bottom of the ocean would be in the millions of dollars.

Human physical intervention is only available through retrieval of the subsea systems to the surface or through ROVs. With the increasing number of subsea projects in the Gulf of Mexico region, intervention vessels with ROVs are scarce and expensive.

Regular testing and operation has to be a part of the system design and work in such a manner as to not require ROV intervention. Remote operation via communicated signals to local controllers is the only solution available.

A Subsea HIPPS would have several pressure transmitters, and some can be located downstream or between the HIPPS valves.

The increased number of sensors is so transmitters have installed back-ups to satisfy industry standards of safety performance. Transmitters assure the HIPPS valves close during an event and they remain closed until the event has passed and is no longer a concern.

Transmitters between the valves may also help in the leakage testing of the valves. To perform leakage testing, an extra valve connects tubing to the space between the HIPPS valves; this allows technicians to inject a chemical (usually methanol) to verify the valves are holding and not leaking and to allow equalizing pressures across the valves prior to opening.

The pressure transmitters featured on subsea HIPPS usually include a more costly internal dual redundant sensor (schematically depicted as a double PT circle) to provide redundancy on a single installed location.

The increased cost of the transmitters is quickly justified when intervention costs to replace a single failed transmitter are considered.

The logic controller is a part of a subsea control pod. The pod is designed to not only withstand the pressures and temperatures encountered on the bottom of the ocean floor, but the requirement for installation and retrieval where the pod has to transition from surface conditions down to the seafloor and back.

The change in pressure and temperature requires oil-filled electronic spaces with compensators. Underwater compatible electric and hydraulic connectors exist for subsea wells, and they can aide in the retrieval of pods.

Most subsea valves do not have limit switches as they are considered unreliable and unnecessary; limit switch technology is limited in the water depths so valve status for subsea wellheads is inferred through monitoring of the hydraulic pressures to the valve actuators.

Not only is there pressure monitoring, but also monitoring of the pressure response to confirm the tubing between the subsea control pod and the valve actuator is not plugging up, kinking, or otherwise failing. This lack of feedback from the actual actuator makes placement and reliability of the pressure transmitters critical.

Valves are also equipped with ROV overrides to allow an ROV to lock the HIPPS valve open. This is for when the subsea wells pressure falls off over time and at some point the HIPPS system will no longer be necessary and the valves can just lock open.

State of the art and standard

After three years of work, the recommended practice is entering the final phase of committee editing and should be available for industry ballot in this year.

The committee makeup includes oil/gas operators, engineering firms, subsea equipment vendors, and representatives of the MMS. Their collective and varying views have melded into one, and the result is a recommended practice, which will serve the oil/gas industry well for using HIPPS subsea.

ABOUT THE AUTHOR

William M. Taggart IV (William_Taggart@murphyoilcorp.com) is a senior staff engineer for Murphy Exploration and Production Company-USA for process control and process safety of deepwater facilities. He has been active on the API 14C committee (offshore topsides process safety), ISO 10418 committee (international version of 14C), API 17O committee (Subsea HIPPS), and ISA84 (Process safety). Taggart acknowledges Christy Bohannon of the Minerals Management Service, Christopher Curran of BP Exploration and Production, and Brian Skeels of FMC Technologies for their contributions to this article.