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Facing up to the HTHP challenge

Extreme reservoir pressures and temperatures are straining the limits of current deep-water technology — and putting pressure of a different sort on US regulators charged with approving field development plans

A big part of Russell Hoshman’s job as technical adviser at the US Bureau of Safety & Environmental Enforcement (BSEE) is to anticipate new technologies operators will need to develop and produce oil and gas reserves.

The other side of his role as technical adviser for regional field operations is to review new technology issues and approve or deny deep-water operations plans (DWOPs) put forward by the operators.

Both sides of the job come into play as offshore exploration and production goes after resources in reservoirs characterised by extreme pressures and temperatures, testing the limits of current technology.

“The 158-year history of the oil business is about technology evolution. There was a time when someone would have considered 5000 psi high pressure,” Hoshman says.

Engineering standards are in place for subsea equipment that must work at pressures to 15,000 psi and temperatures up to 350 degrees Fahrenheit.

Anything over that, however, exceeds the limits of existing standards for high-pressure, high-temperature (HPHT) conditions. That is where Hoshman comes in.

“HPHT well design requires that every single piece of the equipment has to be designed new. It’s not just adding on something,” he says.

“There’s not a single piece of a well that is not impacted by HPHT design. Every piece of equipment is being designed from scratch.”

Implementation of a new technology may precede the development of an engineering standard for that technology by as much as a decade.

Two chief drivers for new technology are the need to obtain a resource that is otherwise unobtainable, and the need to reduce cost to increase profitability.

In the first step in the review process, an operator must submit its DWOP containing the plans to use the new technology. The BSEE reviews the plans and assigns conditions of approval.

“When the new technology is implemented, you always learn lessons, so the next time we will adapt to incorporate this,” he says.

HPHTcropRussell

"When the BSEE evaluates a technology we are not evaluating it for its potential for success. We are evaluating it for its potential for failure."
Russell Hoshman, BSEE
 

“We are approving new technologies well before they’re captured in engineering standards. Engineering standards document proven technology, not new technologies.”

While many new technologies are relatively straightforward, he says, extreme pressures and temperatures present many challenges.

“HPHT is as technically complex as you can imagine,” he says.

API Spec 17D, the engineering standard for the design of subsea wellheads and trees, sets the HPHT threshold at 15,000 psi and 350 degrees Fahrenheit.

Some new projects in the Gulf of Mexico will require subsea wellheads and trees rated for 20,000 psi and 350 degrees Fahrenheit for high-pressure fields, or 15,000 psi and 400 degrees Fahrenheit for high-temperature fields.

“BSEE had to get together with the industry, the manufacturers, the operators, to work on this issue. We have been working together on this for 12 years,” Hoshman says.

One of the results is API 17TR8: High-pressure High-temperature Design Guidelines, a technical report issued in 2015 that sets out design guidelines for HPHT equipment. The second edition of the report is due later this year.

“The industry is developing a consensus solution based on technology and science,” he says. “The API technical reports are part of the process, and that has worked incredibly well. To be clear, a technical report is not an engineering standard, but it is a defined path forward.”

A technical report may be converted into an engineering standard or used to revise existing standards.

Safety focus

The criteria for approving a basic DWOP are protecting people, protecting the environment and identifying potential failure modes, along with the consequences of a failure. The overriding need is a plan for recovering from a failure.

“When the BSEE evaluates a technology we are not evaluating it for its potential for success.

"We are evaluating it for its potential for failure. We are focused on if it fails it doesn’t harm people or the environment,” Hoshman says.

“A fundamental requirement of every technology review is if the technology does fail, are there two mechanical barriers in place to keep oil and gas from escaping?

"What makes HPHT difficult is that HPHT equipment are the barriers needed to protect people and the environment.”

Fatigue, for instance, factors into considerations of HPHT equipment. The potential for fatigue increases with the introduction of higher pressures.

A crack can grow unnoticed, and equipment can explode without warning under extreme pressures. Elevated temperatures can damage elastomer seals, causing failure.

4120e913dedb02d859383e2b01001139 ADAPTABLE: Drillships such as Transocean’s Deepwater Asgard are equipped with 15,000 psi blowout preventers but can be upgraded to operate in 20,000 psi conditions.

“When you start thinking about fatigue in an oilfield environment, and you consider exposure to (hydrogen sulfide), carbon dioxide, chlorides, and you have to predict the fatigue life of a piece of equipment, it becomes complex.

Material testing has to be done to determine if the materials are acceptable for this environment. This is new territory for design of oil field equipment,” he says.

Operators who want to exploit resources in HPHT reservoirs, such as those found in the Lower Tertiary Wilcox Trend, have banded together in a series of joint industry projects aimed at developing the necessary technologies.

“Everything in deep water evolved from new technology. There is nothing in deep water that wasn’t new technology within the last 20 years,” Hoshman says.

“We want (the industry) to determine the requirements for equipment design to be safe. We are here to enforce those requirements.”

However, sometimes new technologies conflict with existing engineering standards.

One example Hoshman cites is the industry’s request to “take credit” for external hydrostatic pressure.

If a subsea wellhead and tree in 9000 feet of water needs to contain 17,000 psi internal pressure, he says, some in the industry assert they should be able to take advantage of the 4,000 psi ambient pressure in that water depth, in which case, the tree would only have to contain 13,000 psi differential pressure.

This “credit” conflicted with API Spec 17D, the standard for subsea wellhead and tree, and the BSEE said no.

Hoshman says the BSEE indicated it would consider this if the API developed guidance on this issue.

HPHT TALL ORDER: A typical 15,000 psi subsea BOP stack.
 

The industry responded in 2015 with API 17TR12, Considerations of External Pressure in the Design & Pressure Rating of Subsea Equipment.

API 17TR12 provides guidance on what must be considered when designing equipment that allows “credit” for external pressure.

The BSEE is now considering some HPHT equipment designs based on both API 17TR8 and TR12 guidance.

No approvals have been granted yet, Hoshman says, but if they are it will represent yet another advancement in subsea technology.

“We in the Gulf of Mexico generally are leading subsea technology development for the world.

"Subsea HPHT and utilising external hydrostatic pressure in equipment design is the next step in technology evolution. We have to go here. It’s not a matter of should we go here.

"It’s in the national interest that we develop this technology,” he says.

“If you look at the technology developed in the Gulf of Mexico over the last 20 years, what it has taken us to do what we do, it’s as impressive as the space industry.

“We don’t have any national heroes in the oil industry,” he says.

“We don’t wind up on the front page of the newspaper when we launch a new deep-water production facility or break another record.

"But what we’re doing is as impressive as anything going on in the space programme.”