The pressure is on

Quietly, but surely, high-pressure, high-temperature expertise is being developed on the UK Continental Shelf. Elaine Maslin sets out the detail.

Action on Alder. Photos from Airborne.

The North Sea’s latest high-pressure, high-temperature (HPHT) development to come onstream was Chevron’s Alder field – a project that saw a field discovered in 1975 finally brought online 41 years later (November 2016), thanks to a string of new technology developments.

It joins Total’s Elgin Franklin HPHT development in the central North Sea, which was challenged with pressures up to 15,500psi and temperatures up to 350°F (176°C) (OE: August 2014). The discoveries were made in 1991 and 1986, respectively, and took 15 years and US$24.1 million (£20 million) of research investment to bring online. Next to come onstream will be Maersk Oil’s Culzean development (OE: December 2015), with first oil expected in 2019.

The pressures and temperatures are high – a household pressure cooker works at a maximum 15psi and 250°F (121°C). A standard coal plant steam working pressure is about 2460psi. Alder is 12,500psi and with temperatures up to 302°F (150°C). Culzean is higher yet, at 348°F (176°C) and around 13,500psi.

The 2005 Jackdaw discovery saw even bigger numbers, at 17,250psi reservoir pressure and temperatures at 385°F (196°C) at its base (OE: August 2014). Operator BG Group, now part of Shell, had to qualify new equipment to carry out a 2012 drill stem test on Jackdaw.

Despite the difficulty and cost of these wells, HPHT exploration continues. Total started drilling its Sween HPHT exploration/appraisal well in the northern North Sea earlier this year. It has potential gross mean gas reserves of 107 MMboe, with upside potential of over 200 MMboe, according to farm-out documents.

Meanwhile, the UK business of CNOOC-owned Nexen Petroleum is planning two North Sea HPHT exploration wells, starting with Craster, west of Shetland, this year, followed by Glengorm. Drilling was due to start on Craster, using a semisubmersible and a Plexus HPHT wellhead system, in June-July 2017. Glengorm will be drilled in the central North Sea using a heavy duty jackup.


Chevron has said Alder had seven technology firsts to get it to first production. The field, discovered in 1975, is about 160km from the Scottish coastline in Block 15.29a, in 150m water depth. The development is a single subsea well drilled using the Blackford Dolphin semisubmersible drilling rig and tied back, via a 28km pipeline, to the existing Britannia platform.

The project has a planned design capacity of 110 MMcf/d of natural gas and 14,000 b/d of condensate. Produced fluids are processed on a new dedicated 800-ton topsides process module, built by OGN in Newcastle (recently acquired by Smulders) and installed on the Britannia bridge-linked platform.

Chevron assessed the field numerous times, but it wasn’t until 2009 that it saw that technology to unlock it could be available, as well as having capacity on the Britannia host facility. Key technologies used to unlock the field included Chevron’s first vertical monobore subsea tree system; a subsea high integrity pressure protection system (HIPPS); and a specially designed corrosion monitoring system to measure the real-time condition of the production pipeline. It also used vacuum insulated tubing and a reeled 10in/16in pipe-in-pipe system.

A subsea cooling loop was also developed to cool the production from 150°C to 115°C as it enters the subsea pipeline. But, then to keep the production warm, to prevent hydrate formation, a pipe-in-pipe system is used for the 28km tieback to Britannia.

Technip had the contract for the detailed engineering, procurement, installation and commissioning of the subsea system. OneSubsea supplied the two HPHT vertical, subsea monobore trees and wellheads. Aker Solutions supplied the subsea control system, including the topsides hydraulic and electrical components.

Another technology first was provided by Airborne Oil & Gas, headquartered in Ijmuiden (Port of Amsterdam). The firm supplied a 12,400psi, 126m-long, 1in internal diameter, 0-20°C operating temperature methanol injection spool for permanent service on Alder. To date, thermoplastic composite pipe (TCP) has been established for use in temporary applications, such as downlines or injection lines, but not permanent service.

Airborne’s TCP is made from carbon fiber or glass fiber and polymer tape meld-fused together, with a coating.

The Alder jumper was made from made from e-glass and polyethylene. It has a 1m minimum bend radius and a 15-year design life.

One of the main benefits of using a TCP jumper was that it was lightweight – just 1kg/m in water – enabling remotely operated vehicle manipulation subsea, said Jessica Lyon, subsea engineer, Chevron Energy Technology Company, at Subsea Expo earlier this year.

Martin van Onna, chief commercial officer, Airborne Oil & Gas, told Subsea Expo that TCP also has a high collapse rate, and high internal pressure rating and fatigue capabilities.

An Airborne Oil and Gas 6in TCP flowline. 


Proving the pipe was fit for service was a challenge, because there wasn’t a dedicated standard for TCP, he said. Airborne used the standard for composite materials and a recommended practice for qualification of new technology and then chose the highest safety class, leading to the highest safety factors. “Stress, strength, strain, stiffness, were tested through the product life cycle, from manufacturing to transport and maintenance,” van Onna says. Burst and collapse testing was to 2400 bar. “We have proven that we understand the performance of the pipe and we are able to qualify it,” he says.

The pipe was installed September 2016 using Subsea 7’s Deep Arctic. Flowline Specialists were used for handling the pipe, as they had previous experience handling Airborne’s TCP.

A subsea carousel was used to limit the free span and give the divers maximum control of the product. Flowline Specialists also supplied under rollers with delivery reel and turn table for the carousel.

The pipe was laid from the tree to the manifold using the carousel, hung from the vessel’s crane, freely rotating for the diver’s handling ease. The jumper was installed in 13 hours. Following hook-up, a leak test was carried out, and since field start-up on 1 November, the jumper has been used a number of times.

“TCP is already established as a temporary solution, but we have now shown it is viable for permanent solution,” van Onna says. “We hope Alder will be the first of many. We will see it used for jumpers and larger flowlines, and risers in years to come.”

The technology was originally developed for coiled tubing to handle rapid gas decompression.

Faster fit

Airborne Oil & Gas’s technology development is not just about the pipe itself and what it can withstand, it’s also about logistics. Airborne has developed the end fittings for its pipe in such a way that they can be fitted fast. It is clamped on, the liner reamed, wedges applied and a sleeve pulled over them, clamping it in place, all in about 2-3 hours.

This means long lengths of pipe can be supplied and specific lengths cut off as and when needed, with in-field terminations carried out during installation. This has the added benefit of making the pipe a component, not a final product, which creates less havoc when it comes to local content laws.

“They can reel off the length they need, cut it off and terminate it and install quicker,” says Martin van Onna, chief commercial officer at Airborne. “You can use half the length and at lower cost than jumpers.” Furthermore, “termination can be offshore and we have done it offshore,” he says, which means that J-tubes can be smaller, as they don’t need to also accommodate the wider end fitting.

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