The HPHT challenge

Elaine Maslin

July 25, 2014

Total E&P UK’s HPHT Elgin Franklin complex. Image from Total E&P UK. 

High-pressure, high-temperature developments are on the increase in the UK North Sea. Elaine Maslin went to an Oil & Gas UK breakfast briefing in Aberdeen to find out more.

North Sea operators are breaking new ground and investing in new technology development to bring high-pressure, high-temperature (HPHT) and ultra-HPHT fields onstream.

It is an extreme, expensive, and challenging game, but one in which many see the potential for some sizeable new developments in the North Sea.

The numbers are high. BG Group’s Jackdaw discovery, in central North Sea Blocks 30/2a (BG Group 44.1%), 30/2d (35%) and 30/3a (30.5%), contains 125-250MMboe and a wider development taking in other fields in the area could unlock 0.5billion boe, BG Group’s managing director, Europe E&P, Andy Samuel, told Oil & Gas UK’s HPHT breakfast briefing in Aberdeen early June. This would amount to 10% of the UK’s domestic gas consumption needs.

But, Jackdaw is also an extreme field, with 17,250psi reservoir pressure and temperatures at 385°F at its base, making it the highest pressure field found to date on the UK Continental Shelf.

It is new territory. BG Group had to qualify new equipment to carry out a 2012 drill stem test on Jackdaw. Giving an example of the technology that will be required to develop the field, Samuel said BG has been assessing a high integrity pressure protection system (HIPPS), involving numerous fast-closing ball valves, weighing well over 10-tonne each, on the development’s well head platform.

Jackdaw was discovered in 2005. BG has since run a four-well, £450 million appraisal program, from 2007-2012. The discovery extends across three licenses, with lean gas-condensate in high permeability Jurassic reservoir, similar to Total E&P UK’s Elgin Franklin development.

Samuel says BG has been through concept select on Jackdaw, with a three-platform base case concept, “remarkably similar” to a development concept chosen by Maersk Oil North Sea for its Culzean HPHT development, also in the central North Sea.

But, costs are crucial on Jackdaw and it is taking longer than BG Group had envisaged to make its economics stack up. The firm is assessing the potential for Jackdaw to be part of a larger cluster development, taking in other nearby fields and prospects, operated by BG as well as other operators, primarily GDF Suez E&P, but also Maersk, to make it and other projects it work.

Despite the challenges, operators, including BG Group, say there is a “substantial yet to find prize” in HPHT.

 
Maersk’s proposed Culzean development. Image from Maersk Oil UK. 

How it is done

Total E&P UK has led the HPHT-way with its Elgin Franklin HPHT development in the central North Sea. It was challenged with pressures up to 15,500psi and temperatures up to 350°F.

It has had a learning curve, due to the 2012 well control incident on Elgin, but it is also extending the development. In the fourth quarter, it is due to bring on stream two new platforms at the Elgin Franklin complex—West Franklin and Elgin B—part of the development’s life extension, from 22 years, as initially anticipated, to 32 years.

Philippe Guys, managing director, Total E&P UK, told the Oil & Gas UK briefing that HPHT is a large proportion of Total E&P UK’s operated reserves, totaling 54%. Some 48% of the UK’s yet to find reserves are in the central North Sea, of which 25% is thought to be HPHT, he says.

“It (HPHT) is a big deal to us, these are highly technically challenging fields we need to develop,” Guys says. But it is also a niche, he adds. “We had to develop new tools for this.”

Franklin was discovered in 1986 and Elgin in 1991. It took 15 years and £20 million of research investment, before both could be produced.

Initial development challenges included 3-4% carbon dioxide, 30-50ppm hydrogen sulfide, and a 1100psi, 190°C temperature reservoir. There was also 175 g/l formation chlorides. Gas also had to be delivered to the grid to specification, which added to the challenges.

To meet some of these challenges, a large well bore completion (5in, tubing) was used to avoid local focal stress on production tubing. A 15,000psi coiled tubing system was developed for through tubing perforations, a production packer was designed and qualified for Elgin Franklin, and the company had to develop and qualify a 12in, 12,500psi emergency shutdown valve, Guys says.

To reduce costs, Total used a TGP500-design platform, to limit offshore commissioning and hookup as well as offering a simpler decommissioning solution. A drawback is a weight limit, Guys says. The firm also used titanium heat exchangers, which are no longer in production, which could pose a future problem. Other innovations included a large diameter (42in.), high temperature (165°C) pipe in pipe bundle, which included foam insulation, qualified to 160°C, and a special caisson cooling system design for the Franklin wellhead platform.

When Total was developing Elgin Franklin, Shell was developing its nearby Shearwater field, another HPHT development. Guys says the firms collaborated on a number of areas on these projects and now even share a backup power supply.

 

BG’s Jackdaw discovery. Image from BG Group. 

A more recent challenge on Elgin Franklin was developing extended reach wells to produce the Glenelg field, discovered in 1999, and developed in 2006, with a 7.7km-long well, at a 4km step out.

In 2008, Total drilled its first infield well on Franklin, which has helped to extend the development’s field life. Initially, the firm had not thought infill well drilling would be possible, due to pressure depletion on the field. But, a well drilled in 2008 produced, “opening a new horizon,” Guys says. Technology used included stress casing mud and using graphite and calcium carbonate to plug the fractures in the reservoir as they drilled.

The 2012 Elgin incident gave the firm a major challenge, and learnings. Pressure depletion in the reservoir caused compaction, which resulted in a rearrangement of the chalk fractures, and introduced some permeability. This meant sustained pressure came from a chalk reservoir that Total had not found or expected gas to come from. In addition, a 10¾in. production casing failed below its design parameter “due to unique stress corrosion cracking phenomena due to the joint dope and the CaBr2 brine,” Guys says.

Since understanding how the incident happened, Total has developed a new safety case on Elgin Franklin and a new annulus management system has been developed. To learn more about the behavior of the chalk, Total is planning a pilot using seismic nodes on the seedbed.

Culzean

Another major HPHT development is Maersk Oil North Sea’s £3-4 billion Culzean development in central North Sea Block 22/25a. Discovered in 2008, Culzean could be producing about 5% of the UK’s domestic gas needs by 2020. First gas is due from a new three platform installation, including a 12-slot wellhead platform, in 88m water depth, in 2019. The reservoir is about 4300m below sea level and about 170°C, some 242km from Aberdeen in the central North Sea.

Martin Rune Pedersen, managing director for Maersk Oil UK, says getting wellhead and downhole engineering right will be critical on the project, as well as material specification.

HPHT challenges have been recognized by the UK government, which is out to consultation with the industry on a new tax allowance.