Elf U.K. expands HP-HT expertise with Elgin-Franklin development

The Elgin-Franklin PUQ platform under construction at Barmac's Nigg yard in Scotland. The jackup platform's three legs will each be 145 m tall. The photograph shows one of the legs rising from within a ring beam, which is mounted over the piles ready to be used during the offshore piling process. Photo courtesy of Elf.

• Projected Elgin-Franklin liquids output, gas sales [131,761 bytes]
• Elgin-Franklin Fields' characteristics [51,415 bytes]
• Elgin-Franklin export routes [84,064 bytes]

A giant jack up processing platform is taking shape in a Scottish fabrication yard as part of the largest development project under way in the U.K. North Sea.

The platform will be installed in Elgin field, which is being developed with nearby Franklin as part of the world's largest high-pressure, high-temperature (HP-HT) field development project.

Elf Exploration U.K. plc is the operator of the Elgin-Franklin gas-condensate project, where two platform jackets have been installed in readiness for wellhead topsides, and development drilling is under way in readiness for the jack up processing platform's arrival.

To develop the fields, Elf has had to overcome many technical hurdles, most obviously in dealing with the difficult reservoir conditions but also in development concept choice.

Joel Fort, Elf Exploration U.K.'s Central Graben asset manager, said the project was made more difficult at first because of the problem of getting consensus among 10 field partners: "It makes things difficult at times, but it also acts as a permanent audit."

Elgin field lies on Blocks 22/30b, 22/30c, and 29/5b, while Franklin lies on Block 29/5b. The water on both blocks is about 92 m deep. Elgin was discovered by Elf in 1991 and Franklin by Ultramar Corp. in 1986.

The operator for the fields is the Elgin-Franklin Operating Group (EFOG) venture, owned 77.5% by Elf and 22.5% by Gaz de France, with Elf fulfilling the role of field operator.

Interest holders in Elgin-Franklin are: operator EFOG 46.173%, Agip (U.K.) Ltd. 13.867%, BG Exploration & Production Ltd. 12.35%, Hardy Exploration & Production Ltd. 8%, Ruhrgas U.K. Exploration & Production Ltd. 5.2%, Shell U.K. Ltd. 4.375%; Esso Exploration & Production U.K. Ltd. 4.375%, Texaco Britain Ltd. 3.9%, and ARCO British Ltd. 1.76%.

Unitization challenge

Fort said that, before development could proceed, the fields required unitization over three blocks, a process made more complex by the fact that the two fields were very different in terms of value.

"The unitization encompassed all perceivable difficulties," said Fort, "and was completed in early 1997 after being started in 1995. It was a nightmare at the time, but now it seems a very good agreement, because there can be no redetermination.

"It was a nightmare with a happy ending. Such a sorted deal frees the spirits of participants from hidden agendas over technical matters, enabling well locations, for example, to be chosen entirely on their merits and not as sometimes has happened."

An unusual aspect of the unitization agreement is that partners get only their allocation of condensate if they take their gas quota, said Fort: "Elf has already sold its own gas, but, because there is no combined sales agreement, we don't know if the others have."

Sixty percent of Elf's gas has been contracted to GdF and will be delivered beginning Oct. 1, 2000, through the Interconnector pipeline from the U.K. to continental Europe. Elf will sell the remainder on the spot market and through its U.K. gas marketing arm.

Reservoirs

Elgin was discovered with the 22/30c-8 well, spudded in 1990, while Franklin was found with Well 29/5b-4, spudded in 1985 by previous block operator Ultramar. Elf later swapped its Markham discovery interest for Ultramar's Franklin stake.

The combined reserves of the two fields are estimated at 700 million boe, and Fort pegged the exploration and appraisal costs for the two finds at $1/boe.

The gas-liquids ratios of the two fields are very different (see table): Elgin has estimated reserves of 889 bcf of gas and 244 million bbl of condensate, while Franklin reserves are estimated at 821 bcf of gas and 123 million bbl of condensate.

Fort said Elgin and Franklin were developed together for two reasons, despite both finds being viable as stand-alone developments. First, a joint development would bring economic benefits from shared facilities. More critically, because the condensate-gas mix in Elgin is much richer than in Franklin, a joint development would enable Elf to get the "best of both worlds"-early sales for liquids coupled with a gas plateau of more than 7 years-for both fields rather than just one (see charts).

"By developing the rich Elgin field with the leaner Franklin," said Fort, "we would be able to produce preferentially from Elgin so that liquids production is up front to bring value to the project and yet compensate for the decline of Elgin by producing Franklin gas to maintain the gas plateau."

Development

Fort said the anticipated total investment in Elgin-Franklin, for which some export facilities are shared with nearby Shearwater field, which is under development by Shell U.K. Exploration & Production, is £1.6 billion ($2.6 billion).

The field development cost target was $3/boe, but, so far, "the trend suggests we will achieve $2.70/boe, which compares well with past projects."

The development plan requires 10 new wells to be drilled in the fields, five in each, while an appraisal well and the discovery well would also be tied back in Elgin field.

So far, the five new wells have been completed in Elgin, and a fifth is being drilled in Franklin. Two Elgin wells have been completed for production. Elf expects to bring Elgin on stream in April 2000 and Franklin that October, with production anticipated to continue at least until 2022.

The fields are being developed with a large processing, utilities, and quarters platform (PUQ) in Elgin plus a bridge-linked wellhead platform in Elgin and a wellhead platform in Franklin.

The PUQ platform will have capacity to process 525 MMcfd of gas and 175,000 b/d of condensate. Fort said the development's value will come two thirds from condensate and one third from gas, although the development's main design constraints relate to the gas.

In Franklin field, Elf installed a 2,500 metric ton jacket in summer 1997, on which will be installed a 2,000 ton unmanned light topsides, remotely controlled from Elgin. Although the Franklin platform will be relatively simple, it will house sophisticated water injection facilities. The Elgin wellhead platform jacket was also installed in summer 1997.

The jackets were built by Lewis Offshore Ltd. at Stornoway, northern Scotland. The two unmanned platform decks were built by Kvaerner Oil & Gas Ltd. at Port Clarence yard in Teesside and are scheduled to be installed during May 30-July 14.

The choice of a jack up for the central processing platform was influenced by the size of the topsides required-18,000 tons-which in turn was decided by the need to process gas to sales specification offshore.

Elf calculated it would be cheaper to build a massive jack up (JU) and float it out for installation than to build an 11,500 ton topsides-the limit for available heavy-lift vessels-and install more modules offshore.

"We had to build one of the largest- capacity platforms in the North Sea," said Fort. "The difference between the JU and conventional design platform prices was £70 million ($115 million) because of the latter's need for heavy-lift capacity and offshore hook-up work."

One benefit of this particular JU concept is that BP Amoco plc had successfully installed a smaller-capacity version of the same design-the TPG 500 by Technip SA, Paris-in Harding field. Much experience from Harding was utilized in the PUQ construction.

Multiphase flow from Franklin will be delivered to Elgin through a 6-km subsea pipeline. The well fluids will leave Franklin at 165° C. and arrive at Elgin at 100° C., which will represent the highest operating temperature for an in-field pipeline: "This required the pipeline to be made from a sophisticated, insulated, corrosion-resistant alloy."

Exports

The ability to export gas to Europe through the Interconnector was critical to the decision to proceed with the development of Elgin-Franklin.

Gas will be evacuated through a pipeline to Bacton terminal, the U.K. end of the Interconnector, allowing delivery through Belgium to other European countries. Liquids will be exported via a link to the Forties pipeline system to Cruden Bay, Scotland.

Fort said Elf studied several export options for gas: to St. Fergus terminal, by a new pipeline to Teesside, through the Central Area Transmission System (CATS) pipeline, and by a new pipeline to Bacton.

"We chose to build a new 34-in. pipeline to Bacton, which at 483 km is the longest pipeline in the U.K. North Sea," said Fort, "because the best market for the gas is Europe. But there was already overcapacity in the other export routes, and there would be high costs involved with upgrades."

One drawback with the Bacton terminal is that it is in an environmentally sensitive area. Fort noted that the developers of the Interconnector found out the implications of this "the hard way." Environmental concerns ruled out installation of Elgin-Franklin processing plant at Bacton: "We wouldn't have been able to install much processing capacity at Bacton, so we had to have the bulk on the platform."

Another factor in favor of offshore processing was the fact that no existing export system could handle the gas and liquids mixture arriving at the platform: "If we had gone the dense-phase route, we would have required very sophisticated systems. So, instead, we opted for one big, heavy processing unit offshore; hence, commercial gas is being produced at the platform."

Elgin-Franklin liquids will be sent by a pipeline link to the Marnock platform-part of the BP Amoco plc Eastern Trough Area Project (ETAP) seven-field development-and from there to shore through the Forties trunkline system.

Elgin-Franklin output volumes will be bolstered by production from Shearwater field, which is being developed by Shell Expro (OGJ, Apr. 21, 1997, p. 29). Shearwater output will pass through the Elgin-Franklin pipeline system under a tariff agreement.

Shearwater also is an HT-HP development. Fort said Elf and Shell decided to share costs in the Shearwater Elgin Area Line (SEAL), which evacuates gas from the fields to Bacton, to reduce costs through economies of scale. SEAL's comparatively low cost per kilometer of pipeline is attributed to buying all the pipe from a single supplier, in Japan.

Elf is the development operator of the liquids lines for both Elgin-Franklin and Shearwater and of the onshore facilities, which will be handed over to Shell at the end of the development, because Elf is not an operator within Bacton and Shell is.

The liquids export line has been laid and is awaiting tie-ins. The SEAL line also has been laid, and spool pieces and subsea intervention valves are being connected up. The modification of the Shell terminal at Bacton is on schedule.

The overall budget for Elf-operated activities in the Elgin-Franklin development was £1.85 billion ($2.96 billion), but Fort said that the project is expected to be completed for a total of £1.7 billion ($2.72 billion).

Fort said the total field capital expenditure is expected to amount to $6/boe, comprising: $2.70/boe for field-development capital expenditures, $0.50/boe for evacuation systems capital outlays, $2.30/boe for field operating expenditures, and $0.50/boe for external export tariffs.

R&D needs

Reflecting on what makes the Elgin-Franklin development so different from other, "bread-and-butter" projects, Fort said, "The 90 m water depth is conventional, but, unfortunately, the water depth is the only thing about these fields that is conventional."

Vertical wells of 5,600-5,700 m are needed to penetrate the reservoir at 5,300 m. At that depth, the reservoir pressure of 1,100 bar is "terrible," although the 190° C. reservoir temperature, while unusual in developed fields, is what would be expected from the typical geothermal gradient of 3° C./100 m.

"What is also not conventional," said Fort, "is the 320 bar dewpoint. This is comparatively low but good for us, because it helps give a high recovery factor. Also, the permeability is very good, in fact, unbelievable for these depths. Again, the high pressure contributes to maintaining the reservoir permeability and porosity.

"But we go back to the bad side when it comes to contaminants. Elgin-Franklin gas contains 3-4% carbon dioxide and 30-40 ppm hydrogen dioxide, which need to be largely removed to meet commercial sales specifications."

Elf expects to recover about 60% of the gas in place. So far, secondary recovery is not planned, because no available technique can work at such high pressure: "This situation may look different in 10 years' time with new enhanced recovery techniques."

Fort said there are only two fields with higher pressures and temperatures: Thomasville, a small U.S. onshore field, and the U.S. Gulf of Mexico's Norphlet 863 field, where Chevron Corp. is operator and Elf a partner. Elf also has experience with HP-HT operations in Lacq field in Southwest France, discovered in 1951.

"The Lacq development was said to be not worthwhile because of its high H2S content," said Fort, "but it subsequently proved crucial to Elf's development of sulfur processing technologies, which it now licenses to others.

"Elgin-Franklin uses Elf's own sulfur removal process. Similarly, with Lacq and Norphlet Elf has had access to HP-HT production data down the years, and this has impacted the Elgin-Franklin development."

The HP-HT nature of the reservoir made it necessary to start the development drilling earlier than on a conventional project, said Fort. Most of the drilling needed to be done ahead of first production.

With Elgin-Franklin, depletion is expected to begin rapidly from 1,100 bar, with a subsequent potential decrease in the fracture pressure of the rock: "To avoid this, almost all wells must be drilled no later than 3-6 months after the start of production.

"This is not good economically, because we must invest up front. The compensation comes in terms of well productivity. We expect to need only 12 wells to deplete Elgin-Franklin."

Because of the complexity of the Elgin-Franklin project, Elf spent £21 million ($34 million) during 1993-96 on preparatory research and development: "We had to master technology that often didn't exist."

The Elgin-Franklin asset group and Elf corporate research center split the R&D funding 50-50. A key issue for the R&D program was how the reservoir sandstones would behave during depletion, when pressures are expected to fall by 600 bar.

Elf had to qualify a special PVT (pressure-volume-temperature) cell to model fluid behavior in the reservoir, because a PVT unit to meet Elgin-Franklin's HP-HT conditions was not available on the market.

Elf developed the PVT modeling software in house but used suppliers to develop the cells. In addition to the PVT cells, Elf also had to qualify other facilities and equipment for such high-pressure operations. Fort cites valves as an example: 6-in. flow line valves, 12-in. gate valves, and 12-in. ball valves all had to be specially qualified.

On the drilling side, Elf had to qualify new tools and procedures, including a completion brine, high-temperature corrosion inhibitors, a new hydraulic fluid for subsea actuators, and fluid loss-gain software.

Elf also designed drilling control software specifically for Elgin-Franklin. Fort said drilling times have been reduced, and the drilling program is well ahead of schedule. While the second Franklin appraisal well took 408 days to complete, typical drilling duration was later cut to about 180 days/well.

"The main reason we were able to improve our drilling results," said Fort, "was the use of an in-house well-design tool, which allowed the drilling teams to understand the pressure on the drilling bit from parameters measured at the surface.

"This tool enabled us to take much of the guesswork out of maintaining the delicate balancing act between blow-out and fracturing these complex reservoirs."

Other innovations included: perforation systems qualified to 200° C.; a 15,000 psi production packer; a 41/2-in., 15,000 psi subsea valve; coiled tubing to 15,000 psi; and a mud line suspension connection to 15,000 psi for production casing duty.

What's next

In mid-July, Elf plans to drill an exploration well in Franklin, which calls for deepening an existing well to the Triassic horizon at a depth of 6,400 m. Here the pressure and temperature are expected to be 1,350 bar and 230° C., respectively.

Because this pressure is beyond the capability of both rigs in use-Santa Fe I in Elgin and Santa Fe Magellan in Franklin-the Magellan jack up was to be fitted with a refurbished 20,000 psi blowout preventer stack used earlier in the Elgin discovery well.

Elgin drilling is slated for completion this October, while Franklin is set for completion in April 2000. Both the rigs were committed under long-term charters, and because of the success of the drilling program, Elf and Santa Fe are currently marketing the 500 days of rig time expected to be available.

"There was lots of thought behind the decision to go ahead with Elgin-Franklin," said Fort. "It is an expensive entry ticket to the world of HP-HT field developers. There are only a handful of operators in this club.

"It was a tough job to get all this equipment ready on time. We got everything developed by the contractors and suppliers, but we had to write the specifications, qualify the programs, and fund the studies. We did a little in-house development, such as the software, but we do not do hardware research.

"We believe it is worthwhile, because we have identified other HP-HT plays near Elgin-Franklin and in other parts of the North Sea. We see HP-HT technology as a key strategic area for Elf, along with deepwater technology."

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