Shell applying new research to marginal prospects

Auk North, Brent, Gannet A benefit from focus

Frank Frazer
Contributing Editor
Scotland

• Auk production history & field development [50,722 bytes]
• Gannet E & F Development [42,478 bytes]

John Dewar, Manager of Well Engineering Services for Shell UK Exploration and Pro duction (Shell Expro), has a vision that some day a single project will combine all the innovative techniques which his team has helped to pioneer to keep the company at the forefront of cost-effective offshore development.

If he is right, his dream well will be in a high pressure/high temperature formation, with multilateral drainage provided by the use of both coil tubing and under-balanced drilling. It will also be fitted with an intelligent completion.

Integrating the individual technologies has become a priority for Dewar's team as the company strives to unlock value from remaining reserves for the North Sea's largest single investment partnership under the long-standing joint venture with Exxon.

According to Dewar, sufficient advances have probably have already been made in the various areas to enable his dream well to be drilled now.

"It's a question of risk versus gain. Each of the technologies has a corner of the market where it can add value and we are already working on combining two or three of them. So, it's just a question of one brave step being taken to combine them all," he said.

Expro in recent years has already taken the bold step of radically changing the way that the development of new technology is managed. Dewar explained that the former centrally-organized and controlled process has been replaced by a system in which areas for research funding are proposed by the front-end business units that will apply the techniques in the field.

Project risk/benefit

Under the new arrangements, the "need-to-know" suggestions are ranked by risk and benefit to determine sums that should be allocated to individual research and development projects. "This is a process we started off last year. We've refined it this year such that our technology planning for next year should be fairly optimum," Dewar said.

By cutting down on hobby-horsing that would have meant spreading resources among 30 to 40 projects, Expro has been able to focus on a small number of major areas that promise the most commercial benefit for research and development dollars. The technologies considered to hold most promise are:

• Multilateral wells to maximize recovery through single boreholes
• Reel drilling systems, including coiled tubing and the development of hydraulic workover rigs to provide a less expensive method of accessing small accumulations
• Under-balanced drilling, which has the potential to unlock vast amounts of reserves considered uneconomic at present in Rotliegendes formations in the southern North Sea
• Intelligent completions to provide better downhole monitoring and flow control
• Techniques to improve drilling into high pressure/high temperature reservoirs that contain about a third of Expro's total reserves.

Dewar said a big push was planned to tackle the difficulties of HP/HT operations, including resolving the complications caused by the slender operating margin between the pressure in the formation and the hydrostatic fracture pressure. "We are operating in as small window as possible in which we either lose fluid into the formation or we get pressure back from the formation and take a kick," he said.

The Expro well technology team expects to resolve the difficulties by a combination of better understanding of HP/HT conditions, more sophisticated modelling and new equipment, leading possibly to the develop ment of different ways of tackling the challenge in the longer term though advances in other areas such as under-balanced drilling.

Auk North development

Among first practical applications for the well technology R&D initiatives, plans have been drawn up to use multilateral and coiled tubing in a scheme for a northern extension to enhance recovery from the Auk field, Expro's first North Sea field which began production in 1975.

Previous studies showed it would not be feasible to develop Auk North by extended reach drilling from the existing platform. The high cost of subsea technology also ruled out a conventional satellite field development.

But the economics are im proved by using multi laterals and electric sub mersible pumps that can be deployed and retrieved on coiled tubing without the need to remove production tubing. Work overs can also be performed faster and less expensively from a light intervention vessel rather than using a semi-submersible rig.

With cost saving ach iev ed in other areas such as pipelines, umbilicals, and topside modifications, the proposals to put Auk North on stream by October 1999 should raise the recovery factor for Auk's oil in place to 23% from 17%. Expro's Auk development team has set a stretch target to get the level up to 30% by using novel technologies in the transitional zones on the flanks of the field which should further help to extend the productive life of the field to at least 2006, from 2002.

Brent coiled tubing

Coiled tubing has also been applied to improve recovery from Shell's Brent field, the largest hydrocarbon discovery in the UK sector of the North Sea. Well No. 38 was completed as a sidetrack from an existing well by using a drill bit on the end of 2-in. diameter tubing, starting at a depth of 9,000 ft below the seabed and travelling some 1,500 ft horizontally to reach about 500,000 bbl of oil reserves, which had previously been regarded as uneconomic to produce.

The well, which went on stream at 6,000 b/d, was completed at about half the cost of a conventional well. The Expro team - working with contractors personnel from Deutag, Transocean, and Baker Hughes Inteq - claimed a world record for offshore operations in terms of the length of sidetrack achieved by the technique.

Completed within one year of the contract being place, the well was the deepest coiled tubing offshore borehole with open hole logs and the first in which stuck pipe was freed by flowing the well.

Apart from the savings on well engineering costs on the Brent project, the success of 38 wells pointed to a low-cost option for tapping many small pockets of reserves which were previously considered uneconomic to put on stream, even with existing infrastructure.

Since the recent completion of a major redevelopment on Brent to extend field life by depressurization to maximize recovery of gas in the final stages of production, engineers are faced the task of reconfiguring well patterns to deal with trapped reserves.

"The redevelopment has made it important to have a more complete understanding of the reservoir," Dewar said. "What we are having is the very challenging task of trying to locate small pockets of hydrocarbons which have been left behind by the flood front and access them economically."

Gannet E pumps

In another venture in pioneering well engineering to tap small outlying accumulations of oil, Expro earlier this year started production from the Gannet E satellite project using a specially-developed electric submersible pump to deliver output from the subsea well to the Gannet A platform nearly nine miles away.

The company claimed a world record for distance covered by the pumping system developed for Shell by Camco's subsidiary Reda Production Services. Downhole monitoring devices were installed to enable Reda to check pump performance in real time from its headquarters near Aberdeen throughout the nine years' expected life of the Gannet E which should peak at 14,000 b/d.

Dewar said that such advances in subsea engineering would be a factor in determining efforts made to increase the distances at which outlying pockets of reserves could be drained by the alternative method of extended reach drilling from existing platforms.

Although extended reach techniques were no longer considered a particularly new technology, Dewar said advances in range that could be covered was important to Expro, which had about 400 million bbl of reserves between three and five miles from existing platforms. "If we can lower the costs and risks associated with extended reach drilling, then we have the possibility of tapping into all these reserves with relatively low infrastructure costs," he added.

Dewar said the present aim was to increase confidence in reliability of drilling from offshore platforms so that distances of three to five miles could be achieved regularly without getting stuck. He admitted that the limits might be pushed farther if there were significant reserves to be reached, but there was a balance to be struck with the other advances that were being made in the costs of draining satellite structures by vertical drilling of subsea wells.

"Improvements in topside engineers, subsea manifolds, and pipeline costs are all affecting the cross-over point," he explained.

Equipped with all the new tools under development, a Shell Expro team has completed a study on the economic benefits of applying appropriate techniques to individual fields. The projects were selected to provide a cross-section of Shell's assets in the North Sea, from mature fields in final stages of depletion to potential discoveries for which investment had not yet been sanctioned.

Details of increments on the production profiles and gains in net present value on individual fields are being kept confidential for commercial reasons. "We were able to improve project economics considerably," Dewar explained. "Where projects were economic, we improved them and where they were uneconomic, we made them economic."

With well engineering costs representing about a third of Expro's total spending in the North Sea, there is clearly a big prize to be won from the efforts to get more value for every dollar spent.

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