UK shelf providing opportunities for independents of all sizes

The Ninian Central platform also hosts the Lyell subsea development.

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"The company saw the North Sea as a maturing basin, offering similar potential to its operations in Canada," says Martin Cole, managing director of CNR International. "There we had been successful in acquiring mature assets and prolonging production through reservoir engineering."

In the UK, Talisman had proven that outright control was the best way of driving tail-end production forward. CNR's first step as a UKCS operator in September 2001 was to persuade the government to waive royalty payments on Columba E, allowing this marginal project to go forward. Like Columba B/D, the geological setting was complex in a downthrown fault block, and would require further development drilling over time to sustain production.

Thereafter, CNR bided its time for a few months before pursuing further equity. From June 2002, it successfully pushed through cash or swap deals with Talisman, Kerr-McGee, Murphy Oil, and Eni. Since last December, it has been operator and majority shareholder of Ninian, Murchison, and the Columba terraces; 100% operator of Lyell, a subsea tieback to the Ninian Central platform; and a small percentage holder in Strathspey, another Ninian tieback, operated by ChevronTexaco. It also has a 54% interest in the 36-in. Ninian pipeline system, 13% of the Brent export system, and 22% of the Sullom Voe oil reception terminal in Shetland.

Additionally, the transaction with Kerr-McGee brought CNR rights to 20 exploration blocks and part-blocks in the Ninian/Murchison area. In Central North Sea Quadrant 29, it has retained control of Kyle and doubled its stake in Banff to 55% through a swap with Enterprise Oil.

Early this year, the company announced a C$280-million sweeping program of development drilling in the North Sea, managed by Aberdeen-based contractor KCA Deutag. Most of this was focused on Ninian and Murchison and the Columba terraces. Here, two wells were planned on Columba D and one on Columba E, following the addition of a new 6,500-b/d producer on Columba B last December.

Uneven development

Ninian was discovered in 1974 and developed four years later with one concrete and two steel platforms, all of which were modified in the early 1990s to handle new production from Lyell, Strathspey, and Staffa. Early this year, Wood Mackenzie estimated that a further 75 MMbbl remained to be recovered, with output averaging 32,000 b/d in 2003. Thereafter, it foresaw a steady decline through to cessation in 2011.

According to Wayne Chorney, production/ operations director, "Companies come to a point where they have cessation of production in mind, so they no longer invest. But we believe that by continuing to invest, through drilling new wells and workovers, you can push up production and value. Take Murchison – when we came in, production was around 8,300 b/d, compared with 100,000 b/d at peak, and there had been no workovers for several years. We're drilling nine wells and two workovers this year alone. This should push us close to 14,000 b/d."

The Murchison wells will include six producers and three injectors, Chorney said, and up to four could be through tubing redirectional drill (TTRD) candidates. Oryx has had only one failure, a sidetrack for a water injector where it turned out the wellbore had fallen away.

"On Ninian, we started drilling last December," Chorney said. "By the end of this year, we'll have drilled 19 wells, of which eight to twelve will be producers, and seven injectors. Three of these wells also employed TTRD, with no failures reported. Our main problem has been an extended shutdown at the Ninian South platforms due to an oil leak in the process pumps."

Oryx decided to replace all the piping straight out, an operation that lasted 40 days. During this program, the company skidded the rig over to Ninian Central to abandon five old wells for re-use in future operations.

"All this time, we've managed to sustain three drill strings simultaneously," adds Cole. "One factor in our favor is that our wells have been very quick, so we've reduced our costs efficiently. That's partly due to the performance of KCA Deutag following realignment of their remuneration terms. Another factor is the use of TTRD, which is a new technology. But even so, our drilling costs have come down by a factor of 2, which is a significant achievement."

Murchison was discovered in 1975, in UK northern North Sea block 211/19a and Norway block 33/9b. The unitized field was brought onstream by Conoco in 1980, with a near 50,000-ton steel platform built by McDermott in Ardersier, Scotland. Original reserves were estimated at 410 MMbbl of oil, with 20 MMbbl of natural gas liquids and 75 bcf of gas. Oil/liquids production at peak reached 114,000 b/d; water injection was used at the outset.

According to Cole, "We now have 78% of Murchison. Our management style depends greatly on significant control. That way, we can be very quick in turning opportunities into results. We've put in wells on Ninian and Murchison that were drilled and completed in one to two months. The previous regimes weren't doing anything."

All four platforms are staffed and run on CNR's behalf by facilities management contractor Petrofac.

"We've been a lot more hands-on with them than the previous operator," says Chorney, "giving them a clearly defined direction of where we want to go. Before, they were left to their own devices, but we regard Petrofac as an integral part of our team."

Following a CNR wildcat well offshore France, the semisubmersible Transocean John Shaw is due to drill an exploration well for CNR on the Jude prospect off Ninian's northeast flank. Jude was one of several targets identified from recently acquired 3D seismic, others being Aidan, Nadia, and Nina.

"At Jude, we're drilling a secondary objective that potentially contains tens of million of barrels of oil," says Cole, "but it's also a higher risk target. That secondary objective was a fan that we spotted, in a new play that we've developed."

A successful outcome on Jude could trigger development through subsea facilities tied to the Ninian Central platform. Any discoveries of 10 MMbbl or under can be tapped via platform stepouts.

CNR is also re-evaluating Lyle, a complex field with 300-400 MMbbl in place. "Potentially, it's very valuable, as there is no associated petroleum revenue tax, the oil being tariffed through the Ninian system. We've undertaken an intervention program there this summer, converting one well to an injector, and we're addressing mechanical problems on the subsea equipment."

On Strathspey, a drilling campaign last year helped push current production to 15,000 b/d. A workover campaign is also imminent here.

In the recent UK North Sea licensing round, CNR applied for further acreage close to Ninian. Any new discoveries successfully developed would further extend the life of Ninian.

Talisman branching out into Norway

The rapid emergence of a new order in the North Sea could be compared to the lifting of the Iron Curtain. "There is a sense that we're on the cusp of change," says Paul Blakeley, Talisman Energy UK vice president, "with BP leading the way in asset disposals. Most of the recent deals in the UKCS were the result of BP rationalizing their portfolio, and they have shown over time that this is fundamental to their business management style. Shell in contrast has been much slower, with only one operated asset on the market (Kittiwake). Their other potential disposals are largely rationalization of the interest that came with their acquisition of Enterprise Oil."

Since Talisman entered the UK North Sea in 1994 through the acquisition of Bow Valley, it has taken mature field turnarounds into a fine art. Its first major signing was BP's controlling interest in the Beatrice, Buchan, and Clyde infrastructure; its latest coup is gaining a foothold in Norway, through buying BP's interests in and around the Gyda field. It has also built one new production complex from scratch, in the Moray Firthm around BP's Ross discovery.

Talisman missed out on another opportunity earlier this year when BP traded Forties to Apache. Despite that disappointment, Blakeley welcomes the influx of North American independents.

"The UK North Sea needs a strong supply chain for us all to survive. Talisman can't support this all on its own. We value more involvement from companies our size, and also some of the smaller ones, like Venture Petroleum. But we also need more opportunities."

"At the same time," Blakeley says, "we can't take risks with those we're letting in: you can't just allow anyone with investment capital to operate in the North Sea. This is a serious business that involves preserving platform integrity. We cannot afford any questions there."

Gyda prospects

In Norway, Talisman also broke new ground as the first newcomer to take charge of existing production facilities. The $90-million package includes:

• 61% of production license 019B, which includes Gyda and its platform
• 18 MMboe of net proven reserves
• 61% of the field's 43-km, 12-in. gas export pipeline to Ekofisk
• 45% of production license 019C within block 2/1, containing the Kark prospect. Gyda's oil is exported to Teesside, UK via a tie-in to the Ula pipeline and Ekofisk.

According to Blakeley, the Gyda reservoir "looks just like Clyde when we bought that field from BP, with similar subsurface geology. We're looking to replicate what we've achieved on Clyde, where we've drilled continually for new reserves over the past seven years. From the newly acquired 3D seismic, we've identified a number of drillable targets both around Gyda and in adjacent acreage."

Talisman will open an office in Stavanger, he adds. "We'll make use of our existing North Sea expertise, and we'll also bid for services – probably Norwegian – to support our capital program. But we have an excellent tight-knit crew already in place on the platform."

Blakeley says that the case against Norway is its current fiscal regime, which isn't as good as it should be if they want to encourage activity by independents.

The UK isn't that much better. "Last year's 10% corporation tax supplement was a real shock. But since then, there's been closer cooperation between our industry and the UK Treasury in gaining understanding of the issues surrounding North Sea activity. I'm optimistic the UK government is responsive to our concerns. They too want to see an increase in capital investment. This showed in the tax changes they introduced in this year's budget."

Drilling commitment

Talisman's board allocates £250 million annually to UK operations. "Last year," Blakeley points out, "we drilled seven exploration and appraisal wells on the UKCS, more than any other company. We're planning the same number this year. We have drill crews on Tartan, Claymore, and Clyde. Probably we'll continue at a level of two to three through to the end of the year."

Last October, Talisman recorded possibly its largest UK sector discovery on the J-1 prospect, 10-km northeast of Buchan. The well encountered a 164-ft gross oil column in good quality upper Jurassic sandstones, and also flowed gas.

"Currently, we're working on a development option, and we also planned to drill the nearby J-5 prospect this month. The outcome of that well could influence the shape of the development. It could be standalone or subsea. In this region, we also have to drill another well on North Leven."

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In the Moray Firth, Blake Flank, a BG oilfield development, should shortly be producing through the Ross field FPSO.

"The platform currently handles 45,000 b/d and this new field will add 17-18,000 b/d, pushing the platform close to its 60,000 b/d capacity. After that, we have plans for a workover and another well on Ross to squeeze out further oil."

Platform modification programs include produced water capacity and reinjection upgrades on Piper B, and relocation of Claymore's process control room for safety reasons.

"We're also installing three Centrilift dual electrical submersible pumps on Claymore for gas lift purposes. We phase our brownfield modifications carefully. You learn from experience with mature assets."

None of Talisman's platforms faces imminent decommissioning. This is partly due to its consistent track record in field life extension. "But we also tend to buy assets not that far down the production road," Blakeley points out.

DNO aiming for second major field revival

DNO's work on Heather in the UK Northern North Sea is a model for aspiring operators. What previous operator Unocal saw as a liability has been turned into a productive asset, with a remaining service life estimated at 11 years. Under Unocal, the field and facilities faced abandonment by 1999.

Norwegian-owned DNO has had a presence on the UK shelf for many years in the form of minority field interests. These included 1% of Claymore, acquired in 1990, and 6.25% of Heather from the start of exploration in 1973. From the vantage point gained as a joint venture partner, DNO recognized that over time, the major operating companies were becoming less inclined to commit funds to their ageing assets, preferring to invest in "virgin oil" projects elsewhere.

In 1996, the company reformulated its strategy and set out to become a North Sea operator, specializing in management of mature fields and the development of relatively small accumulations. During the same period, Unocal signaled its intent to exit the UKCS.

Following discussions with Unocal and the other Heather partners BG and Texaco, the UK's Department of Trade and Industry agreed to DNO taking over as operator of the field and blocks 2/4 and 2/5 in 1997.

"We recognized that the UK North Sea E&P industry was maturing, in line with other basins such as the Gulf of Mexico, and we felt there was a niche for us to develop as a low cost operator of mature fields," says Brian Fraser, manager, Business Planning and Support.

DNO thereby became the first Norwegian-owned operator on the UK shelf (and no others have followed since).

"We were coming in and stepping into the shoes of a major operator," says DNO Britain's Chief Executive Stewart Watson, "looking after a first-generation platform that entailed safety case management, compliance with regulations, and keeping a highly competent workforce motivated was all part of the challenge. We considered all options but were emphatic that 'DNO would never be a virtual reality operator'. We believed we had a duty to manage and control, and to do that we had to have core competency across the entire spectrum of exploration and production."

Currently, the company employs a staff of around 130 in its Aberdeen-based UK operation, and a further 135 core contractor personnel.

Human Resources Team Leader Nicola Gille-spie adds: "Recruits to DNO are also buying into a new philosophy, nurturing mature fields and giving them a future. A lot of people are attracted by that and enjoy playing this part."

As for the range of in-house skills, Fraser says: "Our philosophy is to maintain internal core competence in reservoir description, well engineering, drilling, production, operations, maintenance, and project management, with 'informed buyers' managing specialist and support services provided by contractor organizations. On occasions, we implement incentivized contracting arrangements, but our preferred policy is to procure best value for money services without having to draw up overly complex legal documents."

In its six years in charge at Heather, DNO has grown from a company with net production of around 800 b/d to a level close to 30,000 b/d. Around 30% of this is derived from two operated fields in the UK (Heather and the recently acquired Thistle); 40% from two fields onshore Yemen, one of which DNO operates; and 30% from Norway, where DNO now operates four licenses and participates in a further six.

Salvage operation

Heather was discovered in 1973 and brought onstream five years later through a conventional steel platform. Oil production peaked at 38,500 b/d, but a steady decline set in from 1982. The Heather structure proved complex and difficult to evaluate, with the main reservoir tilted to the northwest and bounded by faults to the south east.

Additional reserves were brought into the development over time from the Heather Fairway extension and the North West Heather structure. Two other discoveries, West Heather and South West Heather, were considered non-commercial under the Unocal-led regime.

In 1997, the company's net production had dwindled to 800 b/d, but DNO was convinced it could succeed where Unocal had failed through applying latter-day advances in 3D seismic acquisition and imaging, well construction and completion technologies and subsea tiebacks.

"However, you should always move cautiously with an ageing asset," Watson insists. "You must be careful not to attempt the impossible, i.e., turning an old lady into a four-minute miler."

At Heather, production decline was gradually arrested through a combination of well intervention (scale control/removal, re-perforation and gas lift optimization), and in-fill drilling.

"The campaign during 2000-2001 brought mixed results," says Fraser. "Well H-59 was suspended due to problems encountered running the liner. But the others drilled in that period, wells H-60, H-61 and H-62, have produced nearly 1.5 MMbbl. The major lessons we learned were 'to expect the unexpected' and to treat the possibility of differential pressures occurring in the reservoir with great respect. Effectively, this meant that any complex steering of the well was restricted in the later wells to above the reservoir section."

DNO resumed appraisal drilling on West Heather in fall 2001, with a successful oil discovery (well 2/5-18) in Brent/Emerald Jurassic sands 7 km west of the Heather platform. It concluded that developing West Heather area and adjacent North Terrace accumulations could add a further 40 MMbbl recoverable to the Heather area reserves. Last August, to fund two more wells on West Heather, it farmed out 45% of its non-Heather interests in its two blocks to Global Santa Fe (GSF) subsidiary Challenger Minerals Inc (CMI) and to Palace Exploration, a private company based in Tulsa and New York.

Last year, DNO and Global Santa Fe (GSF) introduced modern turnkey drilling contracting arrangements to the UKCS as part of the farm-in terms. These were modeled on a fixed cost contract concept widely used in the Gulf of Mexico, but which had not previously been used in the UK due to the incompatibility of the legal arrangements between the two jurisdictions.

"Basically, the commercial arrangement is that the contractor does not get paid unless he delivers on certain criteria that are jointly agreed," Watson explains. "For GSF, drilling of wells is a dynamic, iterative process, but the operator must also react at times to certain information, e.g., by changing the direction of the well, or gathering different data."

Watson said DNO drew up a menu list and agreed on not only the cost of drilling a well, but also of certain added extras (such as coring, logging, and deepening of the well).

"We also agreed on quite complex arrangements for the transfer of liability," he says "that would be borne by the contractor."

The first well drilled by the partners, 2/5-19y, appraised the northern part of West Heather, using GSF's Arctic IV semisubmersible. A subsequent test suggested the well could produce at over 10,000 b/d, and that 5 MMbbl more could be recovered above the earlier estimate. It was then suspended as a future producer.

The next well in this area (2/5-20) was brought forward to October 2002, and encountered a 180-ft hydrocarbon column at a crestal location in the southern part of West Heather. This well was also suspended as a potential producer.

"The West Heather appraisal well program exceeded our expectation," says Fraser, "and as a result, proven reserves have tripled – relative to the position in 2001 – to 26 MMbbl."

In February this year, DNO received UK government approval to determine West Heather and North Terrace as a single field, renamed Broom. A condition precedent of the Heather area farm-in arrangement with CMI and Palace had been that both should agree to the West Heather development plan and budget before being brought into the 2/4 and 2/5 licenses. The three Broom coventurers also agreed to pay a tariff for use of the Heather processing and pipeline facilities. CMI and Palace have no direct involvement in Heather, nor have they any decommissioning liability except where this applies to the West Heather equipment.

Since 1977, DNO has invested nearly £50 million in the Greater Heather area. Developing Broom will cost an estimated £90 million, equivalent to £2.50/bbl. "One positive implication of the determination of Broom as a separate field is that profits arising from its development will not be subject to Petroleum Revenue Tax (PRT) which is levied at 50% on UK oil fields," Fraser says. "This, together with the government's recently announced royalty abolition, means that only corporation tax and the supplementary charge (SC) at a combined rate of 40% will apply. However, the imposition of the SC and the inequitable charging of PRT to old fields such as Heather and Thistle remains a barrier to investment."

The Heather platform has a normal complement onboard of 50-60 people. Current capacities are:

• Oil export, 30,000 b/d
• Water production, 30,000 b/d
• Water injection, 75,000 b/d

Following modifications to accommodate Broom (including new pig launch/reception and hydrocylone equipment), water production capacity will have increased to 50,000 b/d.

The Broom development will entail in its first phase completing three already drilled producer wells, and the drilling and completion of two water injectors. All wells will be tied back to the Heather platform via a 7-km pipeline bundle from horizontal subsea trees, which will be controlled by an electro/hydraulic control system. The pipeline bundle will be connected to Heather using a flexible catenary riser system suspended from a cantilever structure on the platform north face. At peak, Broom will produce oil at 25,000 b/d.

Aker Kvaerner is manufacturing the horizontal trees with pods and flow bases. Halliburton is responsible for the cantilevered riser platform and modifications to the Heather topsides. Subsea 7 will provide and install the flexible catenary risers, the subsea production/injection manifold and the bundle, comprising two 8-in. production flowlines, one 8-in, water injection pipeline, a 6-in, gas lift line, and a 3-in. service line, and a multiplex/hydraulic controls umbilical. First oil from Broom is expected next summer.

DNO is now turning its attention to South West Heather as another possible subsea tieback to Heather. This accumulation is located 8 km south of West Heather and was discovered by the 2/5-10 well drilled in 1979, which tested oil in the Brent, Emerald, and Triassic reserves at a combined rate of 6,000 b/d.

"After 30 years of exploration and appraisal in the Heather area, we know that there is a productive hydrocarbon reservoir in the Triassic Group lying less than 1,000 ft below the Middle Jurassic Brent reservoir. The current long-term development concept is to appraise South West Heather and deepen an existing Heather field Brent production well to the Triassic when it waters out or fails. If this is successful, a further two wells will probably be drilled. Independent reserves auditors suggest the three Heather Triassic wells could produce at around 1,500 b/d and deliver some 10 MMbbl.

By the end of 2002, 127 MMbbl had been produced from total estimated reserves in the Heather area of 475 MMbbl, representing a 27% recovery factor. Timing of the eventual decommissioning operation will be at DNO's sole discretion, but this will depend on the performance of the Broom and Heather reservoirs, the cost of operating and maintaining the production facilities, and the prevailing oil price. Current cessation of production is assumed to be in 2015. No major remedial or new injection programs are anticipated in the run-up to this period.

BG/Texaco will pay 62.5% of the final decommissioning costs associated with Heather, and a similar percentage of annual decommissioning study work. DNO will be liable for the remaining 37.5%, plus 100% of any additional costs for facilities installed after 1999.

Thistle transfer

This January, DNO completed its second major asset transfer when it was confirmed as the new operator of the Thistle and Deveron fields in blocks 211/18a and 211/19a. The immediate impact of this transaction was to raise its net UK production to around 10,000 b/d and to increase its UK oil reserves by one-third to 80 MMbbl.

DNO participates in numerous network groups aimed at identifying and sharing best practices across the spectrum of E&P activities. It was during discussions with BP on production and maintenance operations in mature fields that both parties realized that transferring operatorship of Thistle and Deveron from BP to DNO might be to the benefit of all concerned.

According to Watson, who had worked on Thistle pre-DNO, "BP and Shell were asking us how we could manage our Heather platform at £20 million per year, while they were paying £35-40 million for similar installations. We were asking them about competency and training procedures and contracts management. A lot of business is being done this way in the North Sea at present, seeking out people to have conversations with, sharing best practices, and identifying 'win-win' opportunities."

Last year, a temporary transfer of operatorship in the fields to DNO was arranged with Thistle/ Deveron's incumbent partners BP and Conoco. This led to DNO acquiring a 99% interest in the fields and also various working interests in the pipeline and terminal infrastructure. As with Heather, these negotiations took 10 months from agreement in principle to final execution.

The Thistle platform, like Heather's, is 25 years old. Thistle is also one of the largest North Sea installations, with a combined topsides/jacket weight of 66,000 metric tons, compared with 38,000 tons for Heather's. At its peak, it could handle overall production capacity of 280,000 b/d. Currently, it processes five times the volume of water (150,000 b/d) as the Heather platform for a similar level of oil production (5,000 b/d). Thistle's field water-cut is 97% compared with 82% for Heather.

Thistle was discovered in 1973 and started producing in 1978 from Mid-Jurassic Brent sandstones. Oil is exported through a 16-in. pipeline running 12.5 km south to Shell's Dunlin platform, and from there to the Sullom Voe terminal via the Cormorant A platform. Deveron, a small satellite field, was developed in 1984 through three deviated producer wells drilled from the Thistle platform. Only 300,000 bbl remained from the original 17 MMbbl recoverable when DNO moved in.

"Our first priority on taking operatorship of the two fields in January was to settle the platform workforce and turn their minds away from redundancy toward field life extension under DNO," says Fraser. "One of our first challenges was to put in place arrangements for reducing annual operating costs by around 25% without negatively impacting the long-term viability of the production infrastructure. Following the Heather model, plans are being drawn up to acquire new 3D seismic data with a view to high-grading possible in-fill drilling locations."

Reactivation of the Thistle drilling package could prove to be a major undertaking, Fraser says, as the rig has not been used for drilling for over a decade. As an alternative, DNO is considering mobilizing a hydraulic workover unit to perform a number of jobs designed to re-instate suspended wells and boost production.

Thistle and Deveron have produced 420 MMbbl from in-place reserves of 900 MMbbl, representing a 46% recovery efficiency. Based on BP's plan to cease production in 2003, no additional reserves would have been produced. DNO plans to extract 2 MMbbl this year, and sees potential for recovering a further 20 MMbbl.

DNO has no participation in the Don and Don West fields, currently undergoing a review by BP, but it has indicated that should the Don group decide to redevelop Don (via a subsea template tied back to Thistle), it would be happy to enter into third party tariff discussions.

DNO is operating Thistle using a combination of its own employees (many employed formerly by BP) and core contractor personnel (100 altogether).

"It is early days for us in getting to know the asset," says Fraser. "One initiative has been to embark on a maintenance strategy review to achieve alignment of the maintenance routines with the requirement of Safety Case Performance Standards, and to reduce the overall maintenance cost. It is not our intention at this stage to bring partners into Thistle."

BP submitted a Cessation of Production document for Thistle to the DTI in 2002. The arrangements with BP/Conoco are based on extension of the field's life through to at least end-2005, but DNO can re-transfer operatorship to BP at any time, subject to certain conditions being fulfilled. Wood Mackenzie has estimated the decommissioning cost for Thistle at £120 million, although this could escalate, depending on whether the Ospar derogation not to remove platform 'footings' is withdrawn, and whether the drill cuttings pile under the platform has to be removed.

Fraser concludes: "DNO would welcome the opportunity to manage other first-generation North Sea platforms under similar arrangements to those agreed for Thistle. However, any transaction should be conducted several years ahead of the planned Cessation of Production, not at the point of ceasing production, as was the case with Thistle."

Late field life extension is a delicate balancing act, Watson points out. "If your company has a 10% rate of return and a final £100 million decommissioning cost, you can afford to lose £10 million annually over the course of many years in order to avoid spending that money. So it becomes tremendously important to run the asset bumping along the bottom as long as you can."

The UK government in turn is delighted, he says, because every barrel counts toward meeting its strategic objective of maximizing economic recovery of indigenous hydrocarbons. An added dimension is the availability of carry back tax relief for decommissioning expenditure based on previously paid petroleum revenue and corporation tax.

Since its formation from scratch in 1997, Venture Production has worked hard to attain its current status. The Aberdeen-based company operates three develop-ment and production hubs in the central and southern North Sea. Three incremental positions in these were secured this year, following protracted negotiations, without the help of a sugar daddy in Houston or Calgary.

According to Chief Executive Bruce Dingwall, "Our strategy is organic growth through acquisition, finding assets to release new barrels through the drill-bit. We look at paying a fair price, but we can't pay a lot for the upside that we have to invest in through new wells."

Venture's method typically involves gaining a toehold in a production license, then buying out the partners one by one until it has reached a position of dominance. This can be a tortuous process.

"Putting together our southern gas basin position involved seven commercial transactions over three years, prior to making any investment," he points out. "It was a different game in the '60s. Then you applied for virgin licenses and proceeded to drill the obvious huge anticlines."

One of the Audrey field platforms, where Venture Production recently assumed operational control from ConocoPhillips.

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More opportunities are coming around, following the majors' stampede to sell their older properties. But would-be buyers must also earn the majors' trust, through proven competence.

"This is something we have done over time with Total, Agip, ConocoPhillips, and now Shell and ExxonMobil. When they sit down with you to negotiate an asset sale and transfer, they need to know that you will be a sensible negotiator, complete the deal, and be there with the money at the end of the day."

Venture operates the A-field platforms (subject to government approval) and associated fields in the southern sector; the Trees blocks subsea developments through Marathon's Brae A platform; the Kittiwake facilities and surrounding acreage (subject to government approval); and the undeveloped Chestnut field.

"We've bought our assets, but we've also invested very heavily," Dingwall says. "Since last summer in the North Sea (not including Kitti-wake), and on a rolling basis to the end of 2004, we will spend over £300 million net on drilling new wells and on new infrastructure. Currently, we have on contract the Stena Dee and the Noble Ronald Hoope for two separate drilling campaigns. So regardless of size, we must be one of the North Sea's busiest operators."

This shows that small companies can punch well above their weight, Dingwall says. "We're not better at what we do on our fields than the larger oil companies, but there's a time and a place where it's more appropriate for someone else to operate and bring that new focus and energy that mature assets demand. The barrels we're chasing are harder to win than the earlier ones."

Venture employs 43 people at its head office in Aberdeen, "although we will raise that to around 55 as we expand our investment in our three hubs," he adds. "We do all our subsurface, drilling, subsea, and well design work in-house. We also have a full-time well performance manager. We're trying to change the way we behave by being very proactive, mapping each of our wells to see how we can optimize performance."

Platform operations are devolved to specialists. Petrofac was recently contracted to manage Kittiwake.

Phasing Sycamore

Venture's first UK North Sea purchase, in April 2000, was Lasmo's operating interest in the Trees block 16/12a, and 25% of the adjoining blocks 16/13b and c. Two fields, Birch and Larch, had already been developed through Brae A, coming onstream respectively in 1995 and 1998. Production problems on Larch caused by an unsatisfactory horizontal water injector led Lasmo to shut in the field. Venture, on taking over operatorship, re-drilled the injector to a new subsurface location and re-established first water injection and then production.

Following remedial work, Larch was producing 14,000 b/d by the end of 2000, and has performed to order ever since. But Birch also had to be shut in last year due to problems with a downhole safety valve. The field remains out of action, although Venture is being pragmatic.

"We have simply deferred Birch's production until pressures in the infrastructure are normalized," Dingwall explained.

The planned deferred output has been offset through the new volumes from the phased Sycamore development. This was approved by the Department of Trade and Industry in May 2002 and brought onstream this March at 27,000 b/d.

Sycamore comprises what was thought to be three separate accumulations – Elm, Pine and North Pine. A new geological model, derived following work on the Larch field rehabilitation, showed that this was one single producing trend extending into the southern part of block 16/12a. Venture is 64.51% operator, with Marubeni its sole partner. The three-phase, £90 million project is targeting 20MM bbl of oil and 14 bcf of gas.

Phase 1 entailed re-entering two suspended exploration wells in the center of the field and completing them as producers. A third producer is being drilled in the northern area (Phase 2), and two supporting water injectors will also be drilled later this year following a period of production (Phase 3). After a further year's production history, the field's southern area may also be developed, through re-completion of two existing suspended discovery wells and the deployment of additional flowlines.

All the current wells are being tied in to a new manifold, which is connected to the Birch/Larch manifold (and onward pipeline system to Brae A) via a 4.5 km flowline bundle. Agip's Tiffany platform was also considered as a host, being only 1 km to the south.

Chestnut revived

Amerada Hess is another of those companies looking to divest 'marginal' North Sea interests. Chestnut, a small oil and gas field in block 22/2a, fell into that category. Amerada acquired operatorship in 2001, 15 years after the original discovery, through a farm-in arrangement. This led to drilling of a horizontal production well and an extended production test the same year, using the Brovig vessel Crystal Ocean.

The well produced at rates of up to 15,000 b/d for four months, before being suspended – just like the development.

In March, Venture, which was already a partner, agreed to buy Amerada's interest, raising its share in the field to 69.875%. Venture and its remaining partners Premier, Bow Valley and Oranje Nassau are now looking to take the project forward as a subsea tieback. At this point, the Andrew and Alba platforms are the nearest and most viable options. Reserves for Chestnut are currently estimated at just over 16 MMboe.

Kittiwake life extension

The agreement for the Greater Kittiwake Area fields was signed by Venture and its equal co-venturer Dana Petroleum in late-April, and covers acreage on blocks 21/12, 21/13a, 21/14a, 21/18a, and 21/19 in the Central North Sea. Currently in production are Kittiwake itself and its high-pressure, high-temperature subsea satellite, Mallard, in 85 m of water. The platform, in service since 1990, is a small, late-generation fixed steel structure, in good condition and with a fully functioning drilling set.

"Normally, on a mature asset, we'd be obliged to bring in a mobile drilling unit," Dingwall points out. Both Kittiwake and Mallard produce from the same Upper Jurassic Fulmar sandstone formation. Oil production is loaded offshore to shuttle tankers via a single-point mooring system.

There are also three undeveloped discoveries within reach of the platform named Gadwall, Grouse, and Goosander, and numerous undrilled prospects led by Kaynine and Lightning (both close to Goosander). Subject to UK government approval, Venture and Dana will equalize their equity holdings across the entire Greater Kittiwake area, but Venture will operate all the assets, also managing sub-surface studies in-house. Petrofac has been engaged to manage platform operations. Remaining proven and probable reserves are estimated at 29 MMbbl.

The work program will start with a new 3D seismic survey late this year.

"This will be the first new seismic over the area for over 12 years," Dingwall says, "and acquisition and processing has moved on a long way since. We're not expecting to open a Pandora's box, but there will certainly be a very different picture under a new 3D data set. We do know that there is a stratigraphic trapping element to Kittiwake. This new data will hopefully allow us to better identify the field limits and locate bypassed or remaining attic oil reserves that are not being drained by the current well stock."

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Once the results have been analyzed, a development plan will be prepared for further infield drilling as soon as possible on Kittiwake, and further subsea tiebacks to the platform.

Goosander, a 10-MMbbl accumulation, lies 10 km distant. Gadwall is a suspended accumulation situated 50 m from a tee in the Mallard oil pipeline to Kittiwake.

Originally, the producing fields were due to run down by 2005, but the new partners aim to extend operations through 2012 at least. This deal also represents the first sale by Shell of a North Sea platform.

"That's a huge cultural change for them," Dingwall points out, although Shell did have plans to sell these facilities three years ago.

Shell has also agreed to retain 50% of the current abandonment liability for Kittiwake and Mallard, in addition to managing the decommissioning work when that happens.

"This being one of the last fixed platforms to go in, it was also designed to be lifted out," Dingwall says. "ExxonMobil has not agreed to the same terms as Shell, although it is paying us a discounted value for its share of the abandonment liability. When we've finished with the platform, we hand back the keys to Shell. So we don't have to draw up our own abandonment team."

A-Fields gas potential

Venture's latest agreement, in May, relates to Audrey, in southern North Sea block 48/15a. Here it has acquired Cono-coPhillips' 30.78 % operating interest, bringing its own share in the field and its facilities to 60.68%. The only other partner is Aberdeen-based Roots Gas, which came in in January 2001.

Audrey has been developed in two phases. The first involved installation of a steel unmanned platform and a single subsea satellite well in 1988. Phase 2, based on a wellhead platform, was completed in 1990.

The reservoir extends across blocks 48/15a and 49/11a, and had total recoverable reserves of 670 bcf (down to 40 bcf this January, according to Wood Mackenzie). The field's gas is exported to a central gathering station on ConocoPhillips' Valiant North platform via a 16-km pipeline, passing from there through the Loggs trunkline system to the Theddlethorpe terminal in Lincolnshire.

Venture first moved into this region in Dec-ember 2000, taking Phillips' equity in blocks 48/10a, 49/11a, and 49/6a. In addition to Audrey, these contained Ann field, in production since 1993 via two horizontal wells tied back to the Loggs riser platform and Alison, a trilateral subsea well developed with ConocoPhillips' Kx field.

Last October, Venture also renegotiated a life of field gas sales contract for Ann and Alison, allowing it to increase production from both fields, in which it now holds an 85% interest. Other commercial prospects in these blocks are the ConocoPhillips-operated Saturn development, the Annabel accumulation (operated by Agip in 48/10a), and undrilled prospects including Adele, Agatha, Annie, and Ava.

In May 2002, negotiations with Agip would lead to Venture securing operatorship of 48/10a, in exchange for drilling an appraisal/development well on Annabel in 2003. This operation recently got under way, using the jackup Noble Ronald Hoope. "Initially, the rig performed a successful workover on Ann. A subsurface safety valve needed fixing. The well on Annabel could add 100 bcf net of new reserves in the area."

Block 48/10b, operated by ConocoPhillips, has a proven gas accumulation that is known to be in communication with Annabel in 48/10a. This has been the subject of unitization negotiations and development planning between the two sets of partners, for a project known as Saturn (expected onstream 2004-05).

ConocoPhillips is reportedly looking to put in a minimum facilities platform and a 38-km gas pipeline to Loggs on its side, ultimately with compression, with three production wells on its Atlas and Hyperion fields. Venture may decide to bring Annabel into this project.

Last year, a comprehensive subsurface review was undertaken of Audrey and surrounding acreage. "We have a team looking at infill potential on the western flank, and what compression might do for us. The entire A-fields area, including Saturn, contains potentially 500 bcf, making it one of the UK's largest in stranded volumes."

On completion of the Annabel well, the jackup will drill two more on Annie and Agatha (Venture 85% in both cases). "These are untested prospects which we plan to tie back to Alison to the east." There are various other prospects in the area, all requiring low-cost exploration/development wells, which Venture may tie back and bring onstream within the next few years.

"Speaking in my other role, as chairman of the UK Offshore Operators Association, I still think a lot more diversity is needed in the North Sea. Of the 24-25 operators on the UK shelf, eight are still producing 80% of the total output, and that's not healthy."

Dingwall says there's too big a gap between companies its size and the middle rung of Kerr-McGee and Talisman.

"As far as some of the government's new initiatives are concerned, if just one well gets drilled through a Promote license, that to me is a success. Also, this year's tax changes are a step in the right direction, which will benefit us at Venture. But a small change on PRT should not be overblown. Other challenges lie around recruiting a new generation of people to our industry."