Partnering/outsourcing arrangements speed development
Jeremy Beckman
Editor, Europe
Britain’s 23rd licensing round, which closed in June, attracted bids for 279 offshore blocks, the largest response since the early days of exploration in 1972. Energy Minister Malcolm Wicks added that of the 114 companies that submitted applications, 28 were new to the North Sea.
The UK Offshore Operators Association said recently that newcomers were now generating of the UK’s annual oil and gas production. That percentage will likely creep up further, with several more companies progressing new field developments. Among the current crop up are:
•ATP Oil & Gas, 100% owner of the Tors fields in the southern gas basin. Here the Garrow and Kilmar accumulations are under development, with separate production platforms and a total of five wells
• Newfield Exploration, planning a fixed platform for Grove, a 1971 gas discovery in the same sector
• Eclipse Energy, which has just applied to the UK government to install the world’s first hybrid offshore gas/wind energy plant in the East Irish Sea. This would involve harnessing the Ormonde North and South fields 10-km west of Barrow-in-Furness to fuel gas turbines for electricity generation
• Caledonia, tying gas from the Hunter field, again in the southern sector, back to ConocoPhillips’ Murdoch platform via a subsea template.
Another group is proving up new reserves via the drillbit. Among the more active is Dana Petroleum, which announced plans recently to explore the mid-size Barbara, Clachnaben and Fiacre prospects this year using the semisubmersibleBredford Dolphin. Granby Oil and Gas is a newer company, led largely by former Enterprise Oil executives. It has a multi-well program lined up this year in the central North Sea, with exploration already under way on Marquis, a promising-looking structure west of the Forties field.
According to a recent report by the UK Offshore Operators Association, Britain is ranked fourth in the world gas production league. But rapid decline is setting in, leading to construction of new import facilities off and onshore to handle supplies from Norway, The Netherlands, and Algeria.
Rising demand has in turn pushed up prices, triggering competition throughout the UK shelf for stranded or mature gas. One of the early crystal ball-gazers anticipating this scenario was Tullow Oil, which entered the southern North Sea in 2000 through buying BP/Arco’s Thames Area assets.
Tullow has since built up production and exploration strongholds farther west, and more recently to the north, off the Yorkshire/Lincolnshire coast. Pre-Thames. Tullow was a relatively small, Dublin-based operation focused on low-key projects in West Africa and the Indian sub-continent.
“We were keen to operate the Thames Area interests from the start,” says Chief Operating Officer Paul McDade, “but we were blocked by partner ExxonMobil.”
In fact, Tullow did end up operating one associated small field, Orwell, which exports its gas to the Thames AR platform for processing and compression. Tullow’s work on Orwell allowed management to build a reputation with the Department of Trade & Industry, in the process gaining familiarity with the UK’s offshore regulatory regime.
In October 2003, the company broadened its base in this region through purchasing ConocoPhillips’ equity in the Hewett Area fields. The transaction propelled Tullow to operatorship of six platforms, subsea facilities, associated export pipelines and, most importantly, the processing terminal at Bacton on the Norfolk coast.
The change in status went through, despite the fact that ExxonMobil was a minority partner.
“By then, they were very supportive, having worked with us for the past 18 months on Thames,” McDade says. “The key for us was getting ourselves known as a serious company, not a speculator building a portfolio only to sell.”
Hewett had become non-core to ConocoPhillips, and from a forward reserves/production point of view, it was not such a big deal. Currently the Hewett area fields are producing 50MMcf/d gross, down from 70MMcf/d at the time of the transaction.
“But we were looking to the future, with control of the Bacton terminal being key to the offshore area as a whole,” McDade says. “It was also a strategic acquisition, which was intended to assist our expansion in the area.”
However, there were profits to be made, even from low-end production. Tullow’s first act was to delegate day-to-day operation of the platforms and associated facilities to Petrofac Facilities Management.
“Petrofac were and still are the only contractor in the North Sea with duty holder capability. I spoke with them, having liked what they had achieved on other facilities such as Talisman’s Galley. But if you agree to a hand-over, it should be a package of responsibilities. So making them responsible also for offshore safety through becoming duty holder made sense.”
Cost cuts and efficiency improvements have provided the main challenge to date. “When we acquired these assets, there were a total of 240 people involved on and offshore,” McDade says. “Now we’re running a manpower level of around 130. We actually terminated all existing contracts on assuming control, the aim being to introduce a feeling of starting afresh, in a different working environment. Nothing we have done since has been particularly new, although we have implemented offshore rotational shift systems onshore at Bacton. The result is that technical staff is now available at all times, not just from 9-5.
“We have achieved a lot of savings on maintenance, without compromising safety. The previous regime operated gold-plated procedures, and had stuck to similar routines over the past 20 years. And we figured there was no need to maintain capacity at Bacton for 100 MMcf/d when the throughput is significantly less. The equipment itself was in surprisingly good condition, considering that much of it had started up in the 1960s.” Tullow has also optimized use of some equipment. For instance, new fuel-efficient compressors at Bacton, designed to handle gas from ExxonMobil’s LAPS fields, are now also employed for supplies from Hewett.
Under ConocoPhillips, the Hewett fields were drifting toward cessation by 2006. With luck, Tullow might extend production through 2010-11.
“We keep looking for solutions,” he says. “There are a few things we can do subsurface, with some potential in Zechstein plays, but this is a complex reservoir.”
Blythe, 100% owned by Tullow, is a 40-bcf prospect in blocks 48/22a and 48/23b within tieback reach of the Hewett infrastructure, which could also be developed jointly with Century’s Dudgeon field.
“If we could find something that makes money even at 20 bcf, we’d consider it,” McDade adds. “That wouldn’t have been the case in the past.”
Thinking longer term, Tullow is looking at an alternative solution. “If you take France and Germany, their gas storage capacity is six times what we have in the UK. We believe Hewett’s reservoirs are suitable for storage, and the location - 20 km offshore Bacton - would be convenient.”
Horne/Wren in business
This June, Tullow brought onstream the Horne/Wren fields, its first operated development in the UK sector. It gained a small stake in these fields as part of the Thames Area package sold by BP in 2001. Numerous asset swaps later, it was in position to launch the project with its new partner, Centrica.
Tullow brought Horn/Wren onstream in June.
Following UK government sanction last October, development got under way based on a monotower platform located between Horne and Wren, built by local fabricator SLP. Production from single horizontal wells on both fields heads to the Thames AR platform via a 20-km, 10-in. export flowline connected to a 10-in. riser.
“We had considered an alternative subsea development through ExxonMobil’s redundant Welland platform,” McDade explains. “But in the end we opted for a normally unmanned installation with the absolute minimum of facilities, possibly the smallest on the UK shelf. This platform does not have a helideck, and our aim is to visit it once a year maximum for minimal maintenance.”
Onboard equipment includes a hydraulic power pack, with power generated by an Ormat power generator fuelled by gas from the fields’ wellstream. Two wind turbines and batteries provide a back-up power source.
Horne/Wren is operating now at a combined plateau rate of 90 MMcf/d. The commitment to this project also persuaded ExxonMobil to produce its Arthur field via the Thames offshore infrastructure to Bacton, lifting the pipeline system’s throughput to over 250 MMcf/d (the capacity is 400 MMcf/d).
“If you can maximize capacity, it makes it that much more attractive to undertake infill drilling,” McDade points out, “as extra volumes of gas lower the infrastructure’s unit costs. In the Thames Area, there are extensions to existing fields in small blocks, such as Thurne, which we are operating.”
Tullow has also completed subsurface studies on Fizzy, a large gas discovery with associated C02, located 12-km south of Orwell in block 50/26b. “We’re looking to separate the CO2 offshore, maximizing the use of our existing infrastructure.”
Schooner/Ketch transfer
North of Thames, close to the Caister Murdoch System (CMS) infrastructure, Tullow has been amassing a spread of operated and non-operated interests. The BP/Arco package in 2000 included stakes in the producing Murdoch and Boulton fields, and led to involvement in ConocoPhillips’ CMS III five-field development, where combined production is over 150 MMcf/d.
Tullow also has stakes in two Carboniferous finds operated by Gaz de France Britain. Monroe is currently under development through the CMS III network, while the recent Opal discovery looks another likely candidate for export via the CMS III infrastructure.
Tullow’s most ambitious step forward in production terms came last December, when it agreed to pay Shell and ExxonMobil £200-million for their joint interests in the Schooner and Ketch fields in blocks 44/26a and 49/28b. Both have been in production via dedicated platforms since 1996 and 1999 respectively.
Estimated gas in place is around 1.5 tcf combined, of which less than a quarter has so far been produced. This May Tullow announced that it was transferring management of the platforms to Petrofac: the gas is transported to a process terminal in Theddlethorpe, Lincolnshire via the CMS trunkline system.
Tullow is looking to raise recovery ultimately to 50%, initially through a combination of sidetracks and workovers on existing wells, and exploration of previously undrained reservoir compartments. The jackupEnsco 101 is due to handle this work under a long-term contract, starting in October. The acreage includes numerous exploration prospects, headed by the Schooner south-east extension.
Other parties were interested in these assets. “We weren’t the highest bidder,” McDade says, “but ExxonMobil and Shell knew we had the operating capability to take these platforms off them. Shell had only pursued a first-phase development in both cases. Our feeling was, to do both fields justice entailed quite a bit of capital commitment, in terms of drilling and workovers, and they just weren’t enthused enough to move to phase 2.
This is a different situation from Hewett, McDade says, as the facilities are both unmanned.
“But before completing the deal in April, we saw first hand how Shell operated the assets. We weren’t happy with production uptime levels, but we had used the assessment period to plan what had to be done, in terms of maintenance and upgrades. So we’re more or less running the two fields on an even keel now. Operations are being managed out of Bacton, where we’ve added two normally unmanned installation teams.”
Combined production from the two fields has been brought up above 50 MMcf/d. Tullow also has minority interests in various untapped prospects nearby, led by Topaz, a probable tieback to Schooner.
Last September, the DTI awarded Tullow nine operated exploration blocks under the UK’s 22nd offshore licensing round. Seven of these blocks lie close to the CMS area interests.
According to McDade, his company is still on the look-out for further acquisitions, “particularly stranded assets that could be developed through our infrastructure. We hope the market becomes more fluid, as we’re also very keen to secure a third core area.”
Outsourcing drilling
Last month, Peak Well Management secured the jackupLabrador from Global SantaFe for four wells this fall in the southern North Sea. The client is Century Exploration UK, one of several newcomers to the UK shelf on Peak’s roster. Peak is also drilling wells this year in the central North Sea on behalf of Dana Petroleum and Century, and for Burlington in the Irish Sea.
According to the company’s managing director Bob Lyons, some of the smaller independents - with a staff of no more than five - clearly need to outsource exploration and appraisal drilling. Peak has built up an 80-strong team in-house, which this year is managing 30 wells worldwide, including and 20 in the UK sector.
Over the past few years, it has expanded from well design to its current project management service, which includes liaising with all relevant contractors, equipment and service providers, and government departments. Others offering a similar service in the Aberdeen area are ADTI, Helix and RDS.
Peak also helps start-up companies new to the UK shelf to develop competence to qualify for a full exploration license.
“The operator needs to provide the Department of Trade and Industry with assurance about its broad technical competence, and that it can deliver a drilling operation that addresses all necessary license and environmental permitting requirements,” says Lyons. “The UK’s Health & Safety Executive says a licensed operator need not be the actual operator of the well. But the company must understand its obligations under the 1996 Design Regulations Act, which includes accredited safety management, quality assurance and risk management systems. We can oblige on all counts, as our own systems are ISO 9001-accredited.”
Independents with forward drilling programs face the same problem as the majors in securing rigs in a tight market.
“Through our multi-well programs, license operators can feel more confident about achieving their drilling goals. We have proven that our programs can minimize the bureaucratic process. Also, logistical and manpower costs are shared. The collaborative approach brings increased purchasing power, which in turns strengthens security of supply. The knock-on effect is more favorable rig rates, better terms and conditions and improved flexibility.”
Sharing start-up and demobilization costs also works to the participants’ advantage, he says, and the performance of a rig engaged in a consistent, continuing program is further enhanced.
Two years ago, says Lyons, there were 15 rigs stacked in Scotland’s Cromarty Firth alone. “The general atmosphere was one of doom and gloom. But I felt even then that with the UK’s new promote license initiative, and the emergence of new entrants, the North Sea was in a period of transition.”
Very short-lived, judging by rig rates over the past year. Peak secured a semisubmersible last year for appraisal drilling on a central North Sea field at a dayrate of $53,000. Recently, it was working elsewhere in the sector at $160,000/day.
Other problems potentially constraining exploration in the UK North Sea are the limited number of skilled service providers, following the slim-down during the last downturn, and a shortage of experienced offshore personnel.
“The offshore industry is operating at close to 100% utilization,” Lyons says, “creating challenges that didn’t exist before. Equipment is also getting harder to come by, with worldwide steel shortages impacting tubular availability in particular.”
Venture forms subsea partnership
Venture Production is a veteran in the UK sector, compared with most other North Sea independents. Since the late 1990s, the company has been steadily revamping production interests unwanted or neglected by the majors. This process started with the Trees fields in the northern North Sea, which Venture has developed in phases as tiebacks to the Brae platform.
Three years ago, following a streamlining program by the newly merged ConocoPhillips, Venture gained control of the A-fields production complex in the southern gas basin. A year later, in partnership with Dana Petroleum, it secured operatorship of the Kittiwake platform and associated prospects from previous owners Shell and ExxonMobil. More recently, it has partnered ConocoPhillips in the Saturn development, adjacent to the A-fields.
This May, Venture announced a further package of acquisitions from Amerada Hess, all in the Central North Sea. These included interests in seven small, undeveloped finds and various other prospects in surrounding acreage. Venture aims to bring many of these fields onstream by 2009 through subsea facilities, adding a potential 30,000 boe/d to its net production in the UKCS, which currently hovers at around 45,000 boe/d. That forecast increase does not include output from Chestnut, which the company also aims to produce through a new concept FPSO, the Sevan SSP 300.
Competition has rarely been tighter in the North Sea for rigs or vessel construction spreads. But the company has solved one potential bottleneck over the next two years by forming a partnership agreement with Subsea 7, under which the contractor has agreed to manage all Venture’s subsea engineering, construction, inspection, maintenance and repair activities.
The $150-million-plus contract goes beyond the traditional subsea contracting scope, pitching Subsea 7 at the front end in terms of concept development, project cost evaluation, logistics, topsides interface and supply chain management. Where possible, the company will make available all pipelay, module installation and ROV vessels from its North Sea fleet to support Venture’s operations throughout the UK sector.
Subsea 7’s first project for Venture was the manufacture and installation of the flowline bundle for Sycamore (one of the Trees fields). The two have also worked together on the current Annabel - Audrey (A-fields) tieback.
“It was Venture’s idea to form this partnership,” says Subsea 7 (UK) Strategic Account Manager Martin Sisley. “They first approached us in February: they were preparing to implement six development projects this year, and the fact that we could fit in all the work they had planned was a plus for them, as they could see the vessel market was already getting tight. We will be working on all their UK hub areas during the remainder of 2005.”
This is a contract, but with no set date for a conclusion, Sisley says. “However, we have imposed a 12-month termination period, which will makes it difficult for either party to pull out, and the duration of the contract is determined by continuing performance. Venture have already offered us their upcoming subsea program, in the form of tiebacks, step-outs, installation of subsea hardware, and bundles. They’ve also proven with Sycamore that they’re not averse to working in winter, which is great for us. But at the same time, they haven’t put us in a situation where we couldn’t fulfil commitments to other clients.”
The guaranteed workload is the main draw for Subsea 7.
“But we were also interested in trying to work in a different way, rather than just routine contracting,” Sisley explains. “We’ll be participating in more aspects of individual projects, including scheduling, so both parties will have a clearer idea of what is required.”
The benefit to Venture is that they ought to achieve their production targets.
“I have been involved in partnerships or alliances in the past that didn’t work out,” Sisley says. “The relationship fell apart because the oil company couldn’t commit, or felt it would be let down by the contractor. Other independents have talked about this type of arrangement, but didn’t really believe in it themselves - whereas these guys do, they’re very open.”
The detail of the partnership is still evolving, but at present, a steering group comprising senior management from both sides meets to review progress once a month. Teams for individual projects, however, get together on a daily basis.
On some subsea developments, Sisley says, the process from tender to award can take four months, due to client deliberation and haggling over contractual terms. “Under our new arrangement, however, we expect to remove this time delay.
Oilexco Paleocene play
Canada’s Oilexco created a stir in the North Sea last year with its run of drilling successes on the Brenda field.
Brenda is a complex stratigraphic trap, but having completed delineation, Oilexco has wasted no time moving to a fast-track development. A Heads of Agreement was signed last month with CNR, under which Brenda will be tied back to the Balmoral field floating production platform.
Oilexco’s president and CEO Arthur Millholland founded the company in Calgary in 2003. Oilexco has a strong geoscience team with solid experience in Paleocene plays from exploration in Canada and the US.
The company first entered the North Sea in 2002, when it was awarded three licenses as operator under the UK’s 20th Offshore Licensing Round. The package of blocks included 15/25b and 15/25c in the Outer Moray Firth, an area know to be prospective for light oil in Paleocene Forties sandstone.
According to Oilexco CEO Arthur Millholland: “Our focus is on low-risk exploration and appraisal. We noted that portions of the Paleocene trends in this acreage were conducive to the development of stratigraphic traps, something we are very familiar with from our work onshore Canada.”
Brenda was first identified by Conoco in 1990, through well 15/25b-3, drilled as an appraisal of Sun Oil’s West Blair discovery in an adjacent block. The appraisal well encountered 22-ft of net oil pay in the uppermost Paleocene sands, flowing 2,960 b/d on test. Neither company followed up on these results, although Conoco’s well logs indicated good reservoir rock and high potential deliverability.
Oilexco started its work on Brenda by re-processing 300 sq km of 3D seismic acquired by Conoco in 1993 over the nearby Glamis field. The work was handled by GXT, a UK-based contractor. The re-processing included state-of-the-art pre-stack depth migration, which is not normally applied to prospects in the Paleocene trend, Oilexco claims.
In January 2004, the company contracted Peak Well Management to drill the first of several three-well clusters on the structure.
“The exploration program was complicated because the stratigraphic elements do not show up on the seismic as structural features,” Milholland explains. Of the initial trio of wells, the most productive was the third, 15/25b-8, which flowed up to 4,785 b/d of 40° API oil from Palaeocene Forties sand. Drilling on Brenda continued for much of the remainder of 2004, with seven more mostly successful wells and sidetracks, designed mainly to delineate the structure’s extent.
Exploration resumed this May, Oilexco having secured the semisubmersibleSedco 712under a two-year contract. This rig’s first assignment was a three-leg single well on block 15/25a, drilled under a farm-in arrangement with ConocoPhillips, with Oilexco funding the wells 100% to earn a 70% interest in the block. The aim was to appraise Nicol, another dormant Paleocene oil discovery, situated in between Brenda and the ConocoPhillips-operated MacCulloch field to the north-west.
In terms of structural definition, this latest cluster also seems to have been a success, with the third well bore intersecting 57-ft of net oil pay. The rig then moved north to appraise another structure on MacCulloch’s southern perimeter, again with a positive outcome.
Tieback options
Brenda lies 175 km northwest of Aberdeen in water depths of 150 m. According to the environmental statement for the field development, the oil is trapped laterally by the pinch-out of the Upper Paleocene sands along the channel margins. Overlying Lista and Sele shale sections provide the seal at the top of the reservoir, with hemiplegic claystones at the base of the debris flow channels acting as the bottom seal.
Once Oilexco had established that the field was commercial, it opted quickly for subsea development to a third-party processing platform. Of the candidates nearby, the MacCulloch FPSO was ruled out due to the costs of associated topsides modifications, and also the fact that the facility was operating close to capacity. Balmoral was the eventual choice, and was realistically always the most obvious candidate.
The field’s production semisubmersible was the closest platform (only 8.5-km distant), it had 50,000 b/d of spare capacity, and Oilexco already had a small stake in the facility, having acquired Pentex Oil’s interests in Balmoral and the associated Glamis field last August.
Development drilling should get under way early next year, with first oil due late 2006. The four wells, featuring gas-lifted subsea completions, will be gathered into an eight-slot seabed manifold. Combined production will be exported to Balmoral through an 8.5-km long, 10-in. pipeline, with a 4-in. gas lift line and a combined power / control umbilical. Oilexco has also proposed tying Nicol to the same manifold via a single production well and a 10-km flowline. Following processing, Brenda’s oil will be exported to the UK through the Forties Pipeline System. Technip will provide the subsea installation services.
Subsea facilities will include an integrated production system from Framo comprising open architecture controls, subsea test metering and multiphase pumping, with sufficient capacity for up to eight wells with gas lift. The metering equipment, in combination with compact multi-port selector manifold, will allow continuous testing of the wells for reservoir management and allocation purposes.
The multiphase pump will optimize tubing head pressures for maximum production: Brenda is expected to boost throughput at Balmoral from 6,000 b/d currently to 33,000 b/d at peak (not including contributions from Nicol).
According to an Oilexco spokesman, “A subsea booster pump was our preferred option, due to ease of change-out and the reduced subsea interfaces.” All subsea equipment will be pre-commissioned onshore prior to offshore installation.
Associated gas from Brenda will be used for both gas lift and power generation for Brenda and Balmoral.•
