Rig availability off northwest Europe will remain tight through 2006, according to a new Peak Well Management Group survey. The Aberdeen-based contractor also expects dayrates for all types of rigs to keep climbing, with perhaps no downward pressure on prices or demand until 2008.
Peak runs a multi-well program in the North Sea area on behalf of four main oil company clients, and is therefore in the thick of bidding. This year it expects to manage up to 22 development and exploration wells. According to Operations Manager Ian Burdis, the program involves contracting two jackups and one semi and managing another semi for a company that contracted this rig.
“Our multi-well approach allows us to deliver better rates and security of rig supply,” he explains. “We also arrange for participants to discuss farm-ins and preferred well order, and we can provide them with greater flexibility in taking up well options. We also aim for better rig performance through sharing of start-up costs.”
The survey of the available drilling fleet shows that 21 semis are at work across the UK sector this year, including one pulled back from West Africa to meet rising demand. Five other semis remain stacked, mostly since 2002. “There would be a lot of effort involved taking these units out of stack, so they are not being actively marketed.” First availability for any semi on the UKCS is October.
Norway has 12 semis on duty, and none at all available this year. Most programs in this sector are longer-term than those off the UK. Looking ahead to 2006, 12 of the UK fleet are already fully contracted, with 12.5 rig years tied up in the Norwegian sector. Theoretically, some semis that left the North Sea for the Gulf of Mexico or West Africa could return. But importation costs can be high in cases where the rig’s North Sea Safety Case has lapsed.
As for jackups, 13 are at work at present in UK waters, with no availability until November. Seven each are on duty offshore The Netherlands and Denmark. Jackups will become available in Denmark in November, followed by The Netherlands in December. Off Norway, the four jackups on offer are also fully booked. Next year, seven of the UK fleet are fully assigned already, as are two in The Netherlands and five in Denmark. Offshore Norway two-and-a-half rig years are tied up so far.
According to Burdis, two of the main drilling contractors appear to be driving rates up. Last August, the fee for a standard third generation semi in the North Sea was $50,000/d. This shot up to $90,000/d in October, and in one case, to just under $110,000/d in December. Jackup rates climbed from $55,000/d last August to $80,000/d in December, and bids for service next year now start at around $90,000/d.
“There may be some panic-buying pushing rates into the $160,000 bracket. We are also aware of two operators that have contracted rigs for one year each, even though they only have firm commitments for two wells each. That’s a gamble, as it would be up to them to try to farm out these rigs to lessen their costs.” However, he also believes contractors could be wary of letting the market overheat.
UK platforms for sale
Since the Peak survey, Shell has tightened the North Sea market further by contracting three semis for 12- to 19-month spells for operations in the UK and Irish sectors. Much of the program is development oriented.
Recently, the company issued an announcement of a rare discovery in the UK sector, drilled jointly last fall with Apache in a low-relief structure in UK block 22/12a. The partners drilled the well using theSedco 711 and identified a 60-ft hydrocarbon column in the Forties reservoir before plugging and abandoning the well. The location is between the Montrose complex and the Shell-operated Nelson field.
The Auk A platform, 155 mi east of Aberdeen, is one of several Shell-owned assets up for sale.
Under a separate joint venture, Shell and its long-standing UKCS partner ExxonMobil have put their interests in the producing Auk, Fulmar, and Dunlin fields on the market. The assets include acreage, production licenses, and infrastructure across blocks 30/16b, 30/11b, and 30/11b-f. Shell’s E&P technical director in Europe, Kieron McFadyen, points out that despite the planned sell-off, his company is still committed to spending $6-7 billion throughout its European operations in 2005-07. This includes a new gas reception facility at Bacton, Norfolk, to receive supplies imported from The Netherlands through the soon-to-be-installed 235-km subsea BBL pipeline.
Norway cool on CO2
Norway’s Petroleum Directorate (NPD) has ruled out use of CO2 injection to increase oil recovery on the Norwegian shelf, following negative results from a feasibility study. The study examined all potential aspects of the CO2 chain, from source, capture, and transport to injection and long-term storage.
NPD found that while injection is technically feasible, and the potential for increased recovery is substantial, the threshold costs for setting up a delivery chain are presently prohibitive. Recovery costs look to be around $30-33/bbl - much higher than prices normally quoted by oil companies for long-term projects with a high level of risk.
The study evaluated 20 fields on the Norwegian shelf, that might be suited to CO2 stimulus. Total increased recovery is estimated at 150-300 MMcm of oil; however, large volumes of CO2 would have to be available at the right place and the right time to exploit the potential prize. There would also need to be expensive modifications to existing production installations to prepare them for CO2 treatment and injection.
The study also pointed out that treated fields will, like any others, undergo planned or unplanned shutdowns from time to time. To avoid large emissions of CO2 when injection is not possible, the capture/transport infrastructure would have to be linked to an alternative long-term storage facility, again pushing costs beyond the economic limit.
In the Dutch North Sea, Gaz de France is persevering with a project to investigate the feasibility of CO2 injection and storage in depleted natural gas fields. The almost-spent K12-B reservoir (150-km northwest of Amsterdam) is the subject of a three-phase study.Phase 1, which Gaz de France has completed, examined potential use of the field’s facilities, including the K12-B platform. Phase 2, recently begun, will comprise two tests at different locations in the reservoir:
- Test 1: CO2 injection into the K12-B8 well, a depleted reservoir compartment
- Test 2: CO2 injection into a nearby depleted section drained by two gas-production wells and one CO2 injector (K12-B6).
Gaz de France’s objectives in this phase are to examine reservoir response in an area still under production, to assess the potential for enhanced gas recovery, and to examine the degree of corrosion along the tubing of the CO2 injection well. Results are due out later this year.
