BP Exploration (Alaska) Inc. continues to push the envelope on advanced drilling and production technology to sustain oil production in the greater Prudhoe Bay area.
The BP PLC unit has taken an aggressive approach to reducing costs and introducing new efficiencies with the greatly expanded use of such technologies as coiled tubing drilling and horizontal wells.
In addition, advances in 3D seismic data gathering and processing have enabled the company to discover a number of small satellite fields in the greater Prudhoe area.
Together, these efforts are painting a different picture of the Prudhoe area as merely the home to a declining supergiant. Instead, BP's focus is on increasing its production in Alaska and keeping it at that higher level indefinitely, putting the turndown date for the Trans-Alaska Pipeline System (TAPS) much further into the future.
Early this year, BP Alaska Pres. Richard Campbell said, "We are now moving ahead with plans to increase our Alaska North Slope oil production by nearly 20% in the next 18 months-from 300,000 b/d to about 350,000 b/d-and to sustain this higher production level into the future.
"We plan to accomplish this through the 2001 start-up of Northstar [oil field], new exploration in the National Petroleum Reserve-Alaska, satellite development, and sustaining core production."
Taken together with the gathering momentum for monetizing stranded gas on the North Slope-26 tcf of reserves in the Prudhoe gas cap alone-the view of the Prudhoe area as rejuvenated for the long term has taken on new luster.
Changes at Prudhoe
Last year, the sale of ARCO's Alaska assets to Phillips Alaska Inc.-following BP's acquisition of ARCO-and the subsequent realignment of equity interests among the major owners of Prudhoe Bay field led to BP being named the sole operator of Prudhoe Bay and other fields in the greater Prudhoe area.
Previously, BP and ARCO had each operated half of Prudhoe Bay, North America's largest oil field. In the early 1990s, BP underwent extensive restructuring and consolidation at a time when operating costs were rising and Prudhoe production was declining. At the time, BP and ARCO embarked on a crash program to combine operations and avoid duplication in order to cut costs. A number of functions, including drilling, logistical support, and warehousing, became shared services.
This closer cooperation thus helped pave the way for a single operatorship, which took effect July 1, 2000, that all agreed would reduce Prudhoe operating costs still further.
Even after the realignment of equity interests, BP continues to chase cost savings in every area of its North Slope operations in what is arguably the most difficult operating area in the world. In the process of integrating the two Prudhoe operations into one, BP targeted savings of $100 million/year. The company recently said it was about halfway to that point. Those savings are coming from reductions in staff, trimming outlays for produrement and contractor expenses, and various methods of tweaking satellite development plans.
In integrating the two corporate cultures, BP has created an entirely new culture, said Greater Prudhoe Bay Business Unit Leader Neil McCleary, noting that about 50-55% of BP Alaska's employees trace their lineage to ARCO or even the former Amoco Corp., also acquired by BP in the late 1990s.
"There's a new culture, and it's a culture that's looking at Prudhoe Bay and the rest of the greater Prudhoe Bay area satellites as having a long-term future...where, historically, we thought that Prudhoe would be about a 25-year asset," he said. "We now think that maybe 50 years may be reasonable, so another 25 years out in the future or even 30 or 40 years out in the future is conceivable-certainly with the gas [commercialization] prospects creating a lot of excitement about the long term."
Satellites
To sustain that long-term vision, BP has pressed development of a string of satellites that are tied back to Prudhoe Bay area facilities for processing and transport through TAPS. They include:
- Midnight Sun. Discovered and started up in 1998, this satellite had 60 million bbl of OOIP and 100 bcf of OGIP. Production earlier this year was 2,400 b/d from two wells.
- Aurora. Starting up in November 2000 at a rate of 7,200 b/d, this satellite now produces about 6,300 b/d from five wells. OOIP was 100 million bbl, and OGIP was 100 bcf.
- Niakuk. Actually two offshore fields, Niakuk and Western Niakuk produce from an onshore drillsite at a rate of 18,000 b/d from 18 wells. The fields started up in April 1994 from the drillsite, and permanent production modules were installed in 1995, when a waterflood was initiated. Production is processed via the Lisburne field production center. The Niakuk fields held 200 million bbl of OOIP and 100 bcf of OGIP.
- Eider. This satellite of Endicott started producing in June 1998 and yielded 1 million bbl under a pilot program before the field was shut in pending supply of water from Endicott. Full production was resumed in June 2000, utilizing a twinned producer-injector scheme. This year, production is expected to average 1,100 b/d. OOIP and OGIP were 13 million bbl and 52 bcf.
- Sag Delta North. Another Endicott satellite, this field started production in 1989, peaking at 13,000 b/d in July of that year. Current output is 400 b/d from two wells, processed through Endicott facilities. It held OOIP of 14 million bbl.
- Badami. Strictly speaking, not a satellite, Badami was the first field BP developed remotely from Prudhoe Bay area infrastructure. It started up in August 1998, but production was hobbled due to reservoir compartmentalization. BP conducted workovers, started gas injection, and explored for new pay horizons, and the field underwent a winter warm shutdown during February-May 1999. Badami now produces 2,000 b/d from one well. OOIP is pegged at 160 million bbl.
Drilling approaches
The greater Prudhoe Bay area has become something of test laboratory for innovations in drilling approaches that provide cost-reduction opportunities, which in turn render some marginal projects economic.
BP has employed widespread use of extended-reach and multilateral horizontal wells, slimhole and ultraslimhole wells, and coiled tubing drilling.
Each multilateral well, for example, represents a savings of $2-3 million in avoidance of new infrastructure costs on the slope.
A switch to smaller-diameter slimholes in the early 1990s enabled BP to shave more than $1 million from the cost of a typical Prudhoe horizontal well that cost as much as $3.7 million in 1992.
And using coiled tubing to drill sidetracks or to handle workovers enables BP to avoid having to use a heavy-duty rotary rig. Plans call for BP to drill about 60 wells with coiled tubing this year.
The company now considers coiled tubing drilling to be its preferred tool for drilling on the slope. CTD now accounts for well over half of all wells drilled in the Prudhoe area, according to Ken Eagle, chief of staff to Campbell.
BP spokesman Ronnie Chappell put the number at closer to two thirds or even three fourths of all wells drilled in Prudhoe Bay field, where the company has developed smaller tools for inserting into progressively smaller production tubing compared with the first CTD tools developed on the slope in the early 1990s.
"I think the operators up here have done more coiled tubing drilling in Prudhoe Bay than possibly anywhere in the world, given the technology that they have developed and perfected here," he said, noting a "fair number of [rotary] rigs that are stacked" on the North Slope now.
CTD has other benefits for BP on the slope beyond the avoidance of high day rates for rotary rigs, McCleary noted.
"By using coiled tubing for reentering existing wells, the surface impacts are basically eliminated," he said. CTD provides the opportunity drill many wells as sidetracks, sometimes even a second or third from an existing wellbore, he noted. And the growing use of the technology has enabled BP to make changes in its drillpad design, reducing what had been a 50-55 acre area to perhaps 10 acres.
Extended-reach drilling, such as the record-setting program in Niakuk field, allowed BP to develop the small offshore field with minimal facilities onshore. In addition to the cost savings, such an effort minimizes environmental impact in the sensitive arctic ecosystem. Lateral displacements in some ERD wells on the slope have reached 20,000 ft to date. Detailed engineering studies are under way now for four ERD wells at Milne Point that could exceed that. And plans are being considered for intelligent completions of some of the slope's ERD wells, which will help in minimizing workover costs.
BP is looking again at ERD after the Niakuk program of the late 1990s, when it stepped away from the technology because of its high costs amid the 1998-99 oil industry downturn.
Pushing the envelope on ERD-as it did at Wytch Farm in the UK with a 35,000 ft extended-reach well-enables BP to rethink some of its satellite development approaches, leveraging its existing infrastructure rather than investing in the extremely costly kind of infrastructure required on the slope.
Perhaps just as important is the ability to drill in new areas where access is a problem beyond physical barriers. North Slope operators could use ERD wells to gain access to deposits underlying especially sensitive surface features. While the Inupiat residents of the North Slope generally favor oil and gas development onshore, they remain opposed to offshore drilling over concerns that it might interfere with the migration of the bowhead whale, key to their subsistence culture. And industry has yet to develop a plan for cleaning up an oil spill in broken ice conditions. That's the reason BP opted to permanently restrict drilling at Northstar to the winter season.
Northstar
Northstar is the latest stand-alone North Slope development for BP, but it's a field that was discovered in the Beaufort Sea in the early 1980s by units of Shell Oil Co. and Amerada Hess Corp. Although Shell and Amerada built Seal Island and drilled from that gravel island five appraisal wells, they opted against developing the field, citing its high costs and the state's steep net profits royalty scheme.
BP acquired the Shell and Amerada interests in Northstar in early 1995 and proceeded with module construction after the state agreed to switch the royalty scheme to 20-27.5% sliding scale royalty tied to oil prices.
Construction was then postponed because of permitting delays and lawsuits, but construction began in late 1999, with Seal Island being rebuilt into a permanent production island. BP then laid a 17-mile pipeline linking the field, in 37 ft of water, with TAPS; a 10-mile section of that line was buried on the Beaufort Sea floor.
It was the first time a pipeline had been buried in the arctic seafloor, a special concern because of seabed ice gouging, caused by irregular ice keels under floating sea ice (OGJ, Apr. 30, 2001, p. 100). The line was buried as much as 9 ft below the seabed, beyond what would be considered a 100-year ice-gouging event. It is also the first arctic offshore field to be connected to shore only by pipeline. The only other producing arctic offshore field, Endicott, is linked to shore with a gravel causeway.
BP is constructing in Anchorage the biggest oil and gas processing module ever built in Alaska, for sealift to the North Slope and installation on the Northstar production island this summer. Living quarters, utility modules, and piperacks were sealifted from Anchorage in July 2000 and installed on the island later that summer.
Development calls for drilling 13 producers, 6 water injectors, three gas injectors, and 1 waste disposal well. Reserves are pegged at about 176 million bbl out of 247 million bbl of OOIP.
At presstime, BP was drilling the fifth development well and had planned to shut down drilling on July 15 to prepare for the installation of the production module in early August.
Startup is expected in the fourth quarter, with the official date put at Nov. 1, but BP is pressing to beat that deadline. Production is expected to start up at a rate of about 30,000 b/d and then peak at 65,000 b/d.
Exploration focus
BP's exploration program is concentrated on two areas that have offered little excitement for North Slope explorationists since Prudhoe start-up: the National Petroleum Reserve-Alaska and natural gas prospects.
Interest in NPR-A faded after a round of leasing and exploration in the reserve during the 1980s failed to yield any significant results.
But the discovery of Alpine oil field and its satellites Tarn and Tabasco, just outside the northeastern edge of NPR-A, got explorationists intrigued enough to press for another attempt at exploring in the reserve.
F.X. O'Keefe, BP Alaska business unit leader for Alaska exploration, explained the change in explorationists' thinking about NPR-A:
"What really changed out there was...the recognition that there was a light oil play on the west side of the slope. That was really recognized in Tarn and Tabasco first, but then it was confirmed with Alpine; that really changed people's view of the hydrocarbon system out there-that lighter oil can be produced at higher rates from a lower-quality reservoir. That's really turned people on to the idea that there might be a play that had never been made in NPR-A."
The result was of this new interest was another federal lease sale offering NPR-A acreage in May 1999, with two groups-ARCO and Anadarko Petroleum Corp. and a combine of BP, Phillips, and Chevron Corp.-dominating the sale. Phillips has already announced five successful wells from its NPR-A exploration effort, while BP drilled two wells at the Trailblazer prospect this past winter.
The Trailblazer wells are farther north and west from where Phillips drilled its wells (see map, OGJ, May 21, 2001, Newsletter, p. 8). BP completed both wells, but is holding them tight and may release details later this year, O'Keefe said.
"We had a very short season out there, so we didn't get to do everything we wanted to do," he noted. "The winter was warm early on, so when we had to build a 75-mile-long ice road to get out there, that took a couple of weeks longer than we thought, and we lost quite a bit of time."
BP and its partners are currently discussing whether or not to reenter the wells next season.
Further piquing industry's interest is the prospect of another lease sale in the same northeastern planning area of NPR-A that was offered in 1999. And the US Bureau of Land Management is considering a plan to offer the rest of NPR-A for leasing.
O'Keefe sees NPR-A prospects farther to the south and west as being even more frontier in nature, in terms of geology as well as remoteness from infrastructure: "Anything you found out there would have to be quite significant to make it economical."
The key to NPR-A exploration is throughly understanding the petroleum system there, O'Keefe noted.
"We knew we had a light hydrocarbon system; the question is, are some parts of the area truly gas-prone-perhaps some others would be retrograde condensate, and some others would be light oil," he said. "I couldn't yet predict where those areas are going to be. And I know that's one of the things we're working on right now from a geochemical standpoint, as I understand the distribution of the different phases out there."
BP isn't interested in offshore exploration for the near term; its main focus in exploration terms through 2004-05 is "between the rivers on state acreage" on the North Slope, O'Keefe said.
Gas exploration
But increasingly, that exploration focus includes the search for natural gas, something that might have been dismissed out of hand just a few years ago. The dramatic upsurge in North American gas markets during 2000-01 and the related revival of interest in bringing North Slope gas to market has changed that view.
The interest in North Slope natural gas prospects was made evident at the last North Slope areawide lease sale, which the state held in May. Anadarko in particular cited gas prospects in detailing its bidding strategy at that sale.
"We're actually just getting started to explore for gas...that's really the long-term piece of our exploration program," O'Keefe said. "To do that, we've joined Anadarko and Alberta Energy [Co.] in exploration of the ASRC [native corporation Arctic Slope Regional Corp.] holdings...and that acreage does extend up into the area where the last areawide sale was held.
"It will be a few years before we're actually drilling out there. We're still in the process of finding where the reservoir quality is better so that we can actually get a commercial rate. We know there is a lot of gas in the area. The question is, can we build a tool that predicts reservoir quality-and I believe we can. I think that we'll have one, but we need to do the work before we go out there and drill the well without knowing what we're going to see. So I think you'll see us de-risking the play for the next 2 years."
The US Geological Survey estimates the Brooks Range foothills of the NPR-A could hold a potential gas resource of 30-100 tcf. O'Keefe reckons that the commerciality threshold for gas find in that area would have to be "several tcf minimum."