Posted on 02/26/2011 6:24:49 AM PST by thackney
The declining flow of crude in the trans-Alaska oil pipeline could be stemmed, independent companies operating in the state said Feb. 18, and illustrated to the House Resources Committee two ways that could happen.
AVCG, Brooks Range Petroleum Corp. and Great Bear Petroleum LLC, testifying in favor of the governor’s proposal to increase investment by reducing oil taxes, House Bill 110, discussed two ways increased volumes of oil could be increased.
AVCG LLC, formed in 2000, is the holding company for Brooks Range Petroleum Corp. BRPC was established as the operating company for AVCG and has been drilling on the North Slope since 2007. Great Bear Petroleum is a company newly formed to target unconventional oil and gas from source rocks beneath the North Slope; it acquired more than 500,000 acres in the state’s October North Slope areawide lease sale.
BRPC and AVCG talked about an incremental plan involving the state, majors and independents, while Great Bear focused on its plan to produce oil from source rocks in an area south of existing development.
New developments
Bart Armfield, vice president of operations for BRPC, talked about “plan 2050,” and said it takes an incremental look at what would be required to keep the trans-Alaska oil pipeline flowing at 600,000 barrels per day. It’s a phased approach, he said, and requires the State of Alaska, the major company players and all of the independents.
If 10 new fields averaging 12,000 bpd are brought on in the next 12 years, that would increase recoverable reserves by half a billion barrels, and require in excess of $6.3 billion.
“History demonstrates that we can” do this, Armfield said, based on what has occurred over the last 12 years with Alpine, Northstar, Oooguruk and Nikaitchuq coming online and Badami restarted.
That isn’t 10 fields, he said, “but collectively they represent the equivalent of 10, 12,000-barrel-of-oil-per-day field projects.”
To get to the next level, 20 years out, requires that 22 more fields be brought online.
Armfield said unconventional resource plays and technology developments in the Lower 48 demonstrate what can happen, and said that in the very near future that may be applicable to the North Slope of Alaska.
By the end of the day, in “plan 2050,” 44 new developments have occurred, requiring more than $18 billion in new investment.
Armfield said the new fields are a combination of developments within existing units and grassroots developments. In the first 12-year phase, if existing units supported four new developments “then new players would support six grassroots developments.”
But the $18 billion to bring on that much new development really requires $36 billion in investment, Armfield said, because “not every project is going to be successful on the North Slope.” He said he used the 50-50 rule, with half failures and half successes, “which is probably very aggressive.”
To get $36 billion of new investment capital coming into the state requires “the positive adjustment through HB 110,” Armfield said.
Taxation an issue with investors
Ken Thompson, managing director of AVCG, called in to testify from the NAPE Expo in Houston, where companies show oil and gas prospects. Thompson said AVCG was looking for a partner to bring additional capital so that projects could be accelerated but also to look at “substantial upside on some of our acreage in the shale oil that you hear so much about in the Lower 48.” He said AVCG is looking for a partner with expertise and said this is the same play concept Great Bear has on its acreage.
Thompson said Alaska’s fiscal system makes it tough to attract partners and related that AVCG lost a former partner, Bow Valley, when Dana Petroleum acquired Bow Valley, concluded the fiscal regime in Alaska was tougher than in the United Kingdom, and decided to focus solely on the UK.
AVCG attended NAPE last summer and had 12 companies express strong interest, but over time all but one dropped out.
“If I were to rank the number one reason they said no, it’s the Alaska fiscal regime and the taxation is simply high and complicated. Several have elected to put their money into North Dakota in what’s called the Bakken oil shale where there’s a much more favorable severance tax rate. And also they do not face some of the same risks that Alaska does, so that’s certainly a factor,” Thompson said.
The board of the remaining company needs to approve and Thompson said senior management told him that “the board members just want to hear one thing and that’s about Alaska’s taxes.” He said he’d prepared a presentation and will have to update it based on how HB 110 progresses, but he said the taxation issue is the only issue remaining with that prospective partner, and “I hope we can overcome that.”
AVCG has a goal of achieving two of the oil fields needed in the first phase of the 2050 plan, he said, “so if we can just find a few other companies or attract some additional investors I think that can add up to the 10 fields we need. … Then the pie is larger and … everybody’s happy,” he said.
Nonconventional play
Ed Duncan, president and chief operating officer of Great Bear Petroleum, told the committee that competition for capital is on a global scale, and said while Alaska presents an opportunity for oil and gas investment, “we also see a great opportunity for Alaska to improve its position globally” by making the tax changes proposed in HB 110. Alaska is prospective for development because “it has some of the best rocks in one of the best petroleum provinces in the world.” But, Duncan said, “it also has some fiscal terms that are suppressing development.” Great Bear was high bidder on 537,500 acres in the 2010 North Slope areawide lease sale, an area the company picked for its source rock.
“This is an opportunity to deliver a play that has long-lived production; manageable risk; allows the state to forecast forward revenue; (and) has tremendous job growth associated with it — if we can make it happen,” he said.
The risk is not technical but “commercial viability in competition for capital (because it) requires capital to make this play really happen,” Duncan said, describing the play as both capital intensive and labor intensive.
Proof of concept
Development will require long-length lateral wells and fracturing and the first step is to prove up the concept. This year, Duncan said, Great Bear will build a rock mechanics model.
“Our rock mechanics studies will be drill holes with whole rock extracted” and then do technical analysis of rock strength to give the company “a better picture of how wells will drill and what kind of fracture stimulation technology will be deployed.”
Two full production tests will be drilled next January through April.
“The full-length laterals will be full exploration style wells.”
Duncan said that in unconventional resource plays once the boundaries of the play are known, “industry tends to move toward a factory type drilling,” increasing the rate at which wells can be drilled and stimulated and put on production.
“We have a very aggressive annual drilling schedule in a full development mode — 200 to 250 wells a year would be our target,” he said, with development drilling beginning in 2013, and up to 250 wells a year for 20 years, a total of 3,000.
Steady-state production would be 150,000 bpd, but would peak at some 300,000 bpd before dropping back to the 150,000 bpd plateau.
Capital intensive
“House Bill 110 will aid Great Bear in attracting critical capital,” Duncan said. At 250 wells a year the capex required for drilling alone is in excess of $2 billion a year, he said. And that doesn’t include facilities — roads, pipelines, pump stations and processing facilities.
Duncan said initial-stage investment capital for the company came from friends and family.
“The additional stages of investment capital that’s come forward to fund us through our proven concept stage has been very broad and significant,” he said, and will get them through the proof of concept stage, but changes in HB 110 would enable the company to go after the capital needed for full development.
The company has taken office space in Anchorage, but Duncan said “our mission is not to build a glass tower in Anchorage; our mission is to build technical alliances with key service providers that actually have cumulatively far greater experience than we could ever assemble if we went out and hired.”
Duncan said his greatest fear going into the October lease sale was that he would “have to really twist arms with the really big service providers to get the technology, drilling and well completion technology, and people” needed for the project.
But when Great Bear met with companies they found what they needed was already in the state, although not used very often, because Great Bear is “the first company to do that unconventional play.”
But the $18 billion to bring on that much new development really requires $36 billion in investment, Armfield said, because “not every project is going to be successful on the North Slope.” He said he used the 50-50 rule, with half failures and half successes, “which is probably very aggressive.”
Oh brother. We can’t afford this especially saying 18 billion but really requires 36 billion. “Not every project is going to be successful on the North Slope??? Sounds like a failure to me. I guess this is one reason why we can’t get people to want to drill for oil.
The article implies to me that the reason for declining pipeline flow is that the suite of wells supplying it is dwindling. This is interesting... it contradicts my layman’s limited-knowledge presumption, based on an old article or two, that the flows were diminishing because of pipeline age. Is the total flow an issue with both? Does an old pipeline have “arteriosclerosis”? Would a flow as high as when the pipe was new, now create a higher risk for pipe breakage?
The age of the pipeline and the slow flow create a problem. Slow flow allows water to drop out and accumulate in low points between pigging. This is a point of corrosion over time.
The pipeline needs more feed into it to keep the flow up as the existing North Slope fields continue their declining production rates.
Opening up NPRA, ANWR and the offshore would help a lot.
/johnny
What’s “feed”? some filler?
I presume that low flows contribute more to corrosion... exposing more air to the inner walls.
...based on what has occurred over the last 12 years with Alpine, Northstar, Oooguruk and Nikaitchuq coming online and Badami restarted. That isn't 10 fields, he said, "but collectively they represent the equivalent of 10, 12,000-barrel-of-oil-per-day field projects." To get to the next level, 20 years out, requires that 22 more fields be brought online.
Nice that they are honest, but that is still a ton of money. When the 15 trillion is paid off then we can talk about projects like this.
No air in the line. Its just moves slower.
/johnny
I would like that if it worked. Exon, and the other oil companies could easily pay the 36 billion. No use having the government pay it......we can’t afford it.
Feed is oil. Input to the line.
Good find.
Thank you.
We don’t need no stinkin oil, we don’t need no stenkin revenue, we don’t need no stinkin jobs, we don’t need no food, oops oops belay that last one.
They're not asking for government investment.
Instead, they're asking that Alaska lower its severance tax so as to encourage private investment.
It's a win-win because, if no investment is made, the severance tax revenues will continue to decline as the existing reservoirs are depleted.
Disclaimer: Opinions posted on Free Republic are those of the individual posters and do not necessarily represent the opinion of Free Republic or its management. All materials posted herein are protected by copyright law and the exemption for fair use of copyrighted works.