The fall production forecast for Alaska’s North Slope is down from the spring forecast — down for the next eight years. Projected volumes have dropped as much as 130,000 barrels per day for fiscal year 2012, petroleum engineer Dudley Platt told the Alaska Senate Finance Committee Nov. 7. The estimated drop for the current fiscal year, 2008, is 38,000 bpd. The reduction in projected barrels increases through FY 2012, and then decreases, with a drop of just 30,000 bpd for FY 2015.
Platt noted that if you look only at projected changes in volumes from state lands (current vs. spring forecast), the range is from a drop of 38,000 bpd in FY 2008, peaking at a drop of 55,000 bpd in FY 2010, with volumes from state lands going positive at plus-5,000 bpd in FY 2014 and plus-10,000 bpd in FY 2015.
Platt said the timing of new projects appears to have changed, but that’s not the most important thing: The major factors are increases in unplanned interruptions in production and planned downtimes for infrastructure renewal.
He said back maybe five or six years he used to be able to get within 2 percent with his forecast for the current fiscal year, but recently the difference between projected and actual production has been higher.
Unplanned interruptions can’t be predicted, Platt said, “so I attempt to make a rational judgment as to how many of those events are going to happen. I’ve dialed that number up for the next eight years.”
Field-by-field forecast
Platt has done production forecasts for Revenue since 1989, first as an employee but for the last 15 years as a contractor. He said he does the forecasts on a field-by-field basis, part of a “bottoms-up approach” which involves taking “a clean, fresh look” at every field twice a year and continually reviewing the assumptions he builds into his forecast.
Then he runs the numbers and when he sees the kind of difference between forecasts that he saw between this year’s spring and fall projections, he looks at the differences on a field-by-field basis, looking for mistakes.
Unfortunately the drop in forecast production wasn’t based on a mistake.
Comparing plots of daily production from the greater Prudhoe Bay area for 2005 and 2007, production in 2007 shows “significantly more than the volatility of the same line just two years ago,” Platt said.
Problem not with reservoirs
Platt said the problem doesn’t lie with the reservoirs.
North Slope reservoirs “want to produce — they’re healthy reservoirs,” he said.
“Just because a reservoir is capable of producing, there’s a lot of other things that can prevent it from performing up to the expectations that I have of it and frankly the expectations that the operators have of it.” Platt said those things include the wells, flowlines, facilities and the trans-Alaska oil pipeline.
“It’s getting the oil from the reservoirs, up to the surface, to the facilities, to Pump Station 1, down to Valdez, where we have a lot of room” for unexpected events that it’s hard to include in a forecast, he said.
In addition to unplanned interruptions, planned infrastructure renewal is likely to slow production rates. Calendar year 2006 “was defined as the year of integrity management,” Platt said, and “was highlighted by pipelines that had some issues.” Platt said that following the pipeline problems in 2006, operators probably decided to “look at everything. And as a result of that they put together an integrity management plan that led to an infrastructure renewal plan that will take years to complete.”
Infrastructural renewal
In calendar year 2007, he said, integrity management seems to have given way to “infrastructure renewal, lifecycle replacement costs.” Healthy reservoirs need “facilities that have integrity” and “a trans-Alaska pipeline that has integrity,” he said.
Platt said he took “a fairly detailed site-inspection tour of all the major fields on the North Slope” about a month ago “and I had a chance to talk to field managers and operators. …”
One issue that came up, he said, is the 1,100 miles of pipelines at Prudhoe Bay alone. “They’re not going to last forever.”
At Milne Point he learned “that over the next three to five years they will be replacing certain flowlines on a regularly scheduled pace” that will reduce production while that replacement is being done “and it will also, hopefully … extend the life of the oil production.”
Platt said he’s heard “there’s plenty of capital and expense money” to go around but that money isn’t always going to “rate-enhancing projects.”
While production may be slowed because you have to shut in facilities to work on them, “you still get the production — you just get it later. That’s my interpretation of the geological producing characteristics of the fields,” Platt said, “and I just don’t believe that not getting it now won’t allow you to get it later.”
700,000 through 2014
Including federal production, “my latest forecast says we’re at 700,000-plus” barrels per day through 2014, Platt said. The fall production forecast for FY 2008 is 732,000 bpd, although Platt warned that for every degree over normal during the winter, you take off 2,000 bpd.
In addition to planned and unplanned interruptions, Platt said he “slowed the pace of heavy oil development,” based on discussions with industry. There are challenges to West Sak-Schrader Bluff development, he said. There were reservoir issues at West Sak, what Platt called “major bypass events,” but he said “ConocoPhillips has done a really good job of figuring out how to fix the problem.”
BP Exploration (Alaska), which is developing the comparable oil at Orion in the western Prudhoe satellite area, “has learned from that and Orion does not suffer from those particular reservoir issues.”
West Sak development in the Kuparuk River unit has commercial issues, as well as technical challenges. “Just because one company, perhaps the operator at an oil field, wants to do something doesn’t necessarily mean that they’re going to convince their co-owners to sign off on that. And that’s happening also at West Sak,” Platt said.
In trying to anticipate that, “I’ve stretched out the development plan as projected to the Department of Natural Resources for West Sak.” ConocoPhillips knows where they want to go, “where they’d like to go — but they can’t because of co-owner approval issues.” Platt said that every time an extra drill site at West Sak is delayed, you delay 10,000 to 15,000 bpd.
New project timing
Platt said Liberty is an example of how he’s revised his projections for new project development.
Initially BP thought it would develop Liberty as a standalone project, he said, but then with further evaluation it realized surplus capacity at the Endicott facility could handle Liberty. It will take, he noted, “world-record” extended reach drilling and construction of “the world’s biggest rig” to reach Liberty from Endicott.
“When you do it that way,” he said, rather than with the more expensive standalone project, “you drill one, maybe two wells a year to see if it works. And you wait a year and you do two more wells and then you wait again and you do two more wells.”
And that approach changes the pace of production, Platt said.
Instead of “a rapid rise to a peak plateau production, you have a stair step,” he said. When you delay some of the production it’s a timing event.
He said he also delayed Liberty production six months because that was what BP told the Minerals Management Service.
There has also been a delay at Oooguruk. A year ago, Platt said, Pioneer Natural Resources expected production to start in the fourth quarter of 2007; now it looks like second-quarter 2008.
And at Nikaitchuq, where Kerr McGee expected to have first production in the fourth quarter of 2008, Eni has taken over as operator and merged in the Tuvaaq unit. Platt said he’s delayed startup there for another year in his forecasts.
While new oil is an issue in maintaining production levels, there are also issues at existing fields, where Platt said facilities expansion may be needed. He said the large facilities are “maxed out on how much gas they can handle and they’re getting close to being maxed out on how much water they can handle. … If they don’t expand their facilities to handle that, the oil production will continue to go down.”
Production basis for forecast
What’s in the forecasts is producing fields, fields under development and fields under evaluation.
There aren’t any undiscovered resources; no Ugnu — the heaviest and shallowest North Slope oil; only a very small portion of West Sak and Schrader Bluff, heavy oil lighter than Ugnu; no discoveries on the federal outer continental shelf such as Sivulliq, Kuvlum and Sandpiper; no National Petroleum Reserve-Alaska discoveries, except a few known oil pools near Alpine; and no barrels from new technologies such as slope-wide implementation of low salinity waterflood, a technology BP is just beginning to test at Endicott.
The largest field under evaluation is Point Thomson, which Platt said he’s currently showing as coming online in 2017.
There was a plan of development for Point Thomson when Platt started doing forecasts in 1989, he said, and plans kept calling for bringing the field online six or seven years down the road. “So it seemed like every year for the last 10 years I’ve been continually pushing that out.” A few years ago the development proposal was changed from gas-cycling to gas sales.
Platt said he’s been using a 10-year planning horizon for Point Thomson, and pushing it out. And “I miss my forecast when I do that — actual vs. what I’ve said — I always miss it.”
Point Thomson is a gas condensate field, but “it’s got an oil rim on it” and like Prudhoe Bay, Kuparuk and Alpine, “Point Thomson has some satellite fields that are known to exist — one kind of straddles ANWR.” When Point Thomson production is deferred, it’s not just 70,000 barrels a day from Point Thomson, but 20,000 to 30,000 bpd from satellite opportunities in the Point Thomson area, Platt said.
