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Time for ‘Plan B’ for North Slope gas? Walker’s state-led pipeline reasonable effort in circumstances, but time to look at alternatives to LNG, gas pipeline, Heinze says TIM BRADNER For Petroleum News
A former state Natural Resources Commissioner and president of a major Alaska oil and gas operating company has endorsed Gov. Bill Walker’s plan for the state to continue pursuit of a large natural gas pipeline and liquefied natural gas, or LNG, project.
However, Harold Heinze, who was the senior executive at ARCO Alaska and ARCO Transportation in the 1980s and was Gov. Walter J. Hickel’s DNR commissioner in the early 1990s, also believes it’s time to look for a “Plan B” for alternatives for using North Slope gas if Walker’s initiative proves unsuccessful.
In an interview, Heinze said that alternatives like gas-to-liquids (where natural gas is chemically converted to liquid form to be shipped through the trans-Alaska oil pipeline), direct loading and shipment by tanker of LNG made on the North Slope and even converting the existing TAPS line to carry natural gas are possibilities that should be seriously examined.
The latter case, shipment of gas through TAPS, would include a new, smaller oil pipeline built to carry crude, but one sized more efficiently for the amounts of oil likely to be produced on the slope.
Completed in 1977, TAPS currently ships about 500,000 barrels per day, a fraction of its original 1.5 to 2 million barrels per day design capacity.
“The Alaska constitution requires that we look at all alternatives for maximizing value in using state resources,” Heinze said in an interview.
Walker’s state LNG initiative reasonable “Over the last few years a large-diameter gas pipeline to an LNG export terminal at tidewater in southern Alaska has been the focus of both the North Slope gas producers and the state of Alaska,” Heinze said in written comments following the interview.
“After extensive engineering and project management work the producers have concluded they are unable to proceed at this time with further investment because the risks associated with the huge investments overwhelm the potential income and profit streams. No income would be generated until the entirety of the project is completed,” Heinze said.
Given the situation, Walker’s proposal to investigate a state-led effort seems reasonable. “The state of Alaska, under Governor Walker, is proceeding to test the Asian gas market to identify potential customers interested in upstream and in the LNG plant and pipeline, thereby reducing the project risk. This is a worthy effort, to find a way forward,” Heinze said.
Taiwan made hard dollar offer “Past attempts have found potential project partners (in Asia) but failed because the state was unwilling to accept the lowered wellhead values associated with these commercial conditions,” Heinze said in his comments.
In this, the former commissioner was referring to an offer made by Taiwan when he was a special advisor to Gov. Hickel and working to find market partners for Alaska gas in Asia.
Heinze developed a firm offer with Taiwan to buy North Slope royalty gas and finance the equivalent of the state’s share of an LNG project, although Hickel rejected it, he said.
The offer was to buy state royalty gas for 50 cents per million British thermal units (which roughly relates to the same price per thousand cubic feet) but Hickel rejected it because 50 cents was too low, said Heinze, who presented the offer.
“Governor Hickel strongly supported sales of Alaska gas to Asia but he wasn’t willing to give state gas away to get a pipeline,” Heinze said in the interview. Hickel’s determination to get good value for the state’s gas at the wellhead is a consideration often lost in the current discussions over the Alaska LNG Project.
The state’s royalty interest is the “Alaska peoples’ share” of the gas and the state should make every effort to get top dollar at the wellhead, just as the producers want good value for their gas, Heinze said.
High LNG costs mean low wellhead value? However, that could now be a challenge, given cost estimates for building the Alaska LNG Project and the outlook for continued low prices for LNG for an extended period.
Studies for the state by consulting firms like Black and Veatch show that even if gas is sold in Asia for $13 per million Btu, a price well above those prevailing, the effective wellhead value could be zero.
Internal studies by industry over several decades reached the same conclusions, Heinze said.
A low or zero wellhead value essentially means no profit in the project, which would be unacceptable to both the state and producers, Heinze said.
The biggest challenge facing Alaska LNG is the complex interaction of the multiple mega-project components and the sheer scale and size of the whole project when compared with many competing projects, which are right at tidewater and don’t need an 800-mile new pipeline. The current cost is now estimated at $45 billion.
Gas to liquids an option? But if Alaska LNG isn’t workable anytime soon, what might be? There are possibilities that could see North Slope gas marketed without building a new pipeline. One is gas-to-liquids.
“Given the low flow in TAPS and significant breakthrough technologies (for chemical conversions) it may be attractive to build smaller plants (than the LNG Project) to convert gas molecules into longer hydrocarbons molecules,” which would be liquids that could be shipped in TAPS.
“New combinations of catalysts and high-efficiency ‘nano’ (small scale) reactors could produce synthetic crude oils, diluent for heavy oil and enhanced recovery fluids,” the latter two which could aid in production of new conventional oil.
A diluent is a liquid used to thin a thick fluid, like heavy oil, that is too viscous to ship through a pipeline on its own. Having such fluids available is ultimately essential if the huge untapped North Slope heavy oil resources are to be developed.
“A meaningful-sized gas-to-liquids plant could be one-tenth previously envisioned (for gas marketed as LNG) and this would greatly reduce the investment exposure and also provide a decade of follow-on construction using an Alaskan workforce,” as the GTL project is incrementally expanded with additional plants on the Slope, Heinze said.
Gas-to-liquids has key advantages over a conventional gas pipeline and LNG project. Two are in using the existing TAPS and eliminating a large LNG plant at the southern end of a new gas pipeline (the LNG plant constitutes about half the cost of the total LNG project).
A third advantage is that a large North Slope plant to remove the 12 percent carbon dioxide in Prudhoe Bay gas is also unneeded, as this function is essentially performed by the gas-to-liquids plant. “Gas-to-liquids processes like carbon dioxide, where an LNG plant cannot tolerate it,” which requires its removal, Heinze said.
There are other ways North Slope gas could be marketed, however. For years people have asked if an LNG project at the North Slope might be feasible. Until recently, the presence of heavy, multi-year ice in the Beaufort Sea made direct shipping of LNG doubtful, but this has changed, Heinze said.
“With the Arctic becoming naturally free of ice over at least the next 20 years, the economics of direct-shipment of LNG should be attractive. Saving the 800-mile pipeline cost is a huge advantage compared with a minimal increase in ice capable tanker costs,” Heinze said in his comments.
“A plant comparable to the existing Cook Inlet plant would be sufficiently large to achieve the economies of scale at a considerably reduced investment risk,” he said. Once in operation, the LNG plant could be incrementally expanded as the volume of shipments grows.
When he was with ARCO and also as a consultant, Heinze was involved in scoping studies of an Arctic LNG transportation system, which envisioned a system of icebreaking LNG tankers, assisted by icebreakers, delivering LNG to storage facilities in the Aleutians where conventional LNG tankers would take delivery.
One conclusion of the study was that the presence of multi-year ice presented operational performance risks, and that icebreaking or ice-strengthened LNG tankers had not yet been demonstrated.
However, that was over 30 years ago. Now the bulk of the ice in the Beaufort Sea is relatively thin one-year ice, a result of climate change, which makes navigation easier and tanker performance predictable.
There is also more experience with Arctic shipping of oil and gas, including LNG, although most of this is on Russia’s Northern Sea Route.
One of the problems that confronts Arctic loading of LNG is the shallow depth of the near-shore Beaufort Sea along the northern coast including Prudhoe Bay. If an LNG plant were built onshore a technically challenging cryogenic pipeline several miles out to an offshore loading facility would be needed. In years past there were concerns about how the moving polar icepack would affect an offshore facility and how LNG vessels could be reliably managed in heavy ice.
Climate change again has changed some of that thinking. Even in late winter most of the polar ice is thinner, one-year ice. Also, BP (and now Direct shipping of LNG from Slope? Hilcorp) has safely operated the Northstar production island six miles offshore Prudhoe Bay for 15 years and has demonstrated techniques to manage ice encroachment.
Unlike other offshore artificial gravel production islands like Caelus Energy’s Oooguruk and Eni’s Nikaitchuq, which are protected from moving pack ice by natural barrier islands, Northstar is in a location fully exposed to the winter icepack.
Northstar is also located in about 40 feet of water, which with some dredging might allow access by medium-sized LNG vessels. A possibility is that if the Northstar field is depleted its gravel island might be incorporated for LNG loading.
A point Heinze made in the interview is that these are engineering problems that could be defined and managed within a changing Arctic environment, and that while LNG ship operations in the Arctic would be costly, those costs pale in comparison with building 800 miles of 42-inch pipe south across Alaska.
Ship gas through TAPS? The third, which seems most radical at first thought, but commonsense at a more basic level, is converting TAPS to a gas pipeline. There’s fundamentally no technical barrier to this, Heinze says, but North Slope oil must still be shipped so this project must be done in connection with building a new, smaller oil pipeline.
“The time has come to address the need for a new oil line that can continue to operate long into the future at rates one fifth of the existing pipeline’s capacity,” Heinze said in written comments.
At the current rate of oil production decline, TAPS, as it is now configured, may not be economical to operate by the late 2020s.
“A new 20-inch or 24-inch high pressure (pipeline) could use a new universal mono-pipe column support design (in lieu of the current, expensive vertical supports on TAPS) and could use the existing right-of-way, pump stations, terminal and control center,” Heinze wrote.
“Once the new line is in service the 48-inch pipe could be converted to low-pressure gas service and with new compression stations it could carry as much as 1 billion cubic feet per day to an LNG plant,” which would be built in Valdez.
Heinze has unique perspective Heinze comes at these questions from a unique perspective, incorporating both creativity and analytics. As a former state DNR commissioner he understands the state’s constitutional mandate to maximize the value of state-owned resources and in this case, the royalty share of North Slope oil and gas.
As a former ARCO president, whose Alaska industry career actually started in 1969 when the Slope oil discoveries were confirmed, Heinze has inside knowledge of how industry works and the development challenges of Alaska and the North Slope.
Heinze was also, in recent years, executive director of the Alaska Natural Gas Development Authority, or ANGDA, a kind of predecessor of the state-owned Alaska Gasline Development Corp., or AGDC.-
ANGDA, under Heinze, focused mostly on problems related to getting gas to Alaska communities, such as through lateral lines built off a larger gas pipeline and the use of propane container-sized tanks for waterborne delivery. AGDC, in contrast, is focused on building the entire $45 billion Alaska LNG Project to export North Slope gas.
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