The question of how low the flow rate of oil through the trans-Alaska pipeline can go before the pipeline becomes inoperative seems a bit like the proverbial question about how long is a piece of string: it all depends on how long you want it to be. And in the case of the pipeline commonly referred to as TAPS it seems that the ultimate answer depends on how much money can viably be spent making pipeline modifications to keep ever smaller volumes of oil trickling south from pump station one on Alaska’s North Slope.
As illustrated by the recently concluded court case over the tax valuation of TAPS, the question of how little oil the pipeline can carry matters a great deal. The lower the volume of oil that can flow down the line, and the longer the life of the line, the more pipeline is worth and the greater the property tax bill for the pipeline owners. At the same time, extending the pipeline life increases the amount of oil that can potentially be recovered from North Slope oil fields, thus enabling oil producers to beef up their “booked” oil reserves, hence increasing the values of their companies and raising their appeal to potential investors.
But just what are the facts regarding the issues surrounding the slowing flow of oil through TAPS?
Few people, if any, dispute the nature of the essential problem: Pipeline throughput is steadily dropping and the 48-inch diameter pipeline was designed to move much more oil than it carries at present. At its peak the line shipped about 2 million barrels of oil per day, while at present that daily throughput has dropped to just over 600,000 barrels.
To enable pumps to push oil over the ups and downs of a pipeline route that includes a couple of mountain ranges, it is necessary to keep the entire line filled with oil. To keep the line full as pipeline throughputs drop, the rate at which the oil flows down the line has to become lower and lower. And nowadays the diameter of the line really is too large for the quantity of oil that the line carries.
With temperatures in Alaska well below freezing during the winter, the oil, warm as it exits the oil fields, cools as it flows south from Prudhoe Bay. And the slower the oil flows, the colder it becomes before it reaches the Valdez Marine Terminal for loading into oil tankers. If the temperature of the oil drops below the freezing point of water, ice is likely to form in the line, potentially causing line blockages and damaging pipeline equipment. At low temperatures, increasing amounts of wax will tend to drop out of the oil, causing clogging of the line. And, also as flow rates drop, the flow in the line will become less turbulent, transitioning into what is termed “laminar flow” and increasing the tendency for sludge to drop out of the oil.
Alyeska Pipeline Service Co., the company that operates the pipeline on behalf of the pipeline owners, periodically runs torpedo-shaped devices called “pigs” down the interior of the line, to scrape and clean the inside walls. Were ice to form in the line, a pig would likely become stuck, a situation that would be difficult and expensive to remedy and that would presumably cause a pipeline shutdown. In addition, the difference in fluid pressure between the front and rear of a pig drives the pig down the line — as the oil flow in the line drops that pressure differential also drops, thus making it increasingly difficult to move pigs and hence clean the line. But, as wax and sludge deposits increase in low-flow scenarios, pig operations become increasingly important in keeping the pipeline clean.
One helpful feature of the TAPS configuration is the existence of an oil refinery at North Pole, near Fairbanks, around the midpoint of the pipeline route. The refinery accepts part of the crude oil stream from the pipeline, refines some products such as jet fuel from it, and then returns the residual fluids back to the line. The residual fluids retain heat from the refinery process, thus heating the oil as it continues on its route to Valdez. Were the refinery to close, Alyeska would presumably have to install some form of heating system, to replace the heating effect of the refinery residues.
The big questions over the future of TAPS relate to estimates of throughput levels at which low-flow problems will start to appear, and whether there is some throughput threshold, below which the pipeline will become impossible to operate.
There are ways to deal with the cooling of the oil, such as the installation of heaters and the warming of the oil by circulating the oil through pipes at pump stations. But can these low-flow mitigation measures handle very low throughput volumes? And at what point does the cost of installing and implementing the mitigation measures cease to be viable? The higher the pipeline operating costs, the higher becomes the transportation cost of the oil, thus lowering the oil’s wellhead value.
In the TAPS valuation court case Superior Court Judge Sharon Gleason accepted the principle that there is some minimum throughput flow rate, below which TAPS ceases to be viable, even if technically the pipeline with appropriate mitigation measures could handle very low rates.
A report published by Alyeska in June 2011, following a study into TAPS low-flow issues, says that low-flow mitigation measures will be essential to keep oil flowing through the pipeline at flow rates below about 550,000 barrels per day. The report listed a number of potential low-flow mitigation measures, such as the heating of the oil upstream of cold points on the line, but said that the Alyeska study had not addressed the mitigation of low-flow problems at flow rates below 350,000 barrels per day.
“As flow rates decline below 350,000 bpd, issues related to low flow will increase the problematic impact on the TAPS operation,” the 2011 low-flow report said. “Measures to mitigate these issues utilizing the existing 48-inch pipe at throughputs below 350,000 bpd have not been determined at the date of this report.”
In the TAPS valuation court case, the TAPS owner companies used the results of the Alyeska low-flow study to claim a minimum viable TAPS throughput rate in the range 300,000 to 350,000 barrels per day. However, Judge Gleason rejected this argument, saying that the Alyeska study had addressed questions of how to keep the pipeline in operation with throughputs down to 300,000 barrels per day, and that the study had not attempted to establish any minimum possible throughput capacity.
And Dan Hisey, a former Alyeska chief operating officer, testified that TAPS has no hydraulic or mechanical minimum throughput level.
According to an Associated Press report, Alyeska spokeswoman Michelle Egan has said that the Alyeska low-flow study was not intended to identify some technical or economic limit for the pipeline.
Judge Gleason’s decision document says that BP had until 2004 used 300,000 barrels per day as the likely minimum TAPS throughput when making estimates of remaining oil reserves on the North Slope. That minimum throughput estimate was apparently based on the use of the turbine powered pumping systems originally installed in TAPS to drive oil from Prudhoe Bay to Valdez. However, the conversion of the pumping systems to the use of new electrically powered pumps as part of a major TAPS upgrade project called “strategic reconfiguration” had considerably increased the flexibility of the system to handle lower oil volumes.
In 2004 BP commissioned a study by a consortium headed by JTG Technology & Information Services Inc. into the potential minimum TAPS throughput following strategic reconfiguration. And a 2005 JTG Technology report for the company suggested that, with the application of heat to the line and some other possible pipeline modifications, pipeline throughput could be sustained down to levels of about 135,000 barrels per day. Further hydraulic flow testing would be required to confirm that result, the report said.
The report also said that, were the pipeline owners to replace the original 48-inch pipeline from Prudhoe Bay to Fairbanks by a new 20-inch pipeline, with oil being carried by railroad from Fairbanks to tidewater in Southcentral Alaska, throughput could be sustained down to 45,000 barrels per day.
BP subsequently used the 135,000 barrels per day lower throughput limit to determine the North Slope oil reserves that the company reported to the Securities and Exchange Commission, the court decision document says. According to testimony presented at the court, transitioning to the 20-inch pipeline option to handle lower flow rates would have involved a “stair step” cost of around $3 billion.
The decision document says that in 2010 BP retained Phil Carpenter, an expert in TAPS low-flow issues, to determine the feasibility of operating TAPS at throughputs below 135,000 barrels per day, without that $3 billion cost hurdle. Carpenter concluded that that it would be possible to operate the pipeline with throughputs in the range of 70,000 to 100,000 barrels per day by installing heaters at intervals along the line. Carpenter’s report stated that wax deposition and issues with pig operations would probably put a lower threshold of 50,000 to 70,000 barrels per day on throughput supported by pipeline heaters. Going below that threshold for oil throughput would likely require other remedies, such as the mixing of seawater with the oil, to maintain total fluid throughput rates, the report said.
However, Carpenter did express concern about the feasibility of operating pigs in the line at 70,000 barrels per day — he recommended research into pig designs for use in this type of scenario, the court decision document says. Carpenter also expressed concern about the impact of pipeline shutdowns and slowdowns on oil temperatures and wax accumulation, the document says.
Cost of heating
In 2010 BP commissioned a report into the likely cost and timing of implementing the system of heaters proposed in the Carpenter report. And from the fall of 2010 BP started using the 70,000- to 100,000-barrel range as the low-flow limit when booking its North Slope oil reserves, the court decision document says.
According to the decision document the BP-commissioned cost report estimated that the implementation of heaters as per the Carpenter plan would cost about $3 billion. However, the Carpenter plan assumed the installation of a heating capacity 70 percent in excess of what might actually be needed, thus making the potential implementation cost substantially lower than the cost estimate prepared for BP, the decision document says. But even with the $3 billion cost, the value of proven oil reserves on the North Slope would render the heating upgrade viable, the document says.
Gleason: 100,000 barrels
Judge Gleason concluded that, based on evidence presented in the court, TAPS can carry oil down at least to a minimum throughput of 100,000 barrels per day.
The question of how this presumed minimum throughput translates to an estimated life expectancy for TAPS then depends on estimates of how much oil remains technically recoverable from Arctic Alaska and on future oil prices, with the prices determining the economic viability of oil production. Testimony presented in court illustrated the considerable uncertainty in current estimates of both oil resources and future oil prices, with various consultants presenting a wide range of estimates for different stakeholders in the economics of TAPS.
Ultimately, Judge Gleason found oil production forecasts presented by consultant Dudley Platt to be the most persuasive of the various forecasts presented to the court. Platt, who used to maintain oil production forecasts for the Alaska Department of Revenue, had prepared forecasts for the Alaska municipalities that obtain revenues from TAPS property taxes.
The decision document says that Platt’s forecasts of remaining recoverable reserves lead to a probable end of life around 2065 to 2068 for TAPS, assuming a 100,000-barrels-per-day minimum throughput. This estimate excludes possible production from the Point Thomson field, the field that is currently the subject of a dispute between the field owners and the State of Alaska.
By comparison, reports by BP to the Securities and Exchange Commission for the Prudhoe Bay Royalty Trust, an investment fund for the Prudhoe Bay field, have indicated TAPS end-of-life expectancies ranging from 2049 to 2075, with that wide range of years apparently related to an equally wide range in future oil price expectations. The pipeline owners’ testimony to the court presented a range of years from 2032 to 2053, with significantly lower estimates of remaining oil reserves than those presented by Platt. The State of Alaska, with reserves estimates between those of the owners and those of the municipalities, estimated an end of life ranging from 2043 to 2053, if the pipeline is operates to its economic limit, the decision document says.