Trans-Alaska pipeline upgrades continue
 Click here to go to the full PDF version of this issue, with any maps, photos or other artwork that appears in
some of the articles.
Alyeska progresses pump station electrification and installation of technology for dealing with low oil flow through line
Alan Bailey Petroleum News
With oil production from Alaska’s North Slope in continuous decline for many years, Alyeska Pipeline Service Co., the operator of the trans-Alaska oil pipeline, has been upgrading the line and taking other actions to accommodate the technical issues caused by declining pipeline throughput. And an overview of the latest status of Alyeska’s efforts to deal with the slowing flow of oil forms a core component of the 2012 State Pipeline Coordinator’s Annual Report, published in October by the Alaska Department of Natural Resources.
Pipeline throughput peaked at more than 2 million barrels per day in 1988 but had dropped to around 600,000 barrels per day in 2012, the report says. The State Pipeline Coordinator’s Office oversees the construction and operation of pipelines, including the trans-Alaska pipeline, on state right-of-way leases.
Low flow The key issue for the trans-Alaska pipeline is the speed at which oil flows down the line. Essentially, the pipeline has a fixed internal volume configured to handle peak oil throughput and, with less and less oil entering the upstream end of the line, oil filling the line takes longer and longer to travel from the North Slope to Valdez.
With the slowing oil flow, the original pipeline pump systems, designed to handle relatively high rates of oil throughput, became inefficient and unsuitable for flexibly handling the lower flow rates. And, with the oil taking longer to travel the pipeline’s 800-mile length, the oil, warm as it exits the oil fields, becomes increasingly cold along the pipeline route, raising risks associated with the freezing of water carried along with the oil and potentially increasing the clogging of the pipeline walls with wax deposits.
Strategic reconfiguration In the early 2000s, to address the increasing inefficiency of the pumping systems as oil volumes declined, Alyeska initiated what it termed “strategic reconfiguration,” a massive project involving the replacement of the original turbine driven pumps by new state-of-the-art electrically powered pumps — variable frequency drives on the new pumps would enable the pumps to operate over a relatively wide range of pump speeds. And as part of strategic reconfiguration, Alyeska installed new remotely operated pipeline control and monitoring equipment, using modern digital technology.
Alyeska completed the electrification upgrades at pump stations 3, 4 and 9 in the years 2005 to 2009. Upgrade work started on pump station 1 in the 2000s but Alyeska subsequently put this upgrade on hold, the report says.
With fewer pump stations needed at lower oil throughputs, Alyeska shut in the remaining pump stations, apart from pump station 5, which acts a pressure relief station on the south downslope of the Brooks Range and does not pump oil.
Pump station 1 During the 2011 financial year, which ended on June 30 of that year, Alyeska restarted the upgrade at pump station 1 in a phase of strategic reconfiguration that the company called the electrification and automation project, or EA, the report says. The EA project involves the installation of three new mainline pumps, with electric motors and variable frequency drives; the installation of a 12-megawatt turbine-powered electrical generator; and the modification of two of the three booster pumps at the pump station for electrical service. The project also involves the construction of a power line and electrical substation, to enable the new pumps to use power from the Prudhoe Bay grid in the event of a shutdown of the new generator system.
As part of the project, by the end of June of this year Alyeska had installed about 200,000 feet of the 293,000 feet of new electrical cabling needed at pump station 1. The new electrical substation was completed in the spring of 2012 and work on the pump station cabling is progressing around the clock, the report says. The EA project appears to be on target for completion in the summer of 2014, the report says.
Three events From the perspective of falling oil temperatures, the report highlights three events that illustrate the vulnerability of the pipeline to low-flow problems. In November 2006 low flow resulting from reduced North Slope oil production, storms at sea and some tanker loading problems at Valdez caused the internal pipeline temperature to drop to 37 F. In 2008 delayed tanker loadings because of storms resulted in a temperature drop to below 40 F. And in January 2011 an oil leak at pump station 1 on the North Slope triggered an extended pipeline shutdown, with the oil temperature dipping to 26 F.
“While these events were cause for concern, none of them prevented the restart of TAPS,” the report says. “A future event with a more extended shut down or lower flow rate might seriously affect the ability to restart flow.”
Recycling Since the January 2011 shutdown incident Alyeska has been recycling oil at pump stations 3, 4, 7 and 9 to warm the oil when oil temperatures in the pipeline drop, the report says. Recycling involves pumping some or all of the oil through pressure-reducing valves at the pump stations, with the pumps adding energy to the oil and the pressure reduction converting flow energy to heat.
However, Alyeska has encountered some snags with the recycling arrangements, including mechanical problems at pump stations 3 and 4, and flow-induced vibrations at pump station 7. The company is upgrading the recycling systems at these pump stations and anticipates the systems being fully operational by late 2012 or early 2013, the report says.
Alyeska has also sanctioned a project designed to further increase oil temperatures through the use of improved control valves for the recycling systems at pump stations 3 and 4, and through the use of new control valves at pump station 7, the report says.
The company is investigating the possibility of heating the pipeline oil flow at pump station 5 and is also considering other possibilities for mitigating the risks to winter pipeline operations. Those possibilities include injecting additives such as freeze-depressants or emulsifiers into the oil; removing water from the oil at pump station 1; and tightening the standards for the amount of water and sediment allowed in oil delivered to the pipeline.
The report also points out that another way of addressing the low flow issues would be to increase production from the North Slope oil fields.
Follow up As a follow up to the January 2011 incident and in response to a safety order by the U.S. Department of Transportation, Alyeska has been replacing or removing some old piping at pump station 1; constructing an additional facility between pump stations 5 and 10 to launch and receive the torpedo-shaped “pigs” that are used to clean and inspect the inside of the line; researching the installation of increased pump station tank capacity; and staging equipment needed for cold temperature operations or a pipeline restart in cold conditions, the report says.
And the company has revised its procedures for a pipeline cold restart. Under new procedures, if the oil temperature drops below 40 F during a pipeline shutdown, a startup of the pump station recycling systems to warm the oil will precede the startup of oil flow through the pipeline. However, if the oil temperature drops below the normal operating temperature range in a situation where oil flow has stopped for an extended duration, it may be necessary to pump oil both north and south in the pipeline to prevent the oil in the line gelling, the report says.
And, to implement the new cold restart procedures, Alyeska has installed new 540-horsepower booster pumps at pump stations 7 and 9 and anticipates installing a 3,390-horsepower engine for the booster pump at pump station 12 in 2013, the report says.
The company is improving the recycling arrangements at pump station 5 by using a tank heater to add heat to the oil in the event of a cold restart.
Alyeska has accepted that the minimum safe oil temperature to maintain oil flow is 31 F but the company also says that the oil temperature should be maintained at or above 36 F, with this being the target minimum temperature to be maintained as a result of low flow mitigation projects, the report says.
Refinery changes One particular issue that Alyeska now needs to contend with is a further drop in oil temperatures in the southern section of the pipeline as a consequence of the reduced temperature and lower volume of residue fluids entering the line from the oil refinery at North Pole, near Fairbanks. The refinery uses some oil from the pipeline as feedstock and returns the refinery residues back to the line. The heat from these residues has been an important factor in maintaining adequate oil temperatures in the pipeline south of North Pole. Since February 2012 an energy savings initiative at the refinery has reduced the temperature of the residues by 20 to 25 F, while a cut back in refinery production has resulted in a corresponding drop in the volumes of refinery residue, the report says.
Pipeline vibrations Alyeska has also been addressing issues associated with pipeline vibrations at the three mountain passes that the line crosses: Atigun Pass in the Brooks Range, Isabel Pass in the Alaska Range and Thompson Pass, north of Valdez. The vibrations first appeared in the 1990s at Thompson Pass, where Alyeska has mitigated the problem by increasing the downstream backpressure in the line, the report says. The company is trying a similar approach at Atigun Pass.
“Preliminary indications are that vibrations have been reduced and APSC (Alyeska) is evaluating the data to see if TAPS can operate continuously with this backpressure,” the report says.
With metal fatigue damage being predictable by a mathematical analysis, an engineering study of the vibrations concluded that vibration induced stresses at Atigun Pass will not result in any risk of a pipeline rupture “in the intermediate or near future,” the report says. However, the vibrations have caused cracks to appear in some of the “shoes” that cradle the pipeline on the above-ground pipeline support structures in the Chandlar Shelf area on the south side of the pass. Alyeska now regularly monitors and, as necessary, replaces the shoes in the affected area, the report says. The company is also taking steps to improve the shoe design and is installing accelerometers for better vibration data logging and analysis.
Vibration levels in Isabel Pass, although increasing, are much lower than in the other two passes, the report says.
“The original TAPS design has built-in redundancies. Such safety factors include the allowance for limited (pipeline) support failure,” the report says. “For these reasons, and others, the vibrations in these areas do not appear to constitute an integrity threat.”
|
