Legislature(2017 - 2018)BARNES 124
05/12/2017 01:00 PM House RESOURCES
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| Presentation: Oil & Gas Well & Pipeline Safety | |
| Adjourn |
* first hearing in first committee of referral
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ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
May 12, 2017
1:04 p.m.
MEMBERS PRESENT
Representative Andy Josephson, Co-Chair
Representative Geran Tarr, Co-Chair
Representative Dean Westlake, Vice Chair
Representative Harriet Drummond
Representative Justin Parish
Representative Chris Birch
Representative DeLena Johnson
Representative George Rauscher
Representative David Talerico
MEMBERS ABSENT
Representative Mike Chenault (alternate)
Representative Chris Tuck (alternate)
COMMITTEE CALENDAR
PRESENTATION: OIL & GAS WELL & PIPELINE SAFETY
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
KRISTIN RYAN, Director
Division of Spill Prevention & Response
Department of Environmental Conservation
Anchorage, Alaska
POSITION STATEMENT: Provided an update on recent pipeline
spills and answered questions.
FRANK RICHARDS, PE, Senior Vice President, Program Management
Alaska Gasline Development Corporation
Department of Commerce, Community & Economic Development
Anchorage, Alaska
POSITION STATEMENT: Provided information related to the Alaska
Gasline Development Corporation's ongoing work on pipeline
design.
KEITH MEYER, PhD, Pipeline Engineering Manager
Alaska Gasline Development Corporation
Department of Commerce, Community & Economic Development
Anchorage, Alaska
POSITION STATEMENT: Provided information related to pipeline
safety and response.
GENE THERRIAULT, Director, Government Relations
Alaska Gasline Development Corporation; Team Lead
Interior Energy Project
Alaska Industrial Development and Export Authority
Department of Commerce, Community & Economic Development
Anchorage, Alaska
POSITION STATEMENT: Provided information on future business
opportunities for the Alaska Gasline Development Corporation.
ACTION NARRATIVE
1:04:30 PM
CO-CHAIR GERAN TARR called the House Resources Standing
Committee meeting to order at 1:04 p.m. Representatives Tarr,
Parish, Talerico, Westlake, Drummond, and Josephson were present
at the call to order. Representatives Rauscher, Birch, and
Johnson arrived as the meeting was in progress.
^PRESENTATION: OIL & GAS WELL & PIPELINE SAFETY
PRESENTATION: OIL & GAS WELL & PIPELINE SAFETY
1:06:20 PM
CO-CHAIR TARR announced that the only order of business would be
a presentation detailing oil and gas well and pipeline safety,
which was requested by Representative Parish.
1:06:39 PM
KRISTIN RYAN, director, Division of Spill Prevention & Response,
Department of Environmental Conservation (DEC), provided updated
information on recent pipeline spills reported by Hilcorp Alaska
(Hilcorp) and BP. In Cook Inlet, three incidents were reported
by Hilcorp. The first was a natural gas pipeline that ruptured
and leaked natural gas into Cook Inlet at a depth of about 75
feet for several weeks; the pipeline has now been repaired and
the cause of the rupture was found to be scouring of the ocean
floor as a section of the pipeline rubbed on the subsurface of
the ocean. Before the repair, the amount of gas flowing in the
pipeline was reduced by one-half, and now the pipeline and
affected platforms are in operation at full capacity. The
second release of oil was believed to be in a pipeline
connecting the Anna platform to the Bruce platform on the west
side of Cook Inlet. However, DEC has concluded a large boulder
hit the legs of the Anna platform and oil condensate burning in
a flare mechanism was released into the environment and observed
as sheen. Hilcorp drained the feeder tube connected to the
flare and provided evidence that three gallons of oil condensate
were released into the environment. After approval by the
Pipeline and Hazardous Materials Safety Administration (PHMSA),
U.S. Department of Transportation, and DEC, Hilcorp reopened the
pipeline in the presence of PHMSA, DEC, and the U.S. Coast Guard
(USCG) without further incident. The third leak in Cook Inlet
was an anomaly in a natural gas pipeline within the jurisdiction
of PHMSA, and she said she had no further information except
that the problem has been resolved.
1:11:37 PM
REPRESENTATIVE PARISH asked for the approximate dates of the
first incident in Cook Inlet.
MS. RYAN said the leak continued from December [2016] to April
[2017] and offered to provide the specific dates.
REPRESENTATIVE PARISH related Hilcorp stated the leak ended in
the second week of April, and inquired as to how many cubic feet
of natural gas were wasted.
MS. RYAN said she would provide that information.
REPRESENTATIVE PARISH said Hilcorp estimated a loss of 26
million [cubic feet of natural gas], and inquired as to the age
of the pipelines.
MS. RYAN advised the original infrastructure was installed in
the early '60s; however, there have been upgrades and changes
made to the pipelines, so she was unsure of the age of specific
areas of the pipelines.
REPRESENTATIVE PARISH asked Ms. Ryan if her division had
accurate information on which sections of pipeline are original,
which have been replaced, and when.
MS. RYAN said no. Her division has an assessment and inventory
underway in conjunction with PHMSA, the Cook Inlet Regional
Citizens Advisory Council, and certain other state and federal
agencies "to get a better picture of the infrastructure from a
holistic perspective ...." Companies provide information when
contingency plans are submitted to DEC for approval that include
preventing spills and their capacity to respond if one occurs,
but the plans do not provide details related to the age of
pipelines.
REPRESENTATIVE PARISH asked for the anticipated lifespan of a
pipeline in the bottom of Cook Inlet before it fails.
MS. RYAN explained the technology for building pipelines has
changed and pipelines are different now. She related the
pipelines in Cook Inlet were not expected to operate for "this
long a period of time ... this is beyond the life that was
originally anticipated."
1:15:25 PM
REPRESENTATIVE RAUSCHER recalled after the [Exxon Valdez Oil
Spill on 3/24/89] double-hulled oil tankers were required, and
suggested the use of double-hulled pipelines may be possible in
the future.
MS. RYAN further explained that the pipelines being built today
are often encased in materials such as concrete. Although not
the same as a double-hulled tanker, pipelines today meet the
standards nationally recognized as the "best standards." [DEC]
has a best available technology requirement that asks industry
to consider using the best equipment and technology for new
construction. She remarked:
The best available technology process is sort of an
iterative process where they evaluate all the
different options that they could use to build that
pipeline and we work with them to figure out the right
and safest method ... that is economically feasible.
REPRESENTATIVE RAUSCHER surmised pipelines in Cook Inlet are
built to new and improved regulations.
MS. RYAN added the best available technology contingencies in
DEC statute and regulations are "state of the art" and in common
use today from a regulatory perspective, "to try to push
industry to use the best technology available to them."
Further, it allows some flexibility to determine the best
methods.
REPRESENTATIVE PARISH expressed his concern that because of
aging infrastructure other pipelines may be in a similar
condition as those that have failed. He posited this may be the
indication of the beginning of a systemic failure, and
questioned how DEC would respond.
MS. RYAN pointed out the state has very different standards for
oil pipelines than for natural gas pipelines; in fact, there are
no standards for natural gas pipelines. There are many
standards for pipelines and infrastructure related to oil. For
example, in addition to the best available technology clause
[oil producers] are required to have cathodic protection and
leak protection technology, so industry monitors pipelines on an
ongoing basis to seek leaks before they occur and perform
prevention measures. She said aging infrastructure is not a new
problem in Cook Inlet or on the North Slope thus DEC is focused
on preventing spills from aging infrastructure by leak detection
technologies.
1:20:51 PM
CO-CHAIR JOSEPHSON asked whether Ms. Ryan could inform the
committee on the history of why the state regulates the quality
and care of oil pipelines but not that of gas pipelines.
MS. RYAN read from AS 46.03.020, DEC generic powers of
department authority, as follows [in part]:
... allows the department to adopt standards for
petroleum and natural gas pipeline construction,
operation, modification, or alternation.
MS. RYAN advised the aforementioned clause creates authority for
DEC to set standards for the construction of natural gas
pipelines; however, AS 46.04.050 exempts DEC from requiring
contingency plans for natural gas pipelines. She explained the
logic behind the exemption was that if there is a release of
natural gas there is no method to clean it up, and therefore
there is no need to document through a contingency plan that a
company has the capacity to clean up a spill. Ms. Ryan related
several years ago "it was looked at to decide if the state
wanted to pursue regulations for natural gas pipeline
construction and operation, and it was determined that that was
not in the best interest for the state, because it would require
getting primacy from PHMSA, the federal organization that
regulates all these lines, and it's sort of an all or nothing
opportunity: you either take all the natural gas pipelines in
the state from PHMSA and do what they're doing, or you do none.
... I was told at that point the state decided that was a lot of
work ... that the work that PHMSA was doing was adequate, and
that the state wouldn't be doing it, probably, any differently
than PHMSA is doing it now, and declined to, to adopt
regulations."
1:23:52 PM
CO-CHAIR JOSEPHSON questioned whether the Alaska Oil and Gas
Conservation Commission (AOGCC), or another agency, could go to
Hilcorp or another company and demand that it make an effort to
stop a natural gas leak.
MS. RYAN explained AOGCC has authority if a company is wasting a
state resource. However, in the aforementioned situation, the
resource was not being extracted but was transiting from land to
fuel an oil platform, thus AOGCC did not have a role. In a
situation where a resource is being extracted and is not managed
correctly, AOGCC could step in. [PHMSA] does have the ability
to force Hilcorp to contain and control any leak from a natural
gas pipeline, and did so. [PHMSA] inspects pipelines, and has
requirements that pipelines are constructed and repaired by
methods that meet national standards, and the state relies upon
PHMSA to regulate natural gas pipelines.
CO-CHAIR JOSEPHSON asked why offshore drilling can be done
safely in the Beaufort Sea and the Chukchi Sea, but the [Hilcorp
pipeline repair] had to wait until ice was cleared in Cook
Inlet.
MS. RYAN pointed out in Cook Inlet the issue was that the divers
needed to be tethered to a boat, and because the boat may have
needed to move to avoid ice flow, the situation was unsafe for
divers. In federal waters, the [Bureau of Safety and
Environmental Enforcement (BSEE), U.S. Department of the
Interior] regulates oil spill prevention and response activity
such as the proposal to drill in the Beaufort and Chukchi seas;
in fact, BSEE required a three-way contingency process to close
a well - all of which would be functional even with ice cover -
before it allowed Shell [oil company] to drill. This is a very
different scenario than a natural gas pipeline in Cook Inlet,
and a very different regulatory paradigm.
1:28:05 PM
CO-CHAIR TARR asked if the movement of the large boulder that
struck the Anna platform could have been related to seismic
activity.
MS. RYAN said it is pretty typical for large boulders to be
rolling around on the seafloor of Cook Inlet due to the strong
tidal influence that pushes the rocks around. In response to
Representative Parish, she said there are 15 platforms in Cook
Inlet.
REPRESENTATIVE PARISH asked for the amount of funding available
for the eventual removal of platforms.
MS. RYAN deferred the question to the Department of Natural
Resources (DNR) because DNR leases the subseafloor to the
platforms with requirements for removal.
CO-CHAIR TARR turned the presentation to Representative Parish's
question as to whether the legislature could be assured that a
large diameter pipeline [under] Cook Inlet would not cause
problems, or how to protect the state from problems.
REPRESENTATIVE PARISH stated that he raised the question of
pipeline safety because of the loss of tens of millions of cubic
feet of natural gas through a pipeline leak. He shared his
strong concern about putting another pipeline in a seismically
active area that possibly could not be repaired for a long time
due to weather.
1:32:50 PM
FRANK RICHARDS, PE, senior vice president, program management,
Alaska Gasline Development Corporation (AGDC), Department of
Commerce, Community & Economic Development, provided brief
background information for Dr. Keith Meyer, pipeline engineering
manager, AGDC. Mr. Richards informed the committee AGDC's work
on pipeline design is conducted within the regulations and
statutory requirements of the Pipeline and Hazardous Materials
Safety Administration (PHMSA), U.S. Department of
Transportation. The transportation of natural and other gas by
pipeline is governed by PHMSA regulation 49 CFR Part 192, which
is the regulation that pipelines in the U.S. must meet to
progress to operation. As a regulator, PHMSA will ensure AGDC
is in compliance with its standards and AGDC has worked with
PHMSA on the Alaska Stand Alone Pipeline (ASAP) and the Alaska
LNG Project (Alaska LNG) due to the great concern about pipeline
safety specifically related to frost heave or frost settlement
to the land crossing from the North Slope to Cook Inlet.
Further, the Cook Inlet crossing is also a very challenging
environment, but AGDC has a design package that meets all
requirements and would put in place safety factors to ensure the
pipeline will meet its design lifespan and beyond.
1:35:18 PM
KEITH MEYER, PhD, pipeline engineering manager, AGDC, said AGDC
is in the design phase of the Alaska LNG project which
incorporates a Cook Inlet crossing. He related AGDC took over
the design of the pipeline from the [Joint Venture Agreement
(JVA) between BP, ConocoPhillips Alaska, Inc., and ExxonMobil]
and is working with the original contractor for the Cook Inlet
crossing, INTECSEA Houston Energy Center II. [AGDC] has
incorporated the design into its recent filing with the Federal
Energy Regulatory Commission (FERC), especially related to
Resource Report 11, which defines pipeline reliability and
integrity in general. He explained the pipeline is one of three
major components [of the project], along with the gas treatment
plant (GTP) and the liquefied natural gas (LNG) plant. Also
included in Resource Report 11 is discussion of the Cook Inlet
crossing, which is of particular interest to PHMSA, the agency
that administers the federal regulations that govern the
pipeline: Title 49, CFR Part 192, that sets the minimum federal
safety standards for natural gas pipelines. Dr. Meyer further
explained there were multi-year analyses of the Cook Inlet
crossing that considered alternative locations for the crossing,
geophysical and geotechnical metocean surveys, and detailed
seismic analysis of faulting and the dynamics of seismic motion.
The pipeline is located in areas to avoid significant changes in
seafloor topography, areas of extreme current, and to avoid a
perpendicular alignment with the direction of the current.
Further, AGDC is working with PHMSA to meet federal standards of
burial depth at the east and west shore crossings, and to
address shallow hazards associated with shore crossings
including Arctic hazards such as ice and ice keels, and moderate
hazards such as keels, soil scour, and beach erosion.
Presentations on the design have been given to PHMSA, and AGDC
has received clarification on the requirements related to
onshore versus offshore pipelines. He said AGDC's design
criteria is extensive, using metocean data and multiyear
analyses under the guidelines of best environmental protection
practices, and the criteria considers moving boulders, anchors,
vessels, ice keels, seismic events, and seismic faulting. He
restated that Title 49, CFR Part 192, are minimum standards;
however, AGDC will use approximately 25 percent over minimum
standards for pipe wall thickness, along with a protective
coating of fusion bonded epoxy, further coated with 3.5 inches
of concrete. Dr. Meyer advised AGDC has site-specific and
general crossing analyses augmented with metocean data, which is
data such as the depth and velocity of currents and changing
topography on the seafloor that may affect the pipeline.
Further work with INTECSEA will be to review all the analyses to
ensure all of the design criteria is sufficient, and to refine
the analyses within the PHMSA and FERC review processes. He
further explained there are block valves located at each shore
crossing, and pads to service the block valves; AGDC has met all
of the minimum standards and all the Cook Inlet specific
standards. Dr. Meyer advised after [the design phase is
complete], AGDC will continue to work with PHMSA for the
operational part of design and to follow through with the
operation of the pipeline, particularly as to the monitoring of
the pipeline during operations. The pipeline is fully piggable
using pigs which travel through the pipeline to detect cracks,
corrosion, and changes in geometry and wall thickness, among
other factors.
1:42:40 PM
REPRESENTATIVE PARISH inquired as to the anticipated design life
of the pipeline.
DR. MEYER responded the desired design life is the same as the
length of the lease: 30 years. However, he pointed out the
Trans-Alaska Pipeline System (TAPS), after its initial design
life transpired, underwent a supplemental environmental impact
statement (EIS) and continues to operate. Generally, the life
of a well-designed, well-maintained pipeline is nearly
indefinite, depending on active operational monitoring and
maintenance. He opined with state oversight, Alaska LNG would
be very vigilant regarding the operational life of the pipeline.
REPRESENTATIVE PARISH asked how often the pipeline would be
pigged.
DR. MEYER said the pipeline would be pigged every year in its
early life to ensure there are no anomalies and to respond if
any are found; after some time, the frequency of in-line
inspections (ILIs) would be increased again to reveal late-life
anomalies, as is specified by code. He added that there would
be continuous leak-detection monitoring by the pipeline control
system that would shut the valves automatically in the event of
a leak, similar to oil pipeline systems.
REPRESENTATIVE PARISH asked for the pipeline's capacity.
MR. RICHARDS said the mainline pipeline is designed to transport
three billion feet cubic feet per day.
DR. MEYER added the project is a 42-inch pipeline operating at a
pressure of above 2,000 pounds per square inch (PSI), which is a
high-pressure pipeline. In further response to Representative
Parish, he explained at that pressure, natural gas is a dense
gas which would be liquified at the site of the proposed
liquefaction plant located on the Kenai Peninsula.
1:46:45 PM
CO-CHAIR TARR pointed out the existing natural gas pipelines in
Cook Inlet are six-inch diameter, and asked how AGDC compensates
when using baseline data from much smaller pipelines.
DR. MEYER said AGDC is using INTECSEA from Houston to bring
experience gleaned from large diameter pipelines in the [Gulf of
Mexico]. He acknowledged there is minimal experiential basis
for data in Alaska on large diameter pipelines, and INTECSEA has
a lot of experience with pipelines of this size. There is
experiential data in the Cook Inlet, such as the metocean data
design criteria. He related AGDC and Alaska LNG used local
contractors to develop ocean data and to record historical data
such as ice events in Cook Inlet.
CO-CHAIR TARR asked whether AGDC is required to build to a
certain magnitude of earthquake minimum standards based on
historical seismic activity.
DR. MEYER confirmed that AGDC must meet minimum federal
standards; however, federal standards are "not that specific,"
thus each project must develop its own standards for the
pipeline. For the onshore pipeline, AGDC researched the
probabilistic seismic hazard assessment, the TAPS standards, and
- due to seismic events in Interior Alaska - a more recent
valuation of seismic activities. Criteria were developed which
are subject to oversight and evaluation by FERC and PHMSA; both
agencies must agree that the results are the minimum standards
specifically for the Alaska LNG pipeline. This would also apply
to Cook Inlet, where AGDC reviewed standards such as faulting.
The faults in the bottom of Cook Inlet are very old and are not
considered active, however, north of Cook Inlet there are the
Lake Clark and Castle Mountain faults which are considered
potential hazards to the pipeline and which are addressed by
onshore design requirements. Dr. Meyer stressed the project
follows industry standards for events within the Holocene Epoch
- which covers about 10,000-15,000 years [up to the present] -
and if an active fault is found within that time period, the
data is included in the design criteria to allow for future
movement; for example, the [Denali Fault] was included in the
TAPS design criteria. He recalled during the most recent Denali
earthquake TAPS performed as designed, and was back in operation
within two days. Further, many of the same "designers" are
working on Alaska LNG, and are using the same fault crossing
criteria and methodology as was used for TAPS.
1:51:41 PM
REPRESENTATIVE TALERICO recalled seeing a section of pipe that
had been replaced in Cook Inlet that was smaller and very
different than the pipe described by Dr. Meyer for this project.
He observed the pipe planned for the project "is certainly much
more substantial than the 50-year-old infrastructure that we
have there ...."
DR. MEYER, although he did not have direct knowledge of the
existing pipe, affirmed that in the last half century advances
have been made in base metal technology and welding technology,
and even more importantly, [improvements have been made] in the
emphases on workers' qualifications, oversight, the evaluation
of construction practices, as well as construction and operator
evaluations that require participation from all parties. He
opined "things have changed quite a bit."
REPRESENTATIVE WESTLAKE returned attention to Hilcorp's natural
gas leak caused by a three- by ten-foot boulder, and asked
whether there is an "active season" when there is more movement
[on the seafloor in Cook Inlet].
DR. MEYER was unware of any patterns other than seasonal ice and
the diurnal pattern of the currents.
CO-CHAIR TARR inquired whether the speed of a response to an
incident is included in the overall plans.
DR. MEYER said the speed of the response [to an incident] has
not been evaluated at this time.
CO-CHAIR TARR expressed her understanding that at this time
block valves at shore crossings and [spill detection] sensors
[are in the plan] thus there are specific locations where the
pipeline could be shut down; undetermined at this time is once
[a spill] is contained, how long would transpire to the point of
repair.
DR. MEYER clarified that response to an initial venting of the
pipeline would be within minutes. He said his previous answer
was to the response to fixing the pipeline "anywhere within the
venting of the 27 miles between the block valves." He restated
AGDC has not evaluated how fast an operational repair team would
respond to an incident, but in the FERC filing there is
information as to how fast the pipeline system responds to an
alert of a venting.
1:56:22 PM
MR. RICHARDS added the design safety studies for the project
reviewed the interaction between [the pipeline] and ice, ice
keels, subseafloor boulder movement, and anchor drop and/or drag
from large ships, thus the design criteria reflects a 30 percent
increase in wall thickness of the pipe from 0.92 inch to 1.25
inch, as well as 3.5 inches of concrete coating. He said these
criteria will provide a suitable support to handle both geologic
and geotechnical types of impacts - as well as ship impacts on
the pipe - and is a very robust design.
DR. MEYER noted AGDC is also tasked by PHMSA to ensure the
pipeline is stable and to demonstrate as part of its offshore
regulatory requirements submitted by INTECSEA in its report;
however, a review of the INTECSEA report has not yet been
received from PHMSA as part of its regulatory oversight.
REPRESENTATIVE PARISH asked about the likelihood that a
significant break, requiring repairs to the pipeline, would
occur during the pipeline's 30-year design life.
DR. MEYER said AGDC feels that is very unlikely as AGDC is
exceeding the design standards; AGDC has amassed a vast amount
of data and experience through TAPS and through the North Slope
Point Thomson and Prudhoe Bay transmission lines. This
confidence is based not only on the pipeline design, but also on
the knowledge that modern gas pipelines today have a lot of
experience in monitoring, and in day-to-day operational
facility; in fact, if a problem is coming up along the pipeline
- which is possible - modern operational monitoring can meet and
safely prevent a major outage.
REPRESENTATIVE PARISH gave a scenario in which a tanker dropped
its anchor on the pipeline, causing a leak in late November or
early December, and asked how long it would take to repair.
DR. MEYER remarked:
I'm sorry, as I said earlier, I don't have the
information for response teams for that, for that
particular scenario, we just haven't gone that far yet
in our operational evaluation.
MR. RICHARDS pointed out plans for actual repairs need to be
factored into the operational component and have not been
identified yet, in terms of risk. Contingencies and mitigations
are a work in progress because AGDC has been working on
preliminary front-end engineering design (pre-FEED), and will
now continue into front-end engineering design (FEED), detailed
design, and operational evaluations on how to handle those types
of arrangements.
REPRESENTATIVE PARISH, noting that Hilcorp took approximately
four months to respond to and repair [a natural gas leak in Cook
Inlet], asked whether AGDC could respond more quickly.
DR. MEYER remarked:
With the caveat that I said earlier, we are looking at
experience, for example, in the North Sea as well the
possibility of contracting, contacting and contracting
deep-sea repair groups that would quickly mobilize to
Alaska. These are speculation, I don't want to put
this on ... as something we're adhering to right now
because we are trying to work those things out;
nevertheless, this is not a situation that is unheard
of around the world, and we are of course ... we would
employ best, best technology to, to respond.
2:04:27 PM
GENE THERRIAULT, director, government relations, AGDC; team
lead, Interior Energy Project, Alaska Industrial Development and
Export Authority, Department of Commerce, Community & Economic
Development, informed the committee he would distribute AGDC's
most recent semi-monthly update [document not provided]. He
directed attention to a press release issued by the U.S.
Department of Commerce that highlighted some of the agreement
between the U.S. administration and the People's Republic of
China, including an item expressing a greater desire for LNG
exports from the U.S. to China [document not provided].
Currently, AGDC president Keith Meyer is in China at a gas
conference presenting the Alaska LNG project, and meeting with
possible financiers and customers. Mr. Therriault then referred
to a recent letter from the Industrial Energy Consumers of
America to U.S. Secretary of Energy [Rick] Perry specifically
identifying Alaska's natural gas as being the first natural gas
that should be exported. Finally, Mr. Therriault noted that
previous attendees of the [Alaska LNG Summit held 3/1/17-3/6/17
in Girdwood, Alaska] are now engaged with AGDC on signing
confidentiality agreements in order to gain access to AGDC's
data, which he said shows "continued forward momentum, no
guarantee that our infrastructure will get built, but a lot of
positive things happening ...."
2:07:59 PM
REPRESENTATIVE PARISH asked for the minimum internal diameter of
a pipe that can be pigged.
DR. MEYER recalled the minimum is four inches; but he pointed
out the minimum continues to decrease with advances in
technology.
MS. RYAN, turning attention to North Slope infrastructure, said
there was an inner annulus mechanical integrity failure that
caused a release of crude oil and diesel fuel at wellhead 13,
drill pad number 2, owned by BP on the North Slope. The event
occurred on 3/30/17, and is in recovery mode. Also occurring
was spraying of oil outside of the wellhouse, and some leaking
of oil out of the wellhouse related to the inner annulus
failure. She said the oil was contained on the well pad and
there has not been a release of oil off the pad. [DEC] is
working with BP to clean up where possible, although because of
the infrastructure on the pad it is not unusual for DEC to allow
the company to leave some [oil] in place if there is a plan for
final clean up when the facility is closed.
2:10:51 PM
REPRESENTATIVE PARISH returned to [one of the aforementioned
natural gas pipeline leaks] and asked whether it was an eight-
inch pipeline that leaked from December [2016] through April
[2017].
MS. RYAN said the Hilcorp natural gas pipeline was eight-inch.
In further response to Representative Parish, she said she was
unsure when, but the gas pipeline and the companion oil pipeline
were pigged. She remarked:
It was tricky to pig it because of a valve that, you
know, these pigs not only have to fit through the
pipeline, they have to fit through all the valves and
there's a right-angle valve going up to the platform
leg that made it very difficult to get a pig that
would fit into that type of a pipeline. It is pretty
amazing how they've been advancing, in the
capabilities to pig [pipelines] today.
MS. RYAN offered to provide the exact date of when the pipeline
was pigged.
REPRESENTATIVE PARISH expressed his confusion about how pigging
a line provides high-quality data on wall thickness, bends, or
breaks, but the data needed to repair the leaking pipeline was
unclear. He asked how reliable the data is from pigging a line
in terms of anticipating problems.
MS. RYAN advised [the data] varies widely depending on the
apparatus used; some pigs are "smarter than other pigs." For
example, the pig used between the oil [pipeline] and the Bruce
platform just pushed the oil through; the term "pig" is a broad
term used for almost any type of device put in a pipeline.
Further, it is harder for a smaller pig to collect advanced
information. In response to Representative Parish, she said it
is possible to have a four-inch smart pig.
REPRESENTATIVE PARISH asked whether Hilcorp is routinely using
smart pigs in its pipeline.
MS. RYAN said Hilcorp was able to do so within the last six
months on its oil pipeline because of the angle of the valve.
How often a company can pig a pipeline varies. In further
response to Representative Parish, she said she was unsure of
Hilcorp's specific plans for the use of smart pigs, but Hilcorp
has announced that it plans to "step up" some of its monitoring.
There are other types of monitoring that Hilcorp does - such as
using sonar to evaluate the pipe from the outside - and other
ways to evaluate the integrity of a pipeline.
2:16:36 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 2:16 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| House Resources Pipeline Safety Supporting Documents 5.12.17.pdf |
HRES 5/12/2017 1:00:00 PM |
Pipeline Safety |