Laura K. Perry
Coordinator – Air Quality
ConocoPhillips Alaska
700 G Street
Anchorage AK 99501
Phone 907-265-6937

December 4, 2015
Environmental Protection Agency
Attention Docket No. EPA-HQ-OAR-2010-0505
1200 Pennsylvania Ave. NW
Washington D.C. 20406
Subject:

Submitted via US Mail, e-mail, and the
Federal eRulemaking Portal

Docket ID No. EPA-HQ-OAR-2010-0505; Comments on Oil and Natural Gas
Sector: Emission Standards for New and Modified Sources (Federal Register, Vol.
80, No. 181, September 18, 2015)

Dear Sir or Madam:
ConocoPhillips Alaska, Inc. (CPAI) is pleased to submit these comments on the above referenced
proposed new source performance standards (40 CFR 60, Subpart OOOOa). CPAI produces oil
from both the Kuparuk and Alpine oil fields and has equity interest in the Prudhoe Bay oil field.
As such, we are the largest producer of oil in Alaska so have a very significant interest in the
proposed OOOOa rule.
CPAI supports the comments submitted by the American Petroleum Institute (API). CPAI submits
this separate letter to focus on issues specific to the Arctic conditions that affect North Slope oil
field operations. The EPA has acknowledged in prior rulemaking processes that Leak Detection
and Repair (LDAR) requirements should not be applied to the North Slope because the balance of
feasibility, benefit, and cost is different under Arctic conditions. For similar reasons CPAI asks
EPA to exempt North Slope operations from the LDAR requirements of the proposed OOOOa
rule.
The reasons for an exemption are set forth fully in the attached detailed comments, and can be
summarized as follows:
•
•

•

•

The technology required does not always reliably work finding methane leaks under the prevailing
conditions on the North Slope.
The prescriptive schedule for methane leak detection and repairs of the LDAR requirements in the
proposed OOOOa imposes a greater burden on the North Slope compared to non-Arctic locations.
The extreme and lengthy winter weather conditions and remote nature of the North Slope along
with the logistical difficulties presented by both make the leak detection schedules and repair
timelines frequently untenable.
The shutdowns that may be required to fix some leaks could result in millions of dollars per day
in lost gross revenue, which would deprive the State of Alaska from its main revenue source and
dramatically affect other stakeholders.
All above-ground piping and valves in oil production service are required by the State of Alaska
to be visually inspected at least once per month for leaks. This means that personnel inspect

 equipment for leaks from the wellhead all the way into the processing facilities for leaks. Piping
containing production fluids, whether liquid or gas, is all above ground on the North Slope, except
for the unflanged piping that must cross roads and pads.
© Alaska North Slope processing facilities are manned 24 hours per day, 7 days per week, and 365
days per year. Alaska North Slope drill sites are visited daily, weather permitting. Practices are in
place to detect and repair leaks at processing facilities and drill sites.
© Because most of the flanged oil production equipment is enclosed and in containment, methane
leaks cannot be generally tolerated on the North Slope.
In short, the goals of a methane leak detection and repair program are not going unaddressed on

the North Slope as evidenced by the leak detection and repair program already in place that is
adapted to the North Slope conditions. These prescriptive rules are not consistent with that existing

program, however, and CPAI believes that if the existing program was substituted with the leak
detection and repair program in the proposed OOOOa rules, it would be a step backward. CPATs
detailed comments, along with background information, are enclosed with this letter. Our
comments include requests for clarification of some phrases used by EPA in the proposed rule.

Thank you for this opportunity to comment and please do not hesitate to call me if you have any
questions or need more information to support our comments.

Respectfully,

Coordinator - Air Quality
907-265-6937

 Docket ID No. EPA-HQ-OAR-2010-0505
Comments on Oil and Natural Gas Sector: Emission Standards for New and Modified Sources
(Federal Register, Vol. 80, No. 181, September 18, 2015)
ConocoPhillips Alaska, Inc. (CPAI)
Alaska’s North Slope – its Climate and Meteorological Impacts on Logistics
The North Slope of Alaska is the area between the Brooks Range and the Arctic Ocean. It is
entirely above the Arctic Circle and is located about 400 miles north of the closest major population
center, Fairbanks. There is one road that connects this population center to some North Slope oil
fields while other North Slope oil fields have no road connection at all. Thus, the primary access
to the North Slope for workers is by air. These road and air connections to our major support
centers are characterized by frequent interruptions due to spring breakup related flooding and
weather-grounded flights, the former of which can last for weeks. 1 As such, schedule adaptation
is a frequent necessity, project delays are not uncommon, and personnel have learned to be resilient
in their transportation expectations. During the periods when they are physically on the North
Slope, workers face additional challenges.
The climate of the North Slope is harsh, marked by persistently low wintertime temperatures,
consistent winds, and a sun that remains below the horizon for about two full months per year.
North Slope-specific weather data, collected just south of the Alpine field, shows that for about
five months of the year, the average temperature is below 0°F (Figure 1).

Figure 1: 2012-2014 Average Hourly Temperature (°F), Nuiqsut, AK
1

See, for example, the interruption that occurred in early 2015 due to Dalton Highway flooding:
http://gov.alaska.gov/Walker/press-room/full-press-release.html?pr=7185

1

 Related, snow is typically on the ground on the North Slope from about September to June each
year. 2 This is important because, as can be seen in Figure 2, winds in excess of 10 miles per hour
occur more than 40% of the year causing periods of blowing snow and reduced visibility. This can
frequently result in what is referred to on the North Slope as “phase” conditions, 3 where the oil
industry implements ground travel restrictions for the purpose of safety. Phase conditions can
occur on more than 30% of the days in the months October to May.

Figure 2: Nuiqsut Wind Speed Histograms; note wind speeds in excess of 10 mph for 11,596 hours of
the 26,304 hours covering the three-year period

From the above, it is relatively easy to see that the North Slope winters are indeed harsh. The
shoulder seasons also have their challenges given the intense pressure gradients seen in the fall
with the onset of winter 4 and the aforementioned issues associated with spring breakup such as the
Dalton Highway flooding. But the short summer season also has its challenges.
Figure 3 below 5 shows the amount of time the main airport into the North Slope oil fields,
Deadhorse (PASC), was subject to various flight rules based on meteorological conditions between
1973 and 2007. Of note, during the months June through September, the airport was subject to low
instrumental flight rules (LIFR) or very low instrumental flight rules (VLIFR) slightly more than
20% of the time. VLIFR accounted for about 1/3rd to 1/4th that amount of time. LIFR applies to
conditions where cloud ceilings are less than 1,000 feet and visibility is less than 1 mile. VLIFR
applies to conditions where cloud ceilings are less than 500 feet and visibility is less than ½ mile.
2

Shulski, M., Wendler, G.; 2007, The Climate of Alaska, University of Alaska Press, page 74
In Phase I conditions (visibility < 500 feet, snowdrifts forming), only essential travel may occur. In Phase
II conditions (visibility <250 feet, snowdrifts narrow the traffic lanes to less than the width of two pickup
trucks), travel may occur only in convoys. In Phase III conditions (visibility <100 feet, snowdrifts
impenetrable by pickups), travel is generally prohibited except for emergencies.
4 Shulski, et al, pages 103-105
5 From MVFR/IFR Climatology for Selected Alaska TAF Sites available at:
http://www.atmos.albany.edu/student/ccastell/research/MVFR-IFR-Climatology-Report.pdf
3

2

 The Federal Aviation Administration identifies VLIFR conditions as a criterion for closing
airports. 6

Figure 3: Deadhorse Airport Flight Categories, 1973-2007

For comparison, Figure 4 is the corresponding plot for the Ted Stevens Anchorage International
Airport (PANC). Note that the flight challenges are so different for the two that they are plotted
on different scales.

Figure 4: Anchorage Airport Flight Categories, 1973-2004
6

Ibid., page 5

3

 To summarize, climatic and meteorological conditions on Alaska’s North Slope are such that, no
matter the season, the best made plans have to be flexible in their scheduling and that delays in
achieving goals are quite often inevitable. In 2013 and 2014, North Slope flights using Boeing 737
jet aircraft were delayed an average of more than once per week. Flights to the satellite fields using
smaller aircraft from the Deadhorse hub are similarly challenged. Each delay has a “daisy-chain”
effect on subsequent flights so schedule recovery can take time. The weather on the North Slope
and the effect it has on logistics must be taken into account when crafting rules with tight schedules
for compliance. In addition, as explained elsewhere in these comments, the North Slope weather
can also force limitations on the technology associated with an LDAR program.
Oil Production on the North Slope of Alaska
Figure 5 is a conceptual overview of North Slope operations. There are multiple drill sites which
are connected via multi-phase pipelines (containing oil, water, and gas) to a central processing
facility. Separation of the produced fluids occurs at the central processing facility, not at the drill
site. Figure 6, a map depicting the layout of the drill sites that feed into Kuparuk’s Central
Processing Facility No. 3 (CPF3), is typical of North Slope oil production operations. Figures 7
and 8 are aerial photographs of CPF2 and a typical drill site.

Figure 5: Simplified diagram of North Slope oil production facility

A drill site (of which six are depicted above), consists of the wellheads (anywhere from 10 to more
than 70) which are enclosed in small well houses, manifold buildings where each individual well’s
production is commingled into a common pipe flowing from the gravel pad toward the processing
facility, sometimes a production heater to prevent produced water from freezing, metering, and
4

 tanks that store materials that are not produced fluids (e.g., methanol for well freeze protect 7). In
Kuparuk and Alpine, there are more than 50 drill sites containing over 1,700 wells. 8 Except when
wells are being completed or having maintenance performed on them, there is no active fluid
separation at the drill sites. During normal production operations, all fluids separation occurs at
the processing facilities.
At the centralized processing facilities, produced sales quality crude oil is not stored as one might
find in the tank batteries common in the Lower 48 states. The produced sales quality oil is piped
directly from the processing facility to Pump Station 1, the beginning of the TransAlaska Pipeline
System (TAPS), where the oil is piped to Valdez, AK for shipment. There are large divert oil tanks
(approximately 55,000 bbl each) at some facilities. These divert tanks are used for emergency
situations (e.g. when a pump station unexpectedly shuts down and cannot accept oil). During such
a time, the produced oil will accumulate in these tanks and they will be emptied back into the
pipeline when normal operations resume. A small amount of oil (approximately 10% or less by
volume) may occupy these tanks at any given time, however this oil is cycled out of the tank either
on a weekly or monthly basis, depending on the tank. These tanks are equipped with a vapor
recovery system.

Figure 6: Map of Kuparuk’s CPF3

The processing facilities receive all the produced fluids from a drill site, separate them into their
water, gas, and oil phases, and route the gases and water back to the reservoirs, using some of the
gas as fuel for the facility equipment (i.e., the gas is not processed for sale). The processing
7 For wells that are not actively producing, methanol is a material that is injected inside the well bore to
keep the downhole fluids from coming into the permafrost zone (where produced water could freeze
inside the pipe). This is referred to as “freeze protect” and the pumps used for freeze protect operations
are electric pumps; no pneumatic pumps are used.
8 There are many more drill sites and wells, of course, in the Prudhoe Bay oil field and other units on the
North Slope.

5

 facilities are fully manned around the clock, are almost entirely enclosed, and consist of the
separators, the equipment necessary to route fluids to their destination, such as pump, turbinedriven compressors, and notably, power generation equipment. The processing facilities, working
together, produce only sales quality crude oil, are remote from civilian infrastructure, and must be
self-contained. Moreover, because they are all enclosed and manned, liquid and gas leaks cannot
be generally tolerated so the facilities (and manifold buildings at the drill sites) contain gas
detection equipment that alert operators to leaks so they may be expeditiously repaired. When
conditions allow, drill site operators make daily trips to the drill sites to, among other tasks, inspect
for leaks so they may also be expeditiously repaired.

Divert Tanks

Figure 7: Typical Central Processing Facility

6

 Figure 8: Typical Drill Site Overview

Employees work in shifts on the North Slope, generally two weeks on and two weeks off. They
are transported to the facilities via air and are provided room and board while at the facilities.
The production of crude oil in the state of Alaska is regulated by the Oil and Other Hazardous
Substances Pollution Control provisions found at 18 AAC 75. 9 For oil production facilities, these
regulations require, among other things, monthly checks for leaks:
18 AAC 75.080. Requirements for facility oil piping. (a) The owner or operator of an oil
terminal, crude oil transmission pipeline, exploration facility, or production facility shall
ensure that all facility oil piping associated with that facility meets the requirements of this
section.
***
(n) The owner or operator of aboveground facility oil piping and valves must ensure
that the piping and valves are
(1) visually checked for leaks or damage during routine operations or at least
monthly, and
(2) appropriately protected from damage by vehicles.

9

Title 18 of the Alaska Administrative Code, Chapter 75:
https://dec.alaska.gov/commish/regulations/pdfs/18%20AAC%2075.pdf

7

 Since all production fluid piping on the North Slope is above ground (except for the welded pipe
under road and pad crossings) and that produced gas and oil piping are routed together, this means
all the piping, whether in produced fluid or gas service, is checked for leaks at least monthly.
Different operators have different schedules for adhering to this requirement, with some doing it
even more frequently than monthly, but it is safe to say that these checks are conducted much more
frequently than the semi-annual checks required by the proposed OOOOa. When methane leaks
are detected during these checks, workers are instructed to generate work orders so they may be
investigated and repaired. Leak detection and repair are an integral part of North Slope oil
production operations.
Technical, Logistical, and Commercial Infeasibility of Applying the Proposed Scheduled
LDAR Requirements to the North Slope of Alaska
There are four major issues with applying the proposed and scheduled LDAR requirements on
Alaska’s North Slope:
•
•
•
•

Optical gas imaging (OGI) cameras are specified to work in temperatures above -4°F;
Performing methane leak detection at each of our 50+ drill sites and 1,700+ wells on a rigid
schedule will be challenged by meteorological conditions;
Completing repairs of methane leaks in the time allotted by the proposed rule will be at
times infeasible, setting us up for situations of non-compliance; and
The commercial impacts associated with repairing leaks that require more than 15 days to
fix could be excessively burdensome.

According to FLIR Systems, Inc., the optical gas imaging cameras’ operating temperature range
is from -4°F to 122°F. This manufacturer does not offer any gas imaging cameras designed to
operate in temperatures below -4°F. From Figure 1, it is seen that temperatures below -4°F are
obviously a common occurrence on the North Slope, rendering wintertime LDAR activities
technically infeasible since not all enclosures are heated, and most above-ground piping is
exposed. In addition, our experience indicates that attempts to perform methane leak detections
activities using the OGI technology in wind speeds greater than 8 miles per hour produces
unreliable results.
Further, Figures 1 and 2 (temperature and wind plots), and the fact that there is typically snow on
the ground from September to June, show that the proposed methane leak detection schedules can
only reliably be carried out in the summer months. The new rule should not impose a methane leak
detection schedule that is known to be impractical to meet.
The proposed repair deadline of 15 days also poses a problem. Though a large inventory of spare
parts is maintained on the North Slope, it is neither practical nor possible to keep on hand all the
parts that may conceivably be needed to repair a future methane leak. Some repairs might thus
require parts to be purchased and shipped in from outside the North Slope. Figure 3, the plot of
Deadhorse airport flight rule categories, shows that getting the parts on a reliable schedule (i.e.,
within 15 days), no matter the time of year, is not a given. We acknowledge that the proposed rule
allows more time to repair the methane leak if repairing it with 15 days is “technically infeasible
or unsafe” but are not certain that flight delays would fit into this extension allowance. Thus, again,
we foresee difficulty in complying with the rule as proposed.

8

 In some cases, methane leaks on North Slope facilities would inarguably be “technically infeasible
or unsafe” to repair in 15 days, in which case the proposed repair deadline of six months or the
next scheduled shutdown, whichever is sooner, would apply. But even that extended deadline
imposes a disproportionate burden on the North Slope, especially for minor leaks, and would in
some cases cause more emissions than it would prevent. Some leaks may require a shutdown to
repair and, if a shutdown is not already scheduled within six months of detecting the leak, then a
previously unscheduled process shutdown will have to occur. 10 A process shutdown is a time
consuming, labor intensive, expensive, and broadly impacting endeavor. For example: pipelines
must be de-inventoried and surveyed, gas will be flared, diesel engines will have to be started to
provide utilities (because the facilities normally run off natural gas separated from the oil), gasfired equipment will have to be shut down and subsequently started up, and wells will be shut in
(ranges from 250 to 535 wells depending on the facility). The emissions associated with this gas
flaring, diesel use, and equipment shutdown-startup cycle are much greater than the emissions
resulting from methane leaks. We do not believe this scenario is consistent with the proposed rule’s
goals.
Moreover, royalties and taxes on North Slope oil production is the major revenue stream to the
State of Alaska, which would be significantly and adversely affected by any previously
unscheduled shutdowns for the purpose of repairing methane leaks, even minor ones. CPAI
produces sales quality crude oil from its production facilities, and production volume varies by
facility. If a processing facility was to engage in a previously unplanned shutdown to perform
fugitive emission leak repair, lost production revenue would range from a gross of $2.6 million to
$5.2 million per day (based on a crude oil price of $50/bbl) depending on which facility was shut
down. If a drill site must be shut down to repair a leak, the gross lost revenue could be in the
hundreds of thousands of dollars per day. We do not believe economic impacts this large are either
contemplated by or warranted by the proposed OOOOa.
In sum, oil production on the North Slope is distinct from production elsewhere in the United
States. The facilities are inter-connected and flow to a single pipeline that routes all the produced
crude oil from the North Slope to market, there are dozens of wells at each drill site, most of the
facilities are enclosed and manned around the clock, and the operations occur in the context of
logistical and climatological challenges that are unique. Given this, as well as the aggressive leak
detection and repair programs already in place on the North Slope, we request that the prescriptive
LDAR requirements found in the proposed OOOOa rule be made explicitly not applicable to
Alaskan North Slope oil production facilities and drill sites. Compliance with the rule is
impractical and unduly costly, and there are other measures in the place on the North Slope that
would make any benefit of complying with the proposed rule requirements either negative or small.

10 ConocoPhillips performs planned shutdowns of its facilities every three years. These are intricately
planned activities that require up to a year of planning along with coordination with the many other
facilities that feed into the oil pipeline leaving the North Slope. For example, an unplanned shutdown of
CPF2 could cause production and environmental impacts at the Alpine facility which routes its production
through CPF2.

9

 Prior EPA Decisions around Applying LDAR Requirements to North Slope Facilities
EPA has previously recognized the difficulties in applying prescriptive LDAR requirements to the
facilities on the North Slope of Alaska. Because of these difficulties, exemptions from prescriptive
LDAR requirements appear in the following rules:
•
•
•

•

40 CFR 60, Subparts GGG and GGGa: Standards of Performance for Equipment Leaks
of VOC on Petroleum Refineries
40 CFR 60, Subpart KKK: Standards of Performance for Equipment Leaks of VOC
from Onshore Natural Gas Processing Plants
40 CFR 60, Subpart OOOO: Standards of Performance for Crude Oil and Natural Gas
Production, Transmission, and Distribution (exemption only for Natural Gas
Processing Plants)
40 CFR 63, Subpart HH: National Emission Standards for Hazardous Air Pollutants
from Oil and Natural Gas Production Facilities (exemption only for Natural Gas
Processing Plants)

The basis for the exemptions was first seen in the preamble for GGG. EPA wrote: 11
EPA has studied the commenter's concerns and acknowledges that there are several
unique aspects to refining in the North Slope of Alaska. Accordingly, EPA concluded
that the costs to comply with the routine leak detection and repair requirements of the
proposed standards may be unreasonable. These operations incur higher labor,
administrative, and support costs associated with leak detection and repair programs
because: (1) They are located at great distances from major population centers, (2)
they must necessarily deal with the long-term, extremely low temperatures of the
arctic, and consequently (3) they must provide extraordinary services for plant
personnel. These unique aspects make the cost of routine leak detection and repair
unreasonable (Document Number IV-B-15). Therefore, EPA has decided that
refineries in the North Slope of Alaska are exempt from the routine leak detection and
repair requirements of the standards.
This view is evidently carried forward into the proposed OOOOa rule since Alaskan North Slope
Natural Gas Processing Plants are exempted at §60.5401a(e) from the same LDAR provisions the
above listed rules require. Since the climatological and logistical conditions that exist at the Natural
Gas Processing Plants are the same as those at the surrounding drill sites and production facilities,
the drill sites and production facilities should also be exempted from the prescriptive monitoring
requirements and repair schedules.

11

49 FR 22598, May 30, 1984

10

 Language that Requires Clarification
1.

The well site exemption for fugitive emissions found in §60.5365a(i)(2) states:
“A well site that only contains one or more wellheads is not an affected facility”

In the proposed rule preamble at 80 FR 56611, EPA states this definition is meant to exclude from
LDAR requirements “well sites that contain only wellheads.” We are not certain any such
producing well site exists on the Alaskan North Slope. Rather, because of the remote nature of our
operations, the need to freeze protect, and the number of wells we may have on a pad, there is
nearly always more than just wellheads at a well site. But, with few exceptions, there is also no
processing or production fluid storage that takes place at a well site. EPA makes clear on the same
page of the preamble that they want to include in the LDAR requirements those well sites that
contain “ancillary equipment such as storage vessels, closed vent systems, control devices,
compressors, separators, and pneumatic controllers.” In ConocoPhillips’ Alaska North Slope
operations, there is only one such site. The rest of our drill sites contain, along with the wellheads,
mainly electrical modules, manifold buildings, line heaters, and small methanol tanks for freeze
protection.
It appears EPA, in the §60.5365a(i)(2) exclusion, wants to ensure no well sites that engage in any
processing or storage of production fluids enjoy the exemption. If our understanding of this is
correct, we suggest the exclusion language would be much more clear if worded as follows:
“A well site that only contains one or more wellheads or that does not process (i.e.,
separate) or store any sales quality produced fluids is not an affected facility.”
2.
It is not entirely clear how broadly EPA intends the phrase “compressor station site” to be
applied but, as defined in proposed OOOOa, it could be applied in a manner that could cause oil
production facilities to be included (these compress gas for reinjection into reservoirs). We don’t
think this is the intent. As such, we propose the definition be amended to make it consistent with
the definition of “onshore natural gas transmission” found at 40 CFR 98.230(a)(4) as follows:
“Compressor station site means any permanent facility whose primary function is to
compress and move gas at increased pressure via a combination of one or more
compressors that move natural gas at increased pressure out of a production field, out
of a natural gas processing plant, or other transmission compressors through
transmission pipelines to natural gas distribution pipelines, LNG storage facilities, or
into underground storage. through gathering or transmission pipelines, or into or out
of storage. This includes, but is not limited to, gathering and boosting stations, and
transmission compressor stations.”
Similarly, use of phrases like “gathering and boosting station” and “transmission compressor
station” without definition will cause uneven application of the rules.
3.
The definition of “well site” is confusing as it could be read to include production facility
pads that contain no producing wells. We do not believe EPA intends this outcome but the matter
could be clarified by including in the definition language that explicitly states production pads that
contain no producing wells are not considered well sites.
11