Attachment M

Leaks

Matt Harrison

URS Corporation
Comments on 

 Oil and Natural Gas Sector Leaks 

Draft dated April, 2014 

Submitted to: 

Carrie Richardson Fry 

RTI, International 

Submitted by: 

Matthew Harrison 

June 16, 2014 

Overview 

As requested, I have reviewed the draft white paper titled “Oil and Natural Gas Sector Leaks” 

prepared by the U.S. EPA Office of Air Quality Planning and Standards (OAQPS), dated April 

2014. My review is limited to my areas of experience. 

I have only been asked to comment upon this Leaks paper, however, the papers on Compressors 

and the paper on Pneumatic devices and the paper on Hydraulically fractured oil wells have 

significant overlap in the upstream production segment. 

This review document is grouped into two sections: responses to the charge questions for 

reviewers that appear in the white paper, and additional specific comments, organized by page 

number. 
Responses to Charge Questions

1. Did this paper appropriately characterize the different studies and data sources that quantify 

VOC and methane emissions from leaks in the oil and gas sector? 

Response: In general, the paper does an adequate job of summarizing the studies and sources of 

data. However, it summarizes each source independently, and does not do much intercomparison between all the studies. It would be useful to have comparisons and conclusions 

about the differences between all the sources. 

Natural gas is used as a surrogate for VOC and methane emissions as in almost all the cases, 

this is appropriate for traditional leak sources where it is the produced natural gas that is 

emitted. 

A primary issue in this reviewer’s opinion is an improper scope of this paper that defines 

“leaks” to include tank emissions such as flashing emissions, breathing emissions, and 

malfunctions of other equipment that result in emissions from tanks (such as gauging hatches left 

open, or stuck dump valves on separators that allow gas to blow through to a tank). These tank 

sources are extremely different from other traditional leak sources and should not be grouped 

together as “leaks”. 

Leaks from traditional sources come from sealed surfaces, such as flange gaskets, valve 

stem packing, screwed fittings, pressure relief valve seats, etc., and these traditional 

leak sources could be near zero if perfectly designed and maintained. That is not the 

case for tank emissions, which are a designed emission point of a completely different 

character. 

While some of the detection techniques that are discussed for leaks may be applicable to 

find and locate tank issues, it is erroneous for the paper to group tank sources with other 

leak sources simply by making the definition of “leak” broad enough to cover tank 

emissions. Either the title of the paper needs to be “Leaks and Tank Emissions”, or the 

subjects need to be split into separate documents. EPA already split out an important 

source, pneumatic devices, even though these pneumatic devices can be detected and 

measured by some of the same techniques used to address leaks. The rationale appears to 

be because the control techniques for pneumatics will be different than leak repairs. The 

same can be said for tank emissions. 

In fact, the paper states that emissions from improperly operating tanks controls are 

designated to be leaks, or leaks from tanks where the emissions are not exceeding the 

required state or federal control limits. These are not leaks, but defects in control 

systems, or inadequate design, or permitting issues. Only a portion of the tank emissions 

are called leaks by the paper, whereas any emission from a traditional sealed equipment 

source is a leak. This inconsistency needs to be remedied by treating tanks 

independently. Tanks can be an important source of emissions, and should be addressed 

by a white paper, but using appropriate context. 
The Greeley CO report stated that 72% of emissions measured were from storage tanks, 

but there was no mention in the white paper of the amount of that emission that would 

have been considered an exceedance and thus a “leak” 
2. Please comment on the approaches for quantifying emissions and on the emission factors 

used in the data sources discussed. Please comment on the national estimates of emissions and 

emission factors for equipment leaks presented in this paper. Please comment on the activity 

data used to calculate these emissions, both on the total national and regional equipment counts

Response: In some areas, the paper criticizes (or states limitations) of particular emission 

detection approaches, or measurement approaches. Limitations stated for the OGI really exist 

for other techniques as well. This white paper lists limitations for the OGI that are true, but are 

not differentiators. The OGI write up in 3.1.2 lists limitations cited such as “when the 

technology is used appropriately”, and can be affected “by high or variable wind conditions”, 

and “is dependent upon the training and expertise of the operator”. This is true, but is also true 

for many other techniques. The current write up appears to offer this as a unique limitation or 

consideration of the OGI, but it is not unique. 

The white paper lists the Acoustic Leak detector in 3.1.3, and cites limitation in URS/UT 2011 

for “through-valve leak detection device”. This is not the only citation available, as Subpart W 

allows this device for reporting as one option on compressors. Authors of the EPA “Leaks” 

white paper should note that the URS/UT 2011 citation source was re-written and a new final 

version was published without reference to any VPAC results. My personal experience with the 

through valve device has been that it has not offered verifiable results, especially where used in 

noisy, high vibration environments, such as near compressors. This seems especially true for the 

very large valves that are found downstream of production. However, most of these will likely be 

discussed in more detail in the compressor paper reviews. 

3. Are the emission estimating procedures and leak detection methods presented here equally 

applicable to both oil and gas production, processing, and transmission and storage sectors? 

Response: In general, these techniques are applicable to most sectors. Once you are dealing 

with the vapor phase of produced natural gas, then the pipes and packed fittings carrying or 

handling that gas can leak and can be detected using the same general array of measurement 

and detection techniques. 

The downwind techniques discussed in Section 3.1.4 may be more easily applicable to a single 

large site that is readily and easily differentiated from the background, such as a large gas 

processing plant, a large transmission and storage station. In those cases, there are often access 

roads around, upwind and downwind of a facility, and the emission signal is large. In upstream 

production, access is often much more limited, and the site is often remote, and a single well pad 

may not be large enough to differentiate as easily.

4. Are there ongoing or planned studies that will substantially improve the current 

understanding of VOC and methane emissions from leaks and available techniques for 

detecting those leaks? Please list the additional studies you are aware of. 
Response: I am not aware of any new techniques that are not already mentioned in the white 

paper. 

I am aware of other natural gas supply chain studies that are being conducted by a consortium 

of operating gas companies and the Environmental Defense Fund (EDF). These EDF instigated 

studies will show new measured results for traditional leaks at gas processing and gathering, 

and at Transmission and Storage. There will also be one on Distribution systems, but that is 

outside the scope of this “Leaks” white paper. My understanding is that these papers will be 

published later in 2014. EPA should make use of these results in the EPA white paper on 

“Leaks”. 

There are some existing studies on whole basin areas, such as the NOAA study that looked at 

airplane and tower measurements of the Denver Julesberg basin. There have been similar 

flyover studies of other basins. However, these studies have many limitations, and cannot 

separate out all the sources, such as pneumatics, tanks, compressors, etc from the leaks. Also 

they are highly dependent upon meteorology and the ability to estimate and remove other 

unrelated sources of emissions in the same area. 

As mentioned in the introduction, natural gas leaks are appropriately used as a surrogate for 

methane and VOC leaks from traditional leak sources. For non-tank related sources, that is an 

appropriate surrogate, especially since the operating companies usually have a gas speciation 

analysis on the contained stream. 

My experience with the commercially available HiFlow device is that it has some service factor 

issues. When operating, the device provides a reasonable quantification. However, it often 

requires maintenance. I am also aware of some new research by Conestoga Rovers & 

Associates (CRA) that may comment upon the effectiveness of the commercially available HiFlow Instrument under certain conditions of methane concentration in the inlet gas less than 85 

mol %. CRA has shared with me that they believe an issue may exist with the HiFlow device in 

these low methane circumstances. This low percent of methane occurs in upstream production 

and less so in midstream and further in the supply chain. Their work has not yet been published, 

and likely will require further research before being fully understood and tested. 

5. Are there types of wells sites, gathering and boosting stations, processing plants, and 

transmission and storage stations that are more prone to leaks than others? Some factors that 

could affect the potential for leaks are the number and types of equipment, the maintenance of 

that equipment, and the age of the equipment, as well as factors that relate to the local geology. 

Please discuss these factors and others that you believe to be important. 

Response: The University of Texas Methane report, Phase 1, did find regional differences existed 

in the upstream production data for equipment leak emissions. However the cause of these 

differences is not definitively known. There was no single variable (age, well type, geology, etc.) 

that had a strong correlation to leak rate. The study did not gather information on maintenance 

practices, such as DI&M nor LDAR. 
6. Did this paper capture the full range of technologies available to identify leaks at oil and 

natural gas facilities? 

Response: To my knowledge, yes. 

The industry has, of course, had sensory approaches (where a company operator hears or sees a 

leak) for as long as there has been an industry. These approaches are not standardized. 

I did think the 3.1.4 section should have developed the Picarro cavity ring down measurement 

method in detail, as that is in common use for downwind approaches. My understanding is that 

they now offer a new coupling of data handling and installation that produces a quantification of 

flux, though this likely needs to be vetted by many users. 

7. Please comment on the pros and cons of the different leak detection technologies. Please 

discuss efficacy, cost and feasibility for various applications. 

Response: I do not have any detailed data on leak detection technology costs that go beyond 

what is mentioned in this paper. I think it is clear that expense of the survey needs to be 

minimal, to keep a positive ROI for the entire leak detection and repair process. Therefore, 

though OGI is a good method for greatly reducing the manhours needed to screen a large 

number of components, a less expensive method of determining where to apply the OGI, rather 

than applying it to all components, would be beneficial. 

Since most of the sites in many recent studies had very low emissions, and a smaller fraction of 

sites had the large leakers, it is very important to minimize any costs associated with the initial 

screening approaches. 

8. Please comment on the prevalence of the use of the different leak detection technologies at oil 

and gas facilities. Which technologies are the most commonly used? Does the type of facility 

(e.g., well site versus gathering and boosting station) affect which leak detection technology is 

used? 

Response: The best respondents for this question would be the operating companies, rather than 

researchers, academia, or NGO’s. EPA appears to have only one operating company, 

Southwestern Energy, as an official peer reviewer for this paper. EPA may want to expand that 

in order to gather the best response to this question (and others as well). 

In my experience, OGI and HiFlow appear to be in voluntary use in many companies, in that the 

major oil and gas producers own the devices. However, the extent of the surveys for all 

company assets is not known to this reviewer. Downstream, in gas processing, transmission and 

storage, use the OGI commonly as part of required Subpart W reporting.

9. Please provide information on current frequencies of revisit of existing voluntary leak 

detection programs in industry and how the costs and emission reductions achieved vary with 

different frequencies of revisit. 
Response: I have no information on frequencies of voluntary leak detection programs and the 

effectiveness of any different frequencies. I do know some of the upstream companies with 

voluntary programs appear to have a goal of an annual frequency. Also, there would be 

expected diminishing returns by increasing frequencies; the largest leaks would likely be the 

ones found when a first-ever survey was done, and subsequent visits are likely to find fewer of 

the largest leaks. Therefore increasing frequency may not be cost effective. 

EPA should note that surveys more frequently than annual increase the cost of the surveys, but 

without further research, the effect on emission reductions is unknown. It is likely that a positive 

return annual LDAR program could be made to have a negative ROI simply by increasing the 

survey frequency to a level of diminishing returns.

10. Please comment on the potential for using ambient/mobile monitoring technologies in 

conjunction with OGI technology. This would be a two-phase approach where the 

ambient/mobile monitoring technology is used to detect the presence of a leak and the OGI 

technology is used to identify the leaking component. Please discuss efficacy, cost and 

feasibility. 

Response: There are many difficulties with ambient/mobile monitoring, including calculating 

emissions from concentration and atmospheric modelling. A major difficulty with 

ambient/mobile monitoring for screening is determining what is an acceptable baseline. A 

mobile monitoring would require a threshold, wherein a site above this threshold would then be 

inspected by OGI. However, the threshold should depend upon many things, such as the size of 

the facility. A 10 well facility would be expected to have more emissions than a single well 

facility, and a different single well facility with high liquids production may have higher tank 

flash emissions than the previous single well site. However, downwind measurement crews 

usually have little to no information about the equipment and production at a site. The practical 

application of an ambient/mobile monitoring threshold may prevent its use as a screening tool. 

If this EPA whitepaper continues to focus on tanks, then perhaps the permitted site emissions, 

that included emissions from tanks, could potentially be used as a threshold. However, a 

downwind snapshot may still be made over insufficient time duration to get an actual daily 

average. Tank emission may vary over time with the variation in liquid flow from a well, with 

cycle of separator dumps to the tan (when flash occurs), and other factors. A measurement at a 

particular moment might be a poor representation of the annual average. 

11. Please comment on the cost of detecting a leak when compared to the cost to repair a leak. 

Multiple studies described in this paper suggest that detecting leaks is far more costly than 

repairing leaks and, due to generally low costs of repair and the subsequent product recovery, 

it is almost always economical to repair leaks once they are found. Please comment on this 

overall conclusion. 

Response: It makes sense that it would almost always be economical to repair a leak once found, 

so long as the repair can be made without affecting the normal operation of the site. However, 

where shut downs are required for repairs, the cost of lost production can drastically affect the 

cost of repair. 
The white paper does comment, and cites other papers that comment on the fact that the cost of 

survey is very important and must be minimized to make any repair program cost effective. 

12. If the conclusion is correct that it is almost always economical to repair leaks once they are 

found, then how important is the quantification of emissions from leaks when implementing a 

program to detect and repair leaks? 

Response: If the assumption is that all found leaks are repaired, then quantification is likely not 

needed. 

Quantification is needed for certain other things, such as National Emissions Inventories. 

However, quantification for the purposes of National Emissions Inventories can be determined 

from sampling of a subset of operations across the US in broader studies, rather than by 

requiring each site to quantify each leak. In the case of national inventories, it may be more 

valuable to know general emissions end results of a program where every found leak is repaired, 

so that the emission per component are known for programs with LDAR, and as a baseline, 

measurements could also be made for programs with no LDAR requirements at all. These 

emissions could be determined by industry studies that sample various operations across the US, 

rather than by emissions required to be measured for every single found leak by every operator, 

every time. 

If there were to be a future LDAR regulation, then quantification might be an allowed option. If 

there were such an option, such quantification might allow an owner/operator to decide which 

leaks to repair, or to prioritize the repairs. There are other parts of the supply chain, such as 

Distribution, just downstream of the scope of this white paper, where decades of Public Utility 

Commission practices recognize that certain small leaks do not require repair for safety nor for 

gas loss reasons. They recognize the cost of repairs can be high, and Distribution companies 

are allowed to grade their leaks in Class 1, 2 , and 3, with grade 3 leaks being monitored but not 

mandatorily repaired. Since the white paper recognizes that there is a skewed distribution of 

leaks (i.e. 80% of the leaks caused by 20% of the leakers), then it makes sense that the most cost 

effective repairs are the largest leakers. 

This philosophy, suggested in the question, also assumes that all repairs cost the same, which is 

not always the case. Some repairs can be made easily and on line, some require a shutdown, but 

only of one piece of equipment for which there is a spare, and some might require shutdown of 

the facility. These have differing costs. 

It depends whether the cost of survey already included the cost of HiFlow quantification.

13. Please comment on the state of innovation in leak detection technologies. Are there new 

technologies under development that are not discussed in this paper? Are there significant 

advancements being made in the technologies that are not described in this paper? 

Response: I am not aware of new leak detection technologies, but the amount of activity in the 

natural gas supply chain has brought recent analysis (such as the Picarro cavity ring down 
device), and efforts such as research and recent technology development challenges by EDF may 

lead to other innovations.

 
Specific Editorial Comments and Questions 

Page 2: the third paragraph states “the projected groth is primarily led by.....” The sources 

mention only gas development plays, and should also mention oil plays, which is driving most 

drilling now. 

Page 9: define “Unit-specific” when the term is used. 

Page 16: “the GHGRP covers a subset of national emissions...” The paper should cite the 

percent coverage EPA expected for oil and gas. I recall that was covered in preamble and 

technical support documents and was >85%. Cite the best number available. It is too 

undefined as printed. 

Page 17: first 2 paragraphs cite “emission factors” in the Subpart W regulation. Summarize 

the source of those factors. 

Page 18: The top of the page mentions the NEMS regions that are only cited as NEMS 

regiona in the bottom of the page. Make the citation when first introduced, please. 

Page 29: first full paragraph: “components that were identified in the surveys”. This is a 

confusing statement. Was there a larger population of unidentified components? Or does this 

mean simply “all of the components surveyed” 

Page 29: Same paragraph “(Vented emissions are not considered leaks for the purposes of this 

paper).” Does “this” refer to the whitepaper or to the CL, 2013 study? Also, hopefully you 

have a final version that can now be cited. 

Page 31: Section 2.10 (IICF paper). I believe there is some published API analysis and 

constructive criticism of this paper that should be reviewed by EPA. 

Page 36; Define “mean repair life” 

Page 39: Section 3.1.2. Spell out Infrared (IR) 

Page 41: First sentence under OGI ends with “quantifying the emissions is difficult.” This 

should say “is not currently possible.” After all, you later state there is no way to do it. 

Page 42: define or footnote “Normally Pressured Lance”