Attachment P

Leaks

Curt Taipale

Colorado Department of Public Health and Environment
Oil and Natural Gas Sector Leaks

5.0 CHARGE QUESTIONS FOR REVIEWERS

Reviewer: Curtis Taipale, E.I.T.

12538 W. 77th Place

Arvada, Colorado 80005

Home Phone: 303-420-5225

Home Email: cotaipale@msn.com

Work Email: curtis.taipale@state.co.us

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

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

Response: Yes, based on my knowledge of this subject, I think this paper appropriately 

and adequately characterizes pertinent oil and gas studies and the data sources for 

quantifying VOC and methane leaks.

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: On page 12, Table 2-2 lists a 90% confidence interval column; which 

displays a percentage number that may not be clear to all readers, particularly for 

persons without a background statistics. It may be more helpful to display the range of 

the data distribution along with the average. For example, if I understand Table 2-2 for 

Eastern US Heaters correctly, it appears that the 90% confidence interval for annual 

methane emissions is within 218%. Thus, 90 percent of the heater methane emissions 

distribution is between a negative 30.1 MT to 55.6 MT. Is this correct? I am not clear 

on what a negative number means. Is this an asymmetric distribution?

The method used for quantifying O&G emissions probably depends on the ultimate use 

of the information, which may depend on the available inventory budget, the level of 

accuracy needed and available time. If adequate financial resources are available, the 

EPA Correlation approach or the Unit Specific Correlation Approach would result in the 

best estimates of oil and gas emissions. Often emissions inventories are a compromise 

of available time, staff and financial resources. Probably, the most common method in 

use is the Average Emission Factor Approach as this is the easiest to understand and 

document. Although, the Average Emission Factor Approach does have limitations in 

situations where the emissions process is dynamic and variable.

In Table 2-6, it might be helpful to identify which states comprise the various regions as 

it may not be clear for states nearby other regions. For example, is New Mexico part of 

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the Rocky Mountain Region or the South West Region? The use of the term 

“associated” and “non-associated” gas wells in Table 2-6 should be defined as it is not 

clear of the distinction between these two categories.

Table 2-8 – Summary of Emissions from Leaks, indicates that 89% of the well sites in 

the Rocky Mountain Region have leaks detected. This is based on 19 well sites visited 

where 17 sites were identified with leaks. It is unclear how many states are represented 

in this statistic, but, Colorado alone has over 50,000 active wells statewide that are 

located in about four different production basins. Consequently, it is misleading 

characterize leak rates on such a small sample size without at least indicating the total 

number of wells involved in the region. If the population of Colorado wells is 

considered, these 19 wells represent less than 0.038%. Based on anecdotal IR camera 

inspection data from the Colorado Department of Public Health and Environment, Air 

Pollution Control Division, Oil and Gas Team, an 89% leak rate seems very high.

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?

Of these four sectors, transmission and storage typically have very similar natural gas 

compositions, so the EPA Correlation or Unit Specific Correlation Approaches may 

provide reasonable estimates of leak emissions for both of these two sectors. For 

production and processing sectors, there is too much variability in natural gas 

composition to allow for equal application of one particular emission estimating 

procedure.

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.

Ongoing or Planned Studies:

In Colorado, I am not aware of any planned studies specific to O&G leak detection. 

Although, a regional Colorado focused air quality study involving NOAA, NCAR, NASA, 

named FRAPPE is planned for July 2014.

Additional Studies:

I am not aware of other “leak” studies beyond what is listed in the O & G Sector Leaks 

document.

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.

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Perhaps this is somewhat unique to Colorado, but the rapid growth in O&G 

development has strained the natural gas pipeline infrastructure and the capabilities of 

compressor stations (at or upstream of gas plant) to push the excess gas production 

down the line, which has resulted in increasing backpressure on the upstream gas 

collection system. Consequently, producing wells must dump at a pressure higher than 

the line pressure to overcome the upstream line pressure (to get the gas to flow into the 

sales line) this results in increasing pressures at the three-phase separator 

(gas/oil/water) which can produce high pressure flow of liquids from the separator to the 

storage tank. For newer tanks with multiple stages of separation (vapor recovery units 

are used to route natural gas to the sales line), the hydrocarbon liquid pressures are 

stepped down to manageable levels, but many older storage tank designs have only 

one stage of separation, resulting in limited pressure reduction and increased 

opportunity for venting at the thief hatch and the pressure relief valve during the flashing 

events.

6. Did this paper capture the full range of technologies available to identify leaks at oil 

and natural gas facilities?

Another potential leak detection technology is the Remote Methane Leak Detector 

(RMLD), which is sold by Heath Consultants. This device is less expensive than a 

Forward Looking Infra-Red (FLIR) but is distance limited (around 100 feet from operator 

and the leak). The device uses Tunable Diode Laser Absorption Spectroscopy 

(TDLAS) to detect methane and can sense above 5 ppm at a distance of 0 to 50 feet 

and over 10 ppm at distances over 50 to 100 feet. Some O&G operators in Colorado 

are evaluating the potential use of this device.

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

Please discuss efficacy, cost and feasibility for various applications.

Until the introduction of the IR camera, most Method 21 inspections likely involved the 

use of a portable Photo Ionization Detector (PID) or Flame Ionization Detector (FID) 

analyzer, which are time consuming to operate and sometimes miss leaks depending 

on probe access and/or hover time over the leak area. The IR camera provides the 

advantage of relatively quick visual recognition of leaks and some sense of the 

magnitude of the leak, which is an advantage on well production facilities that typically 

have numerous components and process equipment spread over a large area. When 

an IR camera is used in conjunction with a PID or FID, leaks above a defined screening 

level can be relatively quickly identified.

Since the IR camera is so new, the total lifecycle costs are not well understood and 

maintenance costs can be a significant factor depending on the care of the operator. 

However, the long-term staff time savings afforded by quicker leak detection with the IR 

camera very likely offsets the high cost of the camera, training and maintenance.

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? 

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Does the type of facility (e.g., well site versus gathering and boosting station) affect 

which leak detection technology is used?

In Colorado, based on anecdotal discussions with O&G operators, FLIR cameras are 

generally preferred, but they are expensive and require extensive training along with 

proper care and maintenance. Some operators also use a PID/FID in conjunction with a 

FLIR camera.

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.

During the February 2014 Colorado Air Quality Control Commission Hearing on 

proposed changes to Regulation Number 7 “Control of Ozone Via Ozone Precursors 

and Control of Hydrocarbons Via Oil and Gas Emissions”, oil and gas representatives 

provided testimony about ongoing voluntary leak detection programs in Colorado. 

Annual leak detection inspections (at well production facilities with storage tank 

batteries) appeared to be the most common frequency mentioned among Colorado 

O&G producers. Very little detail on the costs and emission reductions associated with 

leak detection was provided, but producers did indicate that the first inspection identified 

the most leaks and subsequent inspections found a lesser number of leaks.

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.

The Air Pollution Control Division has discussed the capabilities of the mobile 

monitoring technology with EPA Region 8, and it appears to show great promise for 

quick general verification of regulatory compliance. There are some limitations on wind 

direction and motor vehicle access downwind of the source, but both operators and 

regulators could benefit from the use of this technology to gain a general sense of 

compliance without spending an hour on the site with an IR camera and/or PID/FID.

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.

During the February 2014 Colorado Air Quality Control Commission Hearing on 

proposed changes to Regulation Number 7 “Control of Ozone Via Ozone Precursors 

and Control of Hydrocarbons Via Oil and Gas Emissions”, Dr. David McCabe (with 

Clean Air Task Force) did present research associated with the costs of leak detection 

and repair on Canadian O&G operations that indicated detecting leaks is more costly 

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than the repair of leaks for the majority of leaks. Some operators at the hearing did 

dispute Dr. McCabe’s assertion, although no leak detection and repair data was shared 

with the Air Pollution Control Division. Other operators (with significant operations in 

Colorado) did generally agree that most leaks were cost effective to repair, with the 

exception of some leaks that involved shutting down equipment or pipeline 

infrastructure to repair the leak.

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?

This is a difficult question, as quantification of leaks is very challenging and can be 

costly depending on the level of accuracy desired. If the leak detection and repair 

(LDAR) program is associated with emission reductions booked in a State 

Implementation Plan (SIP), then the associated program reduction (assuming VOC) 

would be subject to some level of verification to assure that the booked reduction was 

reasonably correct. Past EPA studies indicate that the percent reduction associated 

with LDAR is tied to inspection frequency. If EPA is willing to accept these previous 

studies as adequate demonstration of LDAR emission reductions, then perhaps the 

need to further quantify emissions from leaks is unnecessary.

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?

I am not aware of any new innovative or emerging leak detection technologies beyond 

the question 6 discussion.

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