## Attachment P

Leaks

Curt T a ipale

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. 77 th 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 n ot 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 under stand and document. Although, the Average E mission Factor A pproach does have limitations in

sit uations where the emissions process is dynamic and variable

.

In Table 2

- 6, i t might be helpful to identify which s tates compris e the various regions as it may not be clear for states nearby other regions. For example, is New Mexico part of

Curtis Taipale Review

– Oil and Natural Gas Sector Leaks Page 1the 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 n ot
clear of the distinction between the se two categories.

Table 2

- 8

– Summary of Emissions from Leaks, indi cates 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, i t is misleading characterize leak rates on such a small sample size without at least indicating the total

number of wells in volved in the region

. If the population of Colorado wells is

considered , these 19 wells repre sent 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, transmissio n 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. Althoug h, 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.

Curtis Taipale Review

– Oil and Natural Gas Sector Leaks Page 2Perhaps 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 increasi ng backpressure on the upstream gas collection system. Consequently, p roducing 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 press ures 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 unit s 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 p ressure 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 opera tors in Colorado

are evaluating the potential use of this device.

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

Please d iscuss 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 a re 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 q uickly identified

.

Since the IR camera is so new, the total lifecycle cost s 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?

Curtis Taipale Review

– Oil and Natural Gas Sector Leaks Page 3Does the type of facility (e.g., well site versus gathering and boosting station) affect

wh ich leak detection technology is used?

I n 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

d etection programs in industry and how the costs and emission reductions achieved

v ary with different frequencies of revisit.

During the February 2014 Colorado Air Qua lity Control Commission Hearing on proposed changes to Regulation Number 7 “ C ontrol 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 com ment 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 ga in 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 d etecting 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 Qua lity Control Commission Hearing on proposed changes to Regulation Number 7 “ C ontrol 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

Curtis Taipale Review

– Oil and Natural Gas Sector Leaks Page 4than the repair of leaks for the majority of leaks. Some operators at the hearing did dispute Dr. McCabe’ s assertion, although no le ak 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 emission s 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 booke d 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 significa nt 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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– Oil and Natural Gas Sector Leaks Page 5