Attachment C

Hydraulically Fractured Oil Wells

Ned Jerabek

New Mexico Environmental Department
OIL AND NATURAL GAS SECTOR HYDRAULICALLY FRACTURED OIL WELL 

COMPLETIONS AND ASSOCIATED GAS DURING ONGOING PRODUCTION

7.0 CHARGE QUESTIONS FOR REVIEWERS 

1. Please comment on the national estimates and per well estimates of methane and VOC emissions 

from hydraulically fractured oil well completions presented in this paper. Are there factors that 

influence emissions from hydraulically fractured oil well completions that were not discussed in this 

paper? 

COMMENT: National well estimates and per well estimates of methane and VOC emissions, as 

represented in the paper, from hydraulically fractured oil well completions have a significant amount 

of variability due to the calculation methodology, the extremely limited emissions inventory 

databases, and the unique composition of gas in different geologic formations. Of particular concern 

was the need to use databases which are not dedicated to this task, and therefore requires 

extrapolation based on reasonable assumptions. Given the lack of actual measurement of emissions 

during well completions and subsequent reporting that would be required in a permitting action and 

thus verifiable, the analysis is credible as a first step, establishing the fact that there are significant 

methane and VOC emissions from well completions. Clearly before draft regulation can be proposed 

the focus needs to be on developing an accurate emissions inventory representative of the different 

geologic formations and well completion dynamics (event duration, pressure, GOR, etc.). After 

several interviews with the New Mexico Environment Department (NMED), Air Quality Bureau, 

GHG Emission Inventory personnel it was very heartening to see the GHG emission inventory has 

improved dramatically in the past year. Calculation methodologies still need to be standardized when 

direct measurement isn’t used, but at least there is discussion and approval of proposed alternative 

methods. The emission inventory should be further verified in the same manner as the CIRES/NOAA 

study in Northeastern Colorado during May 2012, and, as in this case, when discrepancies are 

identified opportunities are created to establish more accurate calculation methods. 

I don’t know that there were unaccounted factors that influence emissions, so much as we likely 

don’t fully understand the full impact of the considered factors and how they likely vary in different 

formations and temperature. For example, the brutal temperature extremes in North Dakota’s Bakken 

formation are not nearly as big an issue in the Permian Basin, and that is going to have a significant 

effect on how equipment operates and potential for retrofit controls.

2. Most available information on national and per well estimates of emissions is on uncontrolled 

emissions. What information is available for emissions, or what methods can be used to estimate net 

emissions from uncontrolled emissions data, at a national and/or at a per well level? 

COMMENT: As mentioned above the CIRES/NOAA study could be used to estimate net emissions 

after correlating it to uncontrolled emissions data, but you would have to back out emission 

reductions due to controls. Perhaps the emission reductions that are reported as part of the EPA Gas 

Star Program should be made mandatory and integrated into the GHGRP. And at the same time you 

would be verifying the accuracy of the reported reductions. I think back to the days when I worked 

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for Phelps Dodge Douglas Reduction Works and we literally had SO2 monitors all over the Sulfur 

Springs valley so we knew what the ambient SO2 concentration was on a real time basis and 

correlated that to real time meteorology and expected near term meteorological changes. Production 

was then reconfigured to make sure we didn’t violate SO2 ambient standards. I mention this because 

it is an example of the investment industry will make if they conclude it will take the uncertainty out 

of production and decisions are based on factual data. Most everyone wants to do the right thing, we 

just need to give them a workable framework that’s based on good science and accurate data.

3. Are further sources of information available on VOC or methane emissions from hydraulically 

fractured oil well completions beyond those described in this paper? 

COMMENT: I am not aware of other sources of information on VOC or methane emissions 

from hydraulically fractured oil well completions with the exception of the report issued 

December 31, 2007 by the New Mexico Environment Department, Oil and Gas Greenhouse Gas 

Emissions Reductions.

4. Please comment on the various approaches to estimating completion emissions from hydraulically 

fractured oil wells in this paper. 

 Is it appropriate to estimate average uncontrolled oil well completion emissions by using the 

annual average daily gas production during the first year and multiplying that value by the duration 

of the average flowback period? 

COMMENT: It is not appropriate, because oil well completion events are not a steady state 

operation. Emissions during the flowback period increase, probably relative to the increase in 

developing pressure, but unlikely at a linear rate. Multiplying by the flow back period is certainly 

correct but we don’t seem to have a very good number for that either.

 Is it appropriate to estimate average uncontrolled oil well completion emissions using “Initial Gas 

Production,” as reported in DI Desktop, and multiplying by the flowback period?

COMMENT: This likely gets closer as the “3 days of initial gas production” would logically be more 

representative of peak production during the flowback period. Then multiplying by the actual 

flowback period should give you a conservative estimate of emissions with a reasonable safety 

factor.

 Is it appropriate to estimate average uncontrolled oil well completion emissions by increasing 

emissions linearly over the first nine days until the peak rate is reached (normally estimated using the 

production during the first month converted to a daily rate of production)?

COMMENT: The O’Sullivan assumption that emissions increase over the first nine days 

overestimates the length of the flowback period, and as stated above it is very unlikely to be linear. 

The industry feedback I’m getting indicates that the flowback period is likely to average closer to 3 

days (see notes at end of comments regarding meeting with New Mexico Oil and Gas Association).

 Is the use of a 3-day or 7-day flowback period for hydraulically fractured oil wells appropriate? 

COMMENT: If we are going to develop an accurate database it would seem appropriate to require 

industry to report the exact duration of the flowback period and we will come up with a more 

representative average number (as noted above), and the number will likely be unique for each 

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geological formation. We could then compare the resulting calculations to the original assumptions

and better understand the true magnitude of emissions.

5. Please discuss other methodologies or data sources that you believe would be appropriate for 

estimating hydraulically fractured oil well completion emissions.

COMMENT: The New Mexico Taxation and Revenue Department collects taxes and royalties on oil 

and gas production and leases, and for this purpose requires reporting of annual production by well. 

The Department also collects the natural gas processors tax, and requires reporting from processors 

for this purpose. The implication here is that industry already has detailed production records by well 

and it would not be overly burdensome to manipulate the data for the purposes of estimating 

hydraulically fractured oil well completion emissions, including the length of the flowback period.

6. Please comment on the methodologies and data sources that you believe would be appropriate to 

estimate the rate of recompletions of hydraulically fractured oil wells. Can data on recompletions be 

used that does not differentiate between conventional oil wells and hydraulically fractured oil wells 

be reasonably used to estimate this rate? For example, in the GHG Inventory, a workover rate of 

6.5% is applied to all oil wells to estimate the number of workovers in a given year, and in the

ERG\ECR analysis above a rate of 0.5% is developed based on both wells with and without hydraulic 

fracturing. Would these rates apply to hydraulically fractured oil wells? For hydraulically fractured 

gas wells, the GHG Inventory uses a refracture rate of 1%. Would this rate be appropriate for 

hydraulically fractured oil wells? 

COMMENT: It seems obvious that data on recompletions that does not differentiate between 

conventional oil wells and hydraulically fractured oil wells would not yield accurate results for 

estimating the rate of recompletions of hydraulically fractured oil wells because once an oil well is 

hydraulically fractured you have now recovered a significant amount of the resource available and 

logically there will be diminishing returns. Therefore, there will always be a higher rate of 

recompletions on conventional oil wells that have never been hydraulically fractured because there is 

greater potential for increased recovery. Also, conventional wells that haven’t taken advantage of 

horizontal drilling logically would have higher rates of recompletions for both advanced drilling 

technology and hydraulic fracturing technology. If we conclude that the hydraulically fractured gas 

well refracture rate of 1% is reliable, because it is based on the GHG inventory reporting, then this 

rate should be appropriate for hydraulically fractured oil wells because the basic physics and geology 

for resource recovery are similar.

7. Please comment on the feasibility of the use of RECs or completion combustion devices during 

hydraulically fractured oil well completion operations. Please be specific to the types of wells where 

these technologies or processes are feasible. Some characteristics that should be considered in your 

comments are well pressure, gas content of flowback, gas to oil ratio (GOR) of the well, and access 

to infrastructure. If there are additional factors, please discuss those. For example, the Colorado Oil 

and Gas Conservation Commission requires RECs only on “oil and gas wells where reservoir 

pressure, formation productivity and wellbore conditions are likely to enable the well to be capable 

of naturally flowing hydrocarbon gas in flammable or greater concentrations at a stabilized rate in 

excess of five hundred (500) MCFD to the surface against an induced surface backpressure of five 

hundred (500) psig or sales line pressure, whichever is greater.”

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COMMENT: The feasibility of completion combustion devices during hydraulically fractured oil 

well completion operations appears to be a forgone conclusion as that is already the standard 

approach in the Permian Basin. As the pipeline infrastructure is extended, thus allowing Industry to 

use REC technology as a revenue source, many of the obstacles like well pressure will be overcome. 

Industry deals with all these problems in the downstream gathering system and it is reasonable to 

require industry to bring that expertise and knowledge to bear at the well head.

8. Please comment on the costs for the use of RECs or completion combustion devices to control 

emissions from hydraulically fractured oil well completions. 

COMMENT: Installing a flare is simpler, cheaper, quicker; it is a proven technology that requires

less maintenance, and so it is the logical choice, at least until profits dictate otherwise. A carbon tax 

would certainly enhance the implementation of REC’s. As the inventory of dehydrators, 3 phase 

separators and flares in the field increases there naturally will be opportunities to redeploy this 

equipment once the pipeline infrastructure is expanded in the field. Downstream compressor stations 

that already have dehydration and flare capabilities should be able to pick up some of this demand 

and free up equipment installed at the well-head for use in new well development. Therefore, the 

amortized cost of this equipment should steadily decrease as field development increases.

9. Please comment on the emission reductions that RECs and completion combustion devices 

achieve when used to control emissions from hydraulically fractured oil well completions.

COMMENT: Industry has a vast amount of experience operating this kind of equipment in existing 

permitted facilities, and those permits require reduction efficiencies generally in the 95 to 98 percent 

efficiency range. Those reduction efficiencies are usually the basis for the permitted emission limits 

and therefore verifiable via the equipment emission testing. While it may be true that hydraulically 

fractured oil wells do not produce in the same manner as a steady-state permitted operation, it is 

reasonable that the oil and gas industry can bring their expertise to bear on the unique circumstances 

at the well head and adapt the technology. Given the variable emission rates during oil well 

completion operations emission reduction efficiencies reasonably would be less, but section 5.1.2 

indicates that REC of 90% control is reasonable based on the reports from Natural Gas Star Partners. 

This appears to be a good baseline.

10. Please comment on the prevalence of the use of RECs or completion combustion devices during 

hydraulically fractured oil well completion and recompletion operations. Are you aware of any data 

sources that would enable estimating the prevalence of these technologies nationally? 

COMMENT: After talking to industry environmental managers it is my understanding that 

combustion devices, i.e. flares, are by far the most prevalent controls being used. The reasons given 

were the same as stated on page 23, first paragraph, “lack of pipeline infrastructure, lack of capacity 

and lack of compression infrastructure”. I also suspect that the fact that flares are relatively quick and 

easy to install with low maintenance requirements is a significant factor. In New Mexico, as I suspect 

in most states, no single state agency regulates all sectors of the oil and gas industry. More or less 

sector-specific regulatory authority and technical expertise is divided among different rule-making 

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bodies and administrative agencies. Three agencies administer regulations pertaining to the sources 

of oil and gas emissions of methane into the atmosphere. However, their statutory mandates and 

regulatory concerns with these sources and their pursuant methane emissions have not been related to 

methane’s role as a greenhouse gas. The Public Regulation Commission regulates the natural gas 

distribution sector, the NMED Air Quality Bureau regulates air pollution under the statutory 

authority of the New Mexico Air Quality Control Act, and the Oil Conservation Division (OCD) of 

the Energy, Minerals and Natural Resources Department enforces rules of the Oil Conservation 

Commission. These Agencies have limited communication and only recently did the NMED Air 

Quality Bureau invite Oil Conservation Division staff to present their data and general understanding

of the hydraulic fracturing boom in the oil and gas fields of New Mexico. One of the conclusions was 

that the OCD database was not user friendly for the express purpose of determining emissions from 

oil and gas well completions, or the type of emission control device. The OCD issues permits for 

drilling, development and production of oil and natural gas. The purpose of the OCD-administered 

regulations and permits is to prevent waste, protect correlative rights, and to protect the resources of 

oil, gas, potash and geothermal water. Clearly they have a lot of relevant and valuable data, but it 

would take considerable resources to gather and interpret the data.

11. Did the EPA correctly identify all the available technologies for reducing gas emissions from 

hydraulically fractured oil well completions or are there others? 

COMMENT: My research indicates the EPA identified all reasonable and pragmatic technologies 

for reducing gas emissions from hydraulically fractured oil well completions.

12. Please comment on estimates of associated gas emissions in this paper, and on other available 

information that would enable estimation of associated gas emissions from hydraulically fractured oil 

wells at the national and the well-level.

COMMENT: Page 22, second paragraph, states “For 2012, 171 facilities reported associated gas 

vented and flared emissions to the GHGRP. Total reported methane emissions were 89,533 MT.” 

Fourth paragraph, same page, states 266,000 Mcf per day was flared as per the Flaring Up report for 

North Dakota’s Bakken formation. For the Bakken formation Table 3-5, page 16 lists 1,183 Mcf

gas/event, and 18.0 MT CH4/event, all uncontrolled. You therefore can derive an emission factor of 

0.0152 MT CH4/Mcf. Now apply this emission factor to the above data: 0.0152 MT CH4/Mcf 

(266,000 Mcf/day) = 4042 MT CH4/day. If the flaring efficiency is approximately 94% then you are 

left with 242.5 MT CH4/day. Multiply that by 365 days/year and you get 88,512 MT CH4/year. That 

is roughly equal to the entire amount of methane reported in the GHGRP for 2012, 89,533 MT CH4, 

and this is strictly from the Bakken formation. My point is it isn’t difficult to reinterpret the data and 

come up with very different results. In the case above one concludes the GHGRP is grossly under 

accounting the total methane emissions. I agree, we had to start somewhere and work with the data at 

hand. The good news is when I compare that to the EPA FLIGHT tool it clearly indicates much more 

accurate and comprehensive data is being reported, but until that data is verifiable we won’t truly 

know what is out there. If the goal is to establish control requirements that implies determining where 

to set the applicability thresholds and to do that it seems to me you really need an accounting tool 

that is credible and verifiable, and therefore able to withstand legal challenge.

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13. Please comment on availability of pipeline infrastructure in hydraulically fractured oil 

formations. Do all tight oil plays (e.g., the Permian Basin and the Denver-Julesberg Basin) have a 

similar lack of infrastructure that results in the flaring or venting of associated gas?

COMMENT: It appears clear that rapid expansion of oil and gas resources due to hydraulic 

fracturing has quickly overwhelmed the existing infrastructure’s ability to handle the less profitable 

associated gas. Recently a NMED manager returning from a trip to the Permian Basin remarked “it 

looks like a birthday cake out there at night” referring to the flaring. Because of the H2S sour gas 

content venting is rarely an option in the Permian Basin of southeast New Mexico. The problem is 

considerably larger than just pipeline infrastructure, in that even if the pipelines could be rapidly put 

into place the natural gas processing plants don’t have enough capacity to handle the increased gas 

flow. Industry environmental managers have also stated that getting “Right of Way” approval to 

expand pipelines from State and BLM officials is a slow process and we might think about what it 

would take to expedite that process. In the last three years the NMED Air Quality Bureau has had 

something on the order of 4 or 5 pre-application meetings with companies proposing to build new 

natural gas processing plants for the sole purpose of meeting the demand of new gas produced from 

hydraulic fracturing and development of new fields. The Bureau has also been notified as a Title V 

“affected program” by Texas in response to operating permit applications to expand existing natural 

gas processing plants within 50 kilometers of the border. So, industry is responding to the increase in 

natural gas production, but it will likely take a few years to bring new and expanded processing 

capabilities on line. I would expect the expansion of the pipeline infrastructure to be on the same 

schedule.

14. Did the EPA correctly identify all the available technologies for reducing associated gas 

emissions from hydraulically fractured oil wells or are there others? Please comment on the 

costs of these technologies when used for controlling associated gas emissions from hydraulically 

fractured oil wells. Please comment on the emissions reductions achieved when these technologies 

are used for controlling associated gas emissions from hydraulically fractured oil wells. 

COMMENT: My research indicates the EPA identified all reasonable and pragmatic technologies 

for reducing associated gas emissions from hydraulically fractured oil wells. As more and more 

dehydrators and 3 phase separators are installed in the field the availability and proximity of the 

equipment inventory in the field will further mitigate the initial cost of investment. Given the 

projected expansion and development of oil and gas formations it logically follows that the 

equipment used for REC’s could be redeployed numerous times as the pipeline infrastructure 

gradually, albeit lagging behind, is extended into the remote areas lacking this infrastructure. 

Industry has a vast amount of experience operating this kind of equipment in existing permitted 

facilities, and those permits require reduction efficiencies generally in the 95 to 98 percent efficiency 

range. Those reduction efficiencies are usually the basis for the permitted emission limits and 

therefore verifiable via the equipment emission testing. While it may be true that hydraulically 

fractured oil wells do not produce in the same manner as a steady-state permitted operation it is 

reasonable that the oil and gas industry can bring their expertise to bear on the unique circumstances 

in the field and adapt the technology.

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15. Are there ongoing or planned studies that will substantially improve the current understanding of 

VOC and methane emissions from hydraulically fractured oil well completions and associated gas 

and available options for increased product recovery and emission reductions? 

COMMENT: As mentioned above the CIRES/NOAA study should provide very interesting insight 

into our current understanding and scope of methane emissions. For those formations that produce 

rich gas with heavier hydrocarbons than can be harvested as Natural Gas Liquids (NGLs) industry 

has ample profit incentive to develop small scale well head treatment technologies. It seems likely 

that less profitable lean gas will be a much lower priority to develop recovery options that result in 

emissions reduction because liquefied natural gas (LNG) is a much more energy intensive and costly 

process as compared to NGL recovery; perhaps with the exception of reinjection to enhance oil 

recovery.

NOTES: 

The New Mexico Oil and Gas Association invited me to discuss many of the above referenced issues 

at their June 4th monthly meeting. Some of their comments conflict with my comments above, but I 

think it best to let it all stand on its own merit. Following are comments from that meeting:

• Defining the flowback period is much more complex. If Fracking with nitrogen the flowback 

gas will be unsaleable for 30 days or more. Furthermore when venting to flare, combustion 

has to be supported by the addition of propane.

• Gaining Right of Way is a patch work affair in the Permian Basin and a large obstacle to 

expanding the pipeline infrastructure to the well heads. The BLM is particularly slow and it is 

their understanding that the BLM office in Carlsbad is about to lose more staff which will 

aggravate the problem.

• Nonproducing wells should be entered in the database as zero, not deleted from the database.

• Much of the data is out of date and doesn’t currently reflect the state of technology in the oil 

and gas industry.

• Many of the members of the New Mexico Oil and Gas Association would like to provide 

comment on the White Papers, but just don’t have time given their workload.

• An Industry/EPA Task Force needs to be set up to QA/QC the data bases, and participate in 

technical analysis and its application to development of new regulations.

• Work on streamlining the BLM clearances and the flaring issues will go away.

• New Mexico Environment Department, Air Quality Bureau is developing a flaring 

regulation, but no progress is being made. This is needed and should be expedited.

• For temporary well head flares ten feet is sufficient for sweet gas, 20 feet for sour gas. There 

are no 40 foot Quad O flares.

• Flaring regulation should be based on 90 days or 90 tons of carbon emissions, whichever 

comes first.

• Temporary flaring at well head should be a permit by rule.

• BLM proposed flaring rule will be based on their authority to require sources to fully utilize 

the resources, which may conflict with state rule.

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