# 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 complet ions 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 a mount of variability due to the calculation methodology

, the extremely l imited emissions inventory

data bases , and the unique composition of gas in different geologic formations . Of particular c oncern was the need to use data bases which are not dedicated to this task, and therefor e 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 fi rst 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 opp ortunities 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 extre mes 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 p art 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

1for 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 reconfi gured 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 Mexi co Environment Department, Oil a nd 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 w ell 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 f or 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: T he O’Sullivan assumption that emissions increase over t he first nine days

over estimates 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 per iod 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 go ing to develop an accurate data base it would seem appropriate to require industry to report the exact duration of the fl owback period and we will come up with a more representative average number (as noted above) , and the number will likely be unique for each

2geological 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 re quires 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 i t 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 beli eve 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 es timate 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, a nd 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 hydraulic ally 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 hydraulicall y fractured because there is greater potential for increased recovery. Also, conventional well s that haven’t taken a dvantage of horizontal drilling logically would have higher rates of recompletions for both advanced drilling technology and hydraulic fra cturing 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 hy draulically 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

t hese technologies or processes are feasible. Some characteristics that should be considered in your comments are well pressure, gas content of flowback, gas to oil rat io (GOR) of the well, and access to infrastructure. If there are additional factors, plea se 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 flowi ng 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.”

3COMMENT: 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, t hus 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 exp ertise 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 fla re 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 ph ase 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

p ermitted 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 emissi on 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 c an bring their expertise to bear on the u nique 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 c ontrols 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 l ow 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

4bodies 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 th e 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 NM ED 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 co nclusions was

that the OCD data base was not user friendly fo r 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 regulation s and permits is to prevent waste, protect correlative rights, and to protect th e 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 th e 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 emissio ns from hydraulically frac tured 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 89,5 33 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 app roximately 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 compr ehensive data is being reported, but until that data is verifiable we won’t truly know what is out there. If the goal is to estab lish 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.

513. 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 as sociated 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 environmenta l 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 ha s 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, industr y 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 te chnologies 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. Plea se 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 in itial 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 infras tructure 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 effic ien cy 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 c an bring their expertise to bear on the unique circumstances in the field and adapt the technology.

615. 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 s hould 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 incenti ve 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

a t their June 4 th 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 w ith 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

exp anding 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 datab ase 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 BL M 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 su fficient 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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