Attachment F

Hydraulically Fractured Oil Wells

Steven Prince

Division of Natural Resources, Navajo Nation
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? 

The national and per well estimates seem extremely high and I believe the 

reason why the estimation methods yield such high numbers can be explained. 

In my extensive experience during completion of hundreds of coal bed methane 

wells which were hydraulically fractured, the flame above the flarestack during 

flowback was surprisingly small, indicating smaller than expected amounts of 

VOCs and methane escaping from the flowback fluids. The gases at depth are 

under pressure and likely in a liquid state prior to hydraulic fracturing. The 

hydraulic fracturing fluid is under extreme pressure as the fracturing occurs and 

since the fluids will likely be moving in the laminar flow regime, the mixing of 

the fracturing fluids with the liquified formation fluids (including methane and 

VOCs) will be minimal. So during flowback, the volume of entrained gases 

emitted from the fracturing fluids will be far less than during production of the 

oil and/or gas following fracturing and flowback. Since these numbers are 

estimated from gas-oil-ratios during production, they will be much higher than 

what would have actually been measured during flowback.

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?

To my knowledge, very little directly helpful information exists except for that 

found in the UT-Austin study. One suggestion is to have an extremely capable 

reservoir engineer do an in-depth study of the fluid dynamics of interactions 

between fracturing fluids and reservoir fluids as the hydraulic fracture treatment 

takes place. A clear understanding of what is truly happening in-situ and at 

depth would shed much light on how much of the formations fluid returns with 

the flowback fluid. Another suggestion would to be to enter into an agreement 

with a drilling operator to place measurement equipment on actual wells and 

measure the actual emissions specifically from the flowback fluids in much the 

same way the measurements were taken in the UT-Austin study. Then the data 

could be examined and possibly correlated to existing uncontrolled emissions 

data from previous wells in the area to get a feel for how closely it matches the 

assumptions of the paper. Then revise the paper’s estimates based on the new, 

more reliable 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? 

A recent search of online resources showed that there are indeed additional 

sources of information available on VOC and methane emissions, however the 

majority of those came from unscientific and/or unreliable sources. Studies 

such as the one conducted by UT-Austin would be of the most value, since they 

took direct measurements and conducted the study in a very professional and 

science-based manner. Hopefully, any additional studies will be conducted in 
this way.

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? 

I believe this method to be inherently inaccurate, due in part to the fact that the 

flowback fluid does not have the same characteristics as the reservoir fluids. 

The amount of gas entrained into the fracturing fluid under downhole 

conditions and in such a short time may likely be much less than either the gas 

in the formation or the gas dissolved in the oil in the formation.

• 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? 

I believe this method to also be inherently inaccurate for the same reason as 

above. The “Initial Gas Production” reported by DI Desktop refers to the 

actual formation fluid being produced, not the fracturing fluid which had only 

limited, short-term contact with the formation fluid and very limited 

opportunity to absorb methane and other VOCs from the formation fluid. I 

believe that this method would be the least appropriate of the three suggested 

here.

• 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)? 

This method seems more appropriate than the other two methods, since 

flowback fluids would contain little gas to begin with and would progressively 

increase in entrained gas content, but not necessarily to the level of the gas 

contained in the formation fluids produced during the actual production phase 

of the well. I believe that this method would be the most appropriate of the 

three suggested here.

• Is the use of a 3-day or 7-day flowback period for hydraulically fractured 

oil wells appropriate? 

The answer to this question would depend entirely on the amount of fracturing 

fluid pumped and would also depend on reservoir characteristics controlling the 

fluid flowback rates. Since the goal of flowback is to remove all of the 

fracturing fluids from the formation, a 3-day or 7-day flowback period would 

likely leave a substantial volume of fracturing fluid remaining in the reservoir 

which would continue to flow back through the separation equipment and may 

continue to bring proppant which could possibly create obstructions within the 

separation equipment.
5. Please discuss other methodologies or data sources that you believe would be 

appropriate for estimating hydraulically fractured oil well completion emissions. 

Employing appropriate measurement equipment on current drilling and 

hydraulic fracturing operations would be the only appropriate and accurate way 

to measure the emissions. Then the results of those studies could be 

extrapolated back to existing data from wells in similar areas to test the 

accuracy of the assumptions made in the paper. I believe that in principle, this 

is the same approach employed by the UT-Austin study.

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? 

The only reliable method would be to examine actual historical data, comparing 

conditions to determine causes for the need for recompletion. Frequency of 

recompletions of conventional wells could not be correlated to hydraulically 

fractured wells because there are completely different forces at work in each 

type of well. For example, closure of the fractures over time may occur in a 

fractured well, which would not occur in a conventional well and under some 

circumstances the rock mechanics of the reservoir in some wells could be a 

cause for more frequent recompletions in fractured wells.

Recompletions performed to correct skin effect that develops over time would 

likely correlate between conventional and fractured wells except that the 

surface area over which the skin effect applies could be much greater in a 

fractured well. The GHG Inventory’s refracture rate of 1% for gas wells would 

likely be comparable for oil wells.

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.”

Back in the 1990s when I was drilling and fracturing coal bed methane wells, 

every well that I fractured employed the use of a CCD or flare stack 

successfully and inexpensively. We used the CCD throughout the drilling 

process as well. We drilled exclusively with air until we reached the production 

zone, at which time we would circulate mud in the hole while we drilled 

through the production zone to facilitate the logging of the well and determine 

where we would fracture the well. Each potential productive zone would be 

isolated for fracturing.

As far as I understand the purpose for the COGCC rule, it is to prevent backflashing (igniting the produced gas/fluid in the well bore prior to exiting the 

system at the pit). The pressures and flow rates set by COGCC seem 

somewhat arbitrary and if they are, they may be adjustable to some degree. 

Certain additional precautions would need to be in place beyond the COGCC 

rule for certain types of wells. For example, our igniter would only be active as 

long as the air compressor was on and the pressure at the blooey line exit was 

sufficient to prevent back-flashing.

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

devices to control emissions from hydraulically fractured oil well completions. 

RECs are much more expensive than CCDs, at least two orders of magnitude 

higher. However, an REC may be entirely inappropriate for use during the 

flowback phase due to its inability to deal with the potential for proppant in the 

flowback fluid. The flowback phase is the only phase of completion (except for 

the actual hydraulic fracturing itself) which differentiates a hydraulically 

fractured well completion from a conventional completion regarding emissions. 

RECs would tend to be even more expensive if multiple units are required 

simultaneously due to multiple simultaneous well completions. Appropriate 

sizing of the RECs to accommodate the needs of each individual well would be 

a factor in increasing the cost of the RECs. This is where a combination of an 

REC with a CCD might help reduce the costs. 

In many cases, a mobile, trailer mounted REC could be scheduled 

appropriately to prevent the incredible delays and skyrocketing costs that are 

likely to occur if RECs become mandatory for most completions. A 

combination of a CCD and an REC might also be a good way to prevent 

excessive back pressure on the formation during testing if necessary as in a coal 

bed methane application in the event that RECs become mandatory. 

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. 

The CCDs that I used years ago achieved very high emission reduction rates. 

This is supported by Chart 3.6 on P. 18 which shows that essentially the same 

percentage of emission reduction is achieved by both a CCD and an REC. This 
reduction in emissions would be achieved regardless of whether the oil well 

were hydraulically fractured or not, since the use of either an REC or a CCD 

would mainly just be during the production phase and only a CCD would 

typically be used during flowback due to the high likelihood of proppant 

plugging the REC.

In appropriate applications, using an REC would give the added advantage of 

recapturing emissions that would otherwise be wasted by using a CCD—as 

long as this could be done in a way to prevent causing the well to become 

uneconomic or marginally economic and therefore not drilled. 

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? 

One-hundred percent of the wells I have hydraulically fractured used a CCD 

use during completion and recompletion operations. We had a mobile REC 

unit which would be used during completion and recompletion if appropriate 

and if available. We never used the REC unit during flowback following 

hydraulic fracturing due to the high likelihood that we would see excessive 

proppant load in the flowback fluid. Our REC was not designed to handle 

proppant in the production stream which can impair the equipment and can 

require excessive downtime to clean out the equipment at a very critical stage 

of the operation. It may be possible to add a hydrocyclone to an REC unit to 

remove proppant from the flow stream in certain types of operations. 

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

emissions from hydraulically fractured oil well completions or are there others? 

It appears that EPA has done a great job of identifying most of the available 

technologies for reducing gas emissions from the flow stream of oil well 

completions after flowback of the fracturing fluid. During the hydraulic 

fracturing flowback phase, the only viable technology is a CCD due to the high 

likelihood of proppant returning in the flowback fluid stream. There may be 

other technologies available of which I am unaware.

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 welllevel. 

There was no specific methodology presented in the paper to estimate the 

amount of gas in the flowback fluid. The wording of this question seems to 

imply that the emissions of associated gas during production of the oil might be 

different for hydraulically fractured wells than for conventional wells. The fact 

that the well has been hydraulically fractured would have little or no bearing on 

how much associated gas would be emitted should a gas pipeline not be 

available. Estimation of the gas emissions in this case has been done 

appropriately for the production phase of the well’s life. Using GOR is entirely 

appropriate to estimate the emissions during production, just not during 
flowback, which is the only phase affected by hydraulic fracturing.

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? 

It stands to reason that pipeline infrastructure will be minimal to nonexistent for 

any exploration play unless it serendipitously is found near an established 

producing field where pipelines have not yet been abandoned. A good example 

is the case of two adjacent fields on the Navajo Nation in San Juan County, 

NM. One was prematurely abandoned a few years ago and the other is in the 

process of being rehabilitated in order to be sold. Although there is pipeline 

infrastructure remaining in the first field, it would take considerable effort and 

expense to relocate buried pipelines which are now abandoned, but it may be 

worth the effort when the field is inevitably leased anew for Mancos Shale 

(tight shale oil and gas) exploration. The other field, has not been abandoned 

but the oil wells are in “stripper” status. When this field is purchased and 

explored for Mancos Shale potential, the pipeline infrastructure will already be 

in place and can easily be used during completions to take the gas to market 

instead of being vented or flared.

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. 

The EPA has identified the most obvious technologies available for all wells for 

reducing associated gas emissions during the production phase of the well’s 

life, whether the well was hydraulically fractured or not. Quantification of gas 

emissions during the flowback phase on a hydraulically fractured well with 

associated gas is important and may be found to be different than that for a gas 

well depending on the fluid dynamics of the interactions between the fracturing 

fluids and the well fluids in this type of well. An in-depth scientific study 

conducted by highly qualified reservoir engineers would be extremely helpful 

in determining how best to approach the method of reducing gas emissions 

during the flowback phase in all types of wells which have been hydraulically 

fractured. 

From the UT-Austin study, it appears that emissions reductions are virtually the 

same with the use of CCDs and RECs, but the costs for RECs could be two 

orders of magnitude higher. On-site generation of electrical power seems to be 

a very good alternative if it could be successfully implemented and the cost 

would likely be on the same order of magnitude as RECs. Reinjection of the 

produced gas and NGL recovery are both very promising alternatives but would 

likely come at a much higher cost than RECs. Each of these alternates to CCDs 

and RECs would likely achieve equal or better emissions reductions to CCDs 
and RECs.

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? 

The UT-Austin study and this white paper seem to have generated a great deal 

of interest and based on the extensive online discussions, I believe it likely that 

additional studies will be planned and executed. Future studies will likely be 

more valuable and informative if they improve upon the basic principles upon 

which the UT-Austin study was executed.