# Attachment F

Hydr aulically Fractured Oil Wells

Steven Prince

Division of Natural Resources, Navajo Nation1. 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 inthis 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 isgreater. ”

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. Thisreduction 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 gasemissions 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 duringflowback, 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 CCDsand 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.