Attachment B

Hydraulically Fractured Oil Wells

Joe Cardenas

XTO Energy, Inc.
Answers to Charge Questions:

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 estimates of methane and VOC’s from hydraulically fractured oil wells do 

not seem to be reasonable or accurate for several reasons. First, the estimates used for all the 

major studies discussed are for uncontrolled emissions. While there are cases where emissions 

during the completion may be vented straight to the atmosphere, most events are controlled by 

combustion. Combustion of hydrocarbons generally reduced emissions amounts by 95-98%. 

Second, the national estimates gross up the uncontrolled amounts by the number of oil wells 

completed. However, these estimates fail to take in to account the diverse nature of the many 

operating regions. The emissions data used by these studies are taken from a small selected 

number of regions. The regions selected tend to be higher pressure and thus have more emission. 

No consideration was given to lower emission areas thus driving the average emissions per well 

up. At the very least, emissions should have been characterized as potential emissions instead of 

being represented as actual emissions. Authors of this paper should also have looked to the 

GHGRP for emissions estimates rather than coming up with estimates based on production 

volumes. While not required, many operators have already been reporting emissions from 

hydraulically fractured oil wells and there is a sizeable dataset to analyze. Use of this data 

coupled with analysis of emissions controls already being used by industry would have resulted in 

much lower emission estimates than what is provided in the report. Additional analysis of a 

larger sampling of reservoirs that included a broader range of associated gas volumes would 

also yield a lower potential emissions number than what is presented here. There is no discussion 

or inclusion of areas where associated gas volumes are low.

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?

It’s difficult to accept the premise of this question that assumes all emissions are 

uncontrolled. For reasons expressed in question 1, it is wrong to make this assumption. The 

GHGRP is the best overall source of emissions data as more than 70 operators have been 

reporting emissions from the GHGRP for hydraulically fractured oil wells though not required. 

This is important data that has been overlooked. “Available information” used by the authors is 

based on production data and makes several questionable assumptions of how to apply 

production volumes to determine flowback emissions. None of the assumptions used in the 

paper have been validated, and I would surmise they are wrong.
Furthermore, the statement in the paper to justify rejection of GHGRP: “The GHG 

Inventory estimates emissions from oil well completions, but does not distinguish between 

completions/recompletions of conventional wells and completions/recompletions of 

hydraulically fractured wells” makes no sense and shows a basic misunderstanding of well 

completions. Conventional wells, (vertical well bores), and unconventional wells (horizontal 

wellbores) can both be hydraulically fractured. Given the report years of 2011 and 2012, the 

location of the wells being drilled, and the type of data being reported, it can easily be surmised 

that the wells in the dataset represent hydraulically fractured wells. Wells that are not 

hydraulically fractured would most likely not have associated gas emissions to report as there 

likely would be no flowback if there was no well stimulation.

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

fractured oil well completions beyond those described in this paper? 

As already mentioned another look at the GRHRP data is warranted. State programs 

may also have requirements to report these emissions for emissions inventories. An example is 

the Wyoming DEQ, completion emission reports are required to be filed on a per well basis. An 

example report can be found at http://www.shalegas.energy.gov/resources/071311_corra.pdf

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? 

• 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? 

• 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)?

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

appropriate? 

a) It is not appropriate to use the average yearly gas production and multiply by the 

flowback period to estimate uncontrolled emissions. The flowback period will have 

different stages of flow from 100% stimulation fluid to near flowline quality gas 

production. Because of the variations, using the yearly average would misrepresent the 

amount of emissions either high or low. 

b) Using “Initial Gas Production” is also not a good estimate since only the end period of 

the flowback gets close to initial production. 
c) It would not be appropriate to use a linear correlation for 9 days. No evidence suggests 

that maximum gas potential is reached in 9 days. 

d) The use of any average flowback days is not appropriate as all flowback will differ due to 

circumstances. 

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

estimating hydraulically fractured oil well completion emissions. 

See answer to question 2. 

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 number of recompletions can be estimated by using the sub-part W program to 

obtain the number of workovers with hydraulic fracturing. Capture of data regarding the amount 

of uncontrolled emissions is more difficult since each region and reservoir will vary. Regional 

factors could provide estimates but expect each well to vary significantly. The rate of refracturing for oil wells is undetermined. I believe 1% may be too high. 

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 required 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.”

RECs are implemented on the majority of oil well completions that have pressure. When 

enough gas is produced to operate a separator, the gas stream is sent to a combustion device. 

Consideration should be given to wells that do not have infrastructure to sell natural gas. These 

wells should be allowed to flare for an extended period (90 days) to allow sale of liquid

hydrocarbon. Low pressure exception should be allowed for wells whose pressure is below line 
pressure. A sufficient pressure differential is required to ensure flowback velocity is sufficiently 

high to adequately lift and clean out fluids and solids from hydraulic fracturing. The Colorado 

rule seems appropriate for RECs as do the requirements of the Wyoming DEQ.

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

emissions from hydraulically fractured oil well completions. 

The cost of an REC will not substantially change the economics of the wells. Cost and 

equipment necessary will vary by well and region. There should be no substantive difference in 

cost than those for hydraulically fractured gas wells. Equipment requirements will essentially be 

the same.

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. 

It is typical for oil well completions which flow to use combustion devices. The devices 

typically reduce emissions by 95-98%. The EDF/UT study indicates a reduction of “nearly 98% for 

the limited data being reported. Compared to the reported reductions for REC of about 98.8%, 

this is only a minimal difference of 1%. “

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? 

See above. No studies that I am aware of, but fairly accurate inferences can be made by 

understanding general characteristics of the various reservoirs Wells completed in high pressure 

reservoirs such as Bakken and Eagle Ford will most surely employ RECs or completion 

combustion devices, whereas low pressure formations such as those in East Texas or some areas 

of the Permian will not since the volume of associated gas is low to nonexistent.

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

hydraulically fractured oil well completions or are there others? 

EPA identified the current technologies. These technologies should be evaluated on a fit

for purpose basis.

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. 

Because the term “associated gas emissions” is used instead of “stranded gas emissions”

it is easy to misinterpret the data set in Appendix A. A reader can conclude from the 

data set that all hydraulically fractured oil wells in 2011 resulted in produced gas that 

was vented and not sold since the gas volumes in the data tables are labeled “associated 
gas”. This is certainly untrue as many if not most of the wells in the data set actually do 

gather and sell the produced gas. Using the term “stranded gas” defined as a subset of 

associated gas that is produced gas in the production phase that is vented or flared 

because it can’t be sold is recommended to avoid this misinterpretation. 

The second problem with “associated gas emissions” is that the discussion in section 4.0 

redefines the term as gas that is vented, not vented or flared as is provided in the 

definition in section 2.2. The focus of the discussion then is centered on how best to 

estimate uncontrolled emissions with no discussion of the importance in determining 

how many wells are vented versus flared. Consequently, the intent of this section is 

confusing since it is not known if EPA is only concerned with wells that vent associated 

gas or wells that both flare and vent associated gas. To get a true picture of stranded 

gas emissions, estimates of the use of controls is as important as estimating gas volumes 

themselves. I would posit that most high volume wells would be flared, whereas venting 

would be more prevalent with wells with low to no stranded gas volumes.

No real emission estimates seem to be provided in the paper other than to quote from a 

couple of sources such as Flare Up and the GHGRP. Other than that, discussion centers 

on possible methodologies to determine emissions. Attempting to develop an average 

GOR factor is not a feasible approach. It assumes its possible to have a direct correlation 

of oil production volume to gas volumes over the life of the well. This correlation doesn’t 

exist in oil and gas production. The goal is not clear, but If an average GOR factor is 

being considered for determining nationwide or regional emissions, the correlation is 

even worse and would be highly inaccurate. Additionally, oil wells with high gas volumes 

would skew such a factor such that it would misrepresent the many wells that produce 

little or no associated gas. There is no discussion of wells with low volumes of associated 

gas and is an important piece of missing information in the paper. The Permian Basin 

for example is an active area for hydraulic fracturing where there are many wells with 

little to no associated gas. Because volumes are so low, gathering for sales is 

uneconomic so associated gas is vented or flared but a nationwide factor skewed by 

wells in the Bakken or Eagle Ford would be an inaccurate representation for many 

Permian wells.

Volumes reported to state oil and gas agencies is another approach discussed, but 

shunned in the paper because there is no accounting for field gas used to support 

production such as instrument gas for pneumatics and fuel gas for fired sources such as 

heaters and compressor engines. However, volumes reported to oil and gas agencies is 

much more accurate than any attempt at using a one size fits all GOR. Additionally, field 

gas use would be only a very small percentage of the total volume of gas produced. 

Additionally, gas volumes reported are measured volumes not estimated, and I think in 

most states field use gas is not included in the reported volume since field use gas is an 

expense and royalties are not paid.
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? 

Pipeline availability differs by region and area within that specific region. Not all shale 

oil plays have infrastructure problems, and in many areas the issue of infrastructure is a 

decreasing problem as more gathering systems and processing facilities are constructed.

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 did identify all the available technologies. 

14. 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? 

EDF/UT study attempts to further the on the ground measurements. Measurements 

taken by aircraft tend to be high and cannot differentiate between various sources.