Attachment A

Hydraulically Fractured Oil Wells

David Allen

University of Texas at Austin
Comments on 

 Oil and Natural Gas Sector Hydraulically Fractured Oil Well 

Completions and Associated Gas during Ongoing Production 

Draft dated April, 2014 

Submitted to: 

Carrie Richardson Fry 

Research Triangle Institute 

Submitted by: 

David Allen 

June 16, 2014 

Overview 

I have reviewed the draft white paper titled “Oil and Natural Gas Sector Hydraulically Fractured 

Oil Well Completions and Associated Gas during Ongoing Production” prepared by the U.S. 

EPA Office of Air Quality Planning and Standards (OAQPS), dated April 2014. I have 

concentrated my review on my areas of expertise. My comments identify additional information 

available from a recent set of measurements of methane emissions from natural gas and oil well 

completion flowbacks (Allen, et al., Proceedings of the National Academy of Sciences, 110, 

17768-17773, and publicly available supporting information, referred to as Allen, et al., 2013 in 

this document). My comments also describe some important features of the available data. The 

review is organized into two sections: responses to the charge questions for reviewers that appear 

in the white paper, and additional specific comments, organized by page number. 
Responses 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? 

Response: Measurements of emissions from completion flowbacks are extremely limited, as 

noted in responses to subsequent charge questions. This creates uncertainties in national 

emission estimates. 

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? 

Response: Net emissions are estimated by estimating potential emissions, then reducing those 

emissions by a control efficiency factor. In the data reported by Allen, et al. (2013), 

measurements were made of control efficiencies for 18 well completion flowbacks. These 

wells controlled emissions either through flaring of flowback gases or through capture of the 

gases and routing the gases to sales. Of the potential emissions for these 18 wells (emissions 

if the well had not had control technologies installed), 99% were captured or combusted. 

This control effectiveness is based primarily on a group of direct measurements, but it was 

necessary to assume the destruction efficiency for materials sent to flares. The assumed 

destruction efficiency was 98%; this assumption is consistent with the limited data available 

on these flares. Allen, et al. (2013) reported measurements of combustion efficiency of a 

flare on a well completion site, and these data suggested very high flare destruction 

efficiency (>99%). 

Thus, overall control efficiencies in the range of 98-99% were observed for 18 wells on 

which emission control equipment was installed during completion flowbacks. Many, but not 

all of these wells were gas wells (see response to Question 4). For the limited number of oil 

wells (defined in the white paper as a gas to oil ratio of 12,500 scf/bbl or less) on which 

measurements were made, control efficiency was also in the range of 98-99%. 

The data reported by Allen, et al, also suggest some possible methods for assembling 

additional data on potential emissions and control efficiencies. Each of the 18 wells with 

controls, on which Allen, et al. (2013) made measurements, utilized a separator. The vast 

majority of the flowback gas was associated with the vapor stream leaving the separator. 

Relatively little gas volatilized from flowback tanks or was released to the atmosphere due to 

initial flow into an open top tank. Therefore, the overall control efficiency for the flowbacks 

were dominated by the fate of the separator vapor stream. If that stream is sent to a flare, 

the overall control efficiency will be similar to that of the flare for many wells. If the gas is 

recovered and sent to sales, the control efficiency can be close to 99+%. 

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

hydraulically fractured oil well completions beyond those described in this paper? 
Response: I am not aware of any additional direct measurements of emissions. 

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

hydraulically fractured oil wells in this paper. 

a. 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? 

Response: The data reported by Allen, et al. (2013), that is cited and reproduced in Table 

3-6 of the white paper, can be used to compare average daily gas production to 

uncontrolled (potential) emissions. Focusing just on the wells that the white paper has 

identified as oil wells (GC-1, GC-2, GC-3 and GC-7), the potential emissions, reported 

by Allen, et al. (2013) and cited in Table 3-6 of the white paper, can be compared to the 

product of the gas production for the same wells, (reported in Table S1-6 of Allen, et al. 

(2013), Supporting Information) and the duration of the event (cited in Table 3-6 of the 

white paper). These data are summarized in the Table below: 

Well Potential 

methane 

emissions* 

(Mcf) 

Gas 

production 

rate (first 30 

day avg.)** 

(Mcf/d) 

Duration of 

flowback* 

(Days) 

Gas production 

rate x duration x 

x 47% methane 

(Mcf) 

Ratio of measured 

potential emissions 

to estimate based on 

duration and gas 

production 

GC-1 5,005 3,000 75/24 4406 1.14 

GC-2 4,205 2,700 76/24 4018 1.05 

GC-3 21,500 1,300 28***/24 713 30.7*** 

GC-7 4,320 1,500 108/24 3172 1.4 

*As cited in Table 3-6 of the white paper 

**From Allen, et al. (2013), Supporting Information, Table S1-6 

***Ambiguity in duration of event, see text below 

For three of the four wells, (all with flaring of gas during the completion) the measured 

potential emissions are comparable to the emissions estimate (based on the method 

described in the white paper); the ratio of the measurements to the estimate has a value 

near 1. For one well, the potential emissions are much larger than the estimate. For this 

well the critical issue is the flowback period. In reporting results, Allen, et al. (2013) 

note that different companies had different practices in defining the end of a completion 

flowback. For example, some companies might define the end of the flowback as the time 

at which gas is first routed to sales. Other companies might define the end of the 

flowback as the time at which flow is routed to permanent, rather than temporary 

completion equipment. No single, consistent definition is in use. Details for the specific 

case of well GC-3 are described in study appendices from Allen, et al. (2013; available at 

the study web site http://dept.ceer.utexas.edu/methane/study). This well had an initial 

flowback to an open top tank that lasted for 28 hours. After 28 hours, the flow was 

directed to a separator and the gas from the separator was then sent to sales and a flare. 

In this case 28 hours was defined as the duration of the flowback, as reported by the 

company, since gas had begun to go to sales. The study team reported emissions from 
th

2

T

d

re

th

b. Is

“I

p

R

c. Is

in

(n

o

A

co

o

sc

to

4 

se

fl

co

st

th

re

d

fl

ty

his flowback

8 hours of th

Thus, well G

defined in the

esults (e.g. f

he end of a c

s it appropria

Initial Gas P

eriod? 

Response: Se

s it appropria

ncreasing em

normally est

f production

Allen et al. (2

ourse of a w

il well using

cf/bbl or les

otal of 75 ho

hours, the 

eparator wa

low to the fl

ompletion fl

tudy web sit

he gas varie

ecorded on a

data are not 

low is nearly

ypes of gas fl

k that includ

he flowback.

GC-3 illustra

e white pape

for wells GC

completion fl

ate to estima

Production,” 

e response t

ate to estima

missions line

imated using

n)? 

(2013) repor

well complet

g the criteri

ss) are show

ours. During

flow was r

s routed to a

flare. The s

owback desc

te, http://de

ed relatively

an hourly av

consistent w

y constant. 

flow patterns

ded the emiss

 

ates a poten

er. While co

C-1, GC-2, G

flowback, con

ate average u

as reported 

to Question 4

ate average u

arly over the

g the produc

rt a limited a

tion flowbac

ion defined 

wn in the Fig

g the first 4 

routed to a 

a flare. The 

slope of this

criptions by

ept.ceer.utex

y little betwe

verage basis

with a linear

This is just 

s associated 

sions from th

ntial issue w

nceptually th

GC-7), unless

nsistent appl

uncontrolled

in DI Deskto

4a. 

uncontrolled

e first nine d

ction during 

amount of d

ck. For exam

in the white

gure below. 

hours, the fl

completion

Figure show

s line is the 

Allen et al. 

xas.edu/meth

een hours 5

s) was relat

r increase in

one type of

with comple

he flare, wh

with the em

he method a

s there is a c

lication of th

d oil well com

op, and mult

d oil well com

days until the

the first mon

data on the d

mple, data f

e paper as 

 This comp

flowback wen

n separator.

ws the cumu

flow rate. A

(2013; study

hane/study), 

5 and 75, an

tively consta

n gas flow du

f flowback, h

etions. 

hich occurred

mission estim

appears to le

consistent m

he method w

mpletion em

tiplying by t

mpletion em

e peak rate is

nth converte

details of flo

for well GCa gas to oil

pletion flowb

nt to an ope

 Gas from

ulative amoun

As describe

y appendices

the methan

nd the gas f

ant over the p

uring a comp

however, and

 

d after the i

mation proce

ead to reason

method of def

will be difficu

missions using

the flowback

missions by 

s reached 

ed to a daily 

ow rates ove

-1 (defined a

l ratio of 12

back lasted f

en top tank. 

m the compl

nt of metere

d in the det

s available a

e compositi

flow (which

period. T

mpletion. Th

d there are 

Cumulative

amount of g

flow during

completion 

GC-1 (Allen

al. 2013) 

initial 

edure 

nable 

fining 

ult. 

g

k

rate 

er the 

as an 

2,500 

for a 

After 

letion 

d gas 

tailed 

at the 

on of 

h was 

These 

e gas 

many 

e

gas 

g

n, et 
T

m

a

co

 

S

et

th

d. Is

ap

R

d

co

A

ra

5. Pleas

estim

Respo

made

assoc

flowb

There

The Figure b

minutes) comp

l. (2013)). 

ompletion flo

Similar data a

t al. (2013); 

he difficulty 

s the use of a

ppropriate? 

Response: A

duration is n

ompany tha

Allen, et al. 

anged from 4

se discuss oth

mating hydrau

onse: As no

e measureme

ciated with t

back tanks o

efore, the o

below displa

mpletion flow

The methan

owback, with

are availabl

these examp

in generaliza

a 3-day or 7-

As noted in t

needed. Ap

t owned the

(2013), (mo

4 hours to 2 

her methodo

ulically fract

oted in respo

ents utilized

the vapor str

or was releas

overall contr

ays methane 

wback of a ga

ne emissions

h gas flows g

le for each of

ples illustrat

ations about

-day flowbac

the response

pplying the 

e well, the d

ostly gas we

weeks, with

ologies or da

tured oil wel

onse to Ques

d a separato

ream leaving

sed to the a

rol efficienc

emission ra

as well to an

s show a co

generally inc

f the well co

te some of th

t flows. 

ck period for

e to Question

definition 

durations of

lls using the

h a mean valu

ata sources th

ll completion

stion 2, all o

or, and the 

g the separa

tmosphere d

cy for a flow

ates (scf/min

n open top ta

omplex beha

creasing ove

ompletion flo

he complexit

r hydraulica

n 4a, a cons

of the flow

f well compl

e definition 

ue of 81 hr.

hat you belie

n emissions.

of the wells 

vast majori

tor. Relativ

due to initia

wback is do

n), over a 1

ank (well MC

avior over t

er time. 

owbacks mea

ties of the flo

ally fractured

sistent defin

wback durat

letion flowba

applied in 

 

eve would be

. 

on which Al

ity of the fl

vely little gas

l flow into a

ominated by

144.7 hour (

C-1 from All

the course o

asured by Al

ows and illus

d oil wells 

ition of flow

tion used by

acks reporte

the white p

e appropriat

llen, et al. (2

lowback gas

s volatilized

an open top 

y the fate o

Methane 

emission ra

(scf/min), o

a 144.7 hou

(8683 minu

completion

flowback of

gas well to 

open top ta

(well MC-1

from Allen,

al. (2013, s

website)

(8683 

en, et 

of the 

llen, 

strate 

wback 

y the 

ed by 

aper) 

e for 

2013) 

s was 

d from 

tank. 

of the 

ates 

over 

ur 

utes) 

f a 

an 

ank 

1

 et 

study 
separator vapor stream. If that stream is sent to a flare, the overall control efficiency will be 

similar to that of the flare for many wells. If the gas is recovered and sent to sales, the 

control efficiency can be close to 99+%. In addition, the amount of gas leaving the 

completion separator is often very close to the potential emissions from the well. Therefore, 

collecting information about gas flows from completion separators has the potential to 

generate a large body of data on potential emissions from completion flowbacks. 

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? 

Response: No response – this question is outside the scope of my expertise. 

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” 

Response: No response – this question is outside the scope of my expertise. 

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

control emissions from hydraulically fractured oil well completions. 

Response: No response – this question is outside the scope of my expertise. 

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. 

Response: As noted in the response to Question 2, Allen, et al. (2013) measured overall 

control efficiencies in the range of 98-99% for 18 wells on which emission control equipment 

was installed during completion flowbacks. Many, but not all of these wells were gas wells 

(see response to Question 4). For the limited number of oil wells (defined in the white paper 

as a gas to oil ratio of 12,500 scf/bbl or less) on which measurements were made, control 

effectiveness was also in the range of 98-99%. 
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? 

Response: No response – this question is outside the scope of my expertise. 

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

hydraulically fractured oil well completions or are there others? 

Response: No response – this question is outside the scope of my expertise. 

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. 

Response: No response – this question is outside the scope of my expertise. 

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? 

Response: No response – this question is outside the scope of my expertise. 

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 

Colorado Department of Natural Resources: Oil and Gas Conservation Commission Rule 

805.b(3)A. (http://cogcc.state.co.us/) 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. 

Response: No response – this question is outside the scope of my expertise. 

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? 

Response: See response to Questions 3 and 5. 

 
Specific Comments 

Page 11, Table 3-2: The first two rows may be labelled incorrectly. It is unclear, for example, 

how a maximum molecular weight for VOCs could be 31.7, while the maximum molecular weight 

for natural gas is listed as 51. 

Page 27: The white paper states that a completion combustion device will achieve an average of 

95% control. Limited measurements made by Allen, et al. (2013) suggest that this control 

effectiveness may be as high as 99%.

Page 48: The Allen, et al. reference cited at multiple points in the document is missing.