Oil & Gas Journal
Vol. 112.11, November 3, 2014
____________________________________________________
New Well-Productivity Data Provides US Shale Potential Insights
Rafael Sandrea, President, IPC Petroleum Consultants, Inc.
Ivan Sandrea, Oxford Institute for Energy Studies (UK)
The US has 13 shale plays with significant oil and gas resources. Two of these plays (Bakken and Eagle
Ford) account for three-quarters of US shale oil output, and four (Barnett, Fayetteville, Haynesville, and
Marcellus) account for 83% of US shale gas output. The Marcellus is the premier shale gas play and
contains roughly 1.6 times the combined reserves of the other three leading major shale gas plays. It went
on-stream in 2008 and is already the biggest shale gas producer with an annualized output of 9.28 bcfd in
2013. The Marcellus is on a robust production growth path and will be the king-pin of US natural gas
production for the foreseeable future. A similarly important role is projected for both the Bakken and
Eagle Ford oil plays. As a result of this recent shale boom – which in effect began in the early 1990s with
the Barnett Shale, and its surge in the mid 2000s when multistage fracking was introduced – the US is
now the world’s largest producer of natural gas and is currently producing nearly 8 million b/d (mbd) of
crude oil, up from 5 mbd in 2008. Figs. 1 & 2 illustrate the production history of the six major shale
plays.
Investors nonetheless see another picture. They seem to be tired of waiting for emerging shale plays to
become lucrative. Over the past four years, returns on energy investments have disappointedly
underperformed, sinking as much as 15 percentage points from those of the past decade. To date, 60,000
shale oil and gas wells have been drilled and the large sums of capital already deployed in shale
investments will take three to four years before they can start generating cash flow. Further, shale
properties as a whole begin to decline 3 to 4 years following heavy capital development costs. Massive
spending lies ahead since production is maintained by drilling more and more wells to compensate field
decline. Financial investors want more accurate predictions of key parameters including reserves, true
production potential, and a trustworthy lifetime drilling capex, that have been difficult to obtain for such
shale reservoirs.
Fortunately, we now have available substantial field performance data on six giant shale plays. This
analysis assesses development of these oil and gas plays with the objective of better determining their
reserves, recovery factors, and production potential. At this time only first order estimates – those
assumed during early development of the play – of these key parameters are available and they need to be
verified or adjusted. Additionally, a methodology is developed for reliably determining well reserves and
future drilling requirements based on well-productivity.
1
1000
Fig 1 Production: Leading Shale Oil Plays
Crude Oil, 1000s b/d
750
Bakken
500
Eagle Ford
250
Sources: EIA; TRRC; NDGS
0
2000
10
2005
2010
2015
Fig. 2 Production: Major Shale Gas Plays
bcfd
Marcellus
8
Haynesville
6
4
Barnett
Fayetteville
2
0
2000
Source: EIA
2005
2010
2015
2
Production Declines
As shown in Fig. 2, production decline has set-in in three of the four major shale gas plays, the exception
being the latest start-up, the Marcellus play. This characteristic early onset of decline in shale plays,
typically 60–80% the first year, occurs merely 3–5 years from production start-up versus 9–12 years for
traditional oil fields of similar size (reserves). While evidently of concern as it points toward low
recoverable reserves, this provides an early opportunity to reassess reserves estimates and associated
recovery factors.
In an earlier article (Sandrea, 2014) field decline analysis provided fresh estimates of reserves (EUR) for
the Barnett and Fayetteville, 20 tcf and 9 tcf, respectively. These values are roughly one-third lower than
their latest EIA/AEO2012 estimates. In regard to the Haynesville, in its short production history which
started in 2008 it has already peaked at 6.8 bcfd in the last quarter of 2011. Thereafter its output has
dropped significantly reaching 3.87 bcfd at the end of 2013. Field decline analysis shows a performance
EUR of 12 tcf, a value drastically different from the EIA/AEO2012 estimate of 66 tcf. It should be noted
that Operators of the Haynesville have also reported a low EUR of 11.4 tcf in their Dec. 31, 2012
disclosures to the SEC. The Haynesville has proven to be surprisingly disappointing.
Regarding the Marcellus, its production kicked-off in 2008 and has since been on a strong growth path
reaching 10.9 bcfd in December of 2013. Its cumulative production is still small, only 6.7 tcf, compared
with its estimated technical reserves of 140 tcf reported in EIA/AEO2012. This short history precludes
decline analysis as a tool to reassess the play’s performance EUR. Based on the current estimate of its
technical reserves (140 tcf), the production potential of the Marcellus would be about 24 bcfd, roughly
double its latest year-end output. Following the reserves reassessments of the three major mature shale
gas plays, their revised recovery factors now range from 1.7% for the Haynesville to 6.1% for the Barnett
and 11% for the Fayetteville. The overall reserves-weighted average is 5.9%. A recent study (2013) by a
BEG/University of Texas team estimates a 19% recovery factor for the Barnett. The EIA estimates a
recovery factor of 7.9% for the Barnett, and an overall recovery factor of 13% for all shale gas plays.
Undoubtedly, geologic settings of shale plays are exceedingly varied. Which of these many lithologic
factors have the most influence on how much oil or gas will be produced – in other words, the recovery
factor of the play – is a big unknown. Unexpectedly, the Haynesville’s field performance has centered
the spotlight on pore pressure gradient. The Haynesville’s extremely high pressure gradient, in the range
of 0.75–0.85 psi/ft, is nearly double the normal pressure gradient of 0.43 psi/ft. The upside of its high
pressure gradient has been abnormally high well IPs (9.5 MMscf/d), almost five times those of the
benchmark Barnett.
On the downside, however, the Haynesville’s wells have very high early decline rates (86%/year). The
net result is very low recovery efficiency for the play, roughly 1.7%. This is the lowest recovery factor of
all major shale gas plays. By comparison, the recovery factor of the benchmark Barnett is 3.5 times that
of the Haynesville. Not surprisingly, the Haynesville is a lonely outlier in the very sturdy power law
relationship between production potential and reserves of the other major shale gas plays (Sandrea et al,
2014). The recovery factor of the Marcellus would be 9.3% based on EIA estimates of its technical
reserves (140 tcf); this is 58% higher than the average recovery factor for the three mature major gas
plays. Table 1 summarizes the results discussed in this section.
3
Table 1 Major Shale Gas Plays: Reserves, Recovery Factors, Production Potential,
Well-Productivities – 2013
Plays
Barnett
Fayetteville
Haynesville
Marcellus
Gas-in-place1, bcf/sq. mile
Year-end Output, bcfd
Cumulative Production, tcf
50
5.31
14.7
30
2.87
4.2
77
3.87
8.5
18
10.90
6.7
Reserves(EUR) 2, tcf
Recovery Factor, %
Production Potential3, bcfd
20
6.1
5.64(2011)
9
11.2
2.88(2012)
12
1.7
7.0(2011)
140
9.3
24
Peak Well-Productivity,
Mcfd/well
Present.Well-Productivity, Mcfd/well
Year-end Producing Wells
Current 180-day Well IPs, MMcfd
Well-Productivity Decline Rate, %/year
Well EUR, bcf/well
Well-Productivity by 2020, Mcfd/well
438 (2008)
833 (2010)
3,382 (2010)
303
17,494
1.9
7
2.2
190
610
4,704
2.1
10
3.0
306
1,195
3,238
9.5
35
3.5
102
1,050
10,369
4.9
Depth, feet
Pore Pressure Gradient, psi/ft
5,000-8,000
0.49-0.54
1,000-7,000
0.44
9,600-13,500
0.75-0.85
2,000-8,500
0.40-0.58
1.6
Notes: Mcfd=thousand (standard) cubic feet per day; MMcfd=million cubic feet per day; bcfd=billion cubic feet per day;
tcf=trillion cubic feet; psi=pounds per square inch; GIP=gas-in-place; EUR=estimated ultimate reserves. (1)GIP values reported
in EIA/AEO2012, except for the Fayetteville which is based on a University of Texas study, OGJ/Jan., 2014; the Marcellus has
an exceptionally low gas content of 80 cf/ton (USGS) – one quarter that of the Barnett – which accounts for its low GIP value of
18 bcf/sq mile. (2) obtained using logistic decline analysis, except for the Marcellus’ EIA/AEO2012 estimate. (3) field values
and date of occurrence except for Marcellus which is algorithm estimated (Sandrea et al, OGJ, Aug. 2014).
Sources: EIA/AEO2012, USGS2011, TRRC.
Well-Productivity
Peak production in a shale play is an important economic milestone. It signals the onset of decline which
in turn allows the use of decline analysis to more reliably estimate both play and well reserves.
Establishing peak values from field production data, however, can at times be not clear-cut as production
rates can plateau or continue growing for a while after reservoir peaking! This apparent dichotomy will
be underscored later in this article. A more definitive way of determining peak makes use of the ratio of
the play’s production to the corresponding number of producing wells. This ratio is labeled wellproductivity – just another way of visualizing field production on a per well basis. It is not to be
confused, however, with the same term in reservoir engineering which refers to a specific well parameter
defined as the ratio of well rate to pressure drawdown.
For illustration purposes, Fig 3 shows the correspondence between production and well-productivity for
US crude oil production. The trends of production and of well-productivity certainly correlate throughout
the 60 years of production history shown in the graph. However, it is evident that the well-productivity
trendline considerably accentuates the production peak feature as it occurred in 1970. To further enhance
the well-productivity trendline, it is standard practice to define well-productivity as the ratio of year-end
(December) values of the field’s or play’s output and of the number of producing wells. This gives
leading edge values to the ratio as compared with annualized production values that essentially reflect
mid-year conditions. The number of active producing wells at year-end includes the number of new
completions during the course of the year minus retired wells that have reached the end of their
productive life.
4
Fig. 3 US Crude Oil Production, Well-Productivity
25
20
Well-Productivity
b/d/well
15
10
Production
million b/d
Source: EIA
5
1950
1960
1970
1980
1990
2000
2010
2020
Finally, it should be emphasized that well-productivity is a distinctive field-wide parameter with a decline
behavior very different from that of individual wells. For example, the current well-productivity for the
Haynesville is 1.2 MMcfd/well which represents the average well production rate of all (old and new)
active wells, while new wells in the Haynesville have an average initial production (IP) of 9.5 MMcfd.
More importantly, in particular for shale plays, well-productivity trends provide a straightforward and
reliable estimate of both the number of wells to be drilled in order to sustain production schedules and of
the overall well EUR. Well-productivity directly accounts for the play’s reservoir decline.
Shale Gas Plays
Fig 4 shows the well-productivity trendlines for the six shale plays of this study. Let’s first look at the
Barnett, the benchmark of all shale plays. Its well-productivity trend grows slowly during early
development reaching a peak of 438 Mcfd/well in 2008, thereafter declining softly to 303 Mcfd/well in
2013 at a rate of 7% per year. At the end of 2008, the Barnett had 10,146 producing wells and by 2009
the well count had jumped to 13,740. Subsequently, drilling dropped off considerably; the number of
producing wells increased by only 840 in 2012, and by 784 in 2013 thus permitting the Barnett’s output to
slip. Evidently, the price of gas has not been high enough to justify the additional 988 wells needed to
sustain an output level of around 5.6 bcfd and at the same time compensate for well-productivity/reservoir
decline.
The following example shows the simple determination of the number of producing wells required to
produce 5.6 bcfd with a current well-productivity of 303 Mcfd/well: (5.6*106) / 303 = 18,482 wells versus
17,494, the number of actual producing wells at the end of 2013. The deficit of 988 wells would
correspond to an additional capex of $3.4 billion based on average well costs of $3.5 million. For 2014,
the number of additional producing wells required would increase to 1,883 as the well-productivity is
expected to decline to 289 Mcfd/well.
5
3000
Fig. 4 Well-Productivity Trends
Major Shale Oil & Gas Plays
450
Gas, Mcfd/well
Oil, b/d/well
2500
2000
Haynesville
300
1500
Eagle Ford
(oil)
1000
150
Bakken
(oil)
Fayetteville
500
Barnett
M arcellus
0
1995
2000
2005
2010
0
2015
The Haynesville, on the other hand, shows (Fig. 4) a steep well-productivity decline trend in line with its
extraordinary high early well decline rates of 86% per year. Well-productivity has dropped 64% from 3.3
MMcfd/well in 2010 to 1.2 MMcfd/well in 2013, all of which point towards a low recovery factor. The
Fayetteville’s well-productivity decline has been more moderate, dropping 27% from 833 Mcfd/well in
2010 to 610 Mcfd/well in 2013. The steeper the well-productivity decline the more capital investment in
new wells is required to compensate reservoir decline and maintain production levels. Based on the
Haynesville’s well-productivity of 1,195 Mcfd/well in 2013, the capex required to maintain an output of 6
bcfd, instead of its actual output of 4.76 bcfd, would have amounted to $17 billion for 1,783 additional
wells!
The well-productivity trendline of the Marcellus shows (Fig. 4) a normal start-up growth pattern which
has leveled off to around 1 MMcfd/well. Development took off at a blistering pace, with 4,127 producing
wells in 2011 from only 763 in 2009. In 2012, the number of producing wells had grown to 8,982, and to
10,369 by 2013. Output reached 11 bcfd in December of 2013, little under half of its expected production
potential of 24 bcfd. The cost of a well runs about $6 million.
In summary, it is worth highlighting the advantages of using well-productivity to define reservoir peak. It
is a more sensitive metric than field production rates. Fig. 4 shows clearly that the Barnett’s wellproductivity peak took place in 2008 whereas Fig. 2 shows its production peak occurring in 2012.
Particularly for shale plays, the well-productivity parameter has a huge advantage: it provides a quick,
6
reliable, ongoing field estimate of the number of new wells required to maintain a desired level of
production. Current methodology assumes an outlook of drilling requirements based on a type-well
production profile which: a) does not reflect the notorious variations in well production rates within shale
plays, and b) does not take into account play/reservoir decline. These shortcomings can lead to gross
under-estimates of critical capex requirements, and over-estimates of future production rates.
Additionally, well-productivity trendlines generally follow the standard exponential decline model which
provides a simple determination of the average well EUR over the entire play and of future declining
well-productivity values. Table 1 gives the well-productivity exponential decline rates for each of the
three mature shale gas plays: 7%, 10% and 35% per year for the Barnett, Fayetteville, and Haynesville,
respectively. By 2020, well-productivity in the Barnett would drop to 190 Mcf/d/well from its current
level of 303 Mcfd/well; for the Fayetteville its well-productivity would drop to 306 Mcf/d/well from 610
Mcfd/well today; and for the Haynesville, its well-productivity would drop drastically to 102 Mcf/d/well
from its present value of 1,195 Mcfd/well – a product of its high decline rate.
Calculated average well EUR based on well-productivity decline is 2.2 bcf/well for the Barnett which is
69% higher than the previous EIA/AEO2012 estimate of 1.3 bcf/well; for the Fayetteville its performance
well EUR is 3.0 bcf/well versus the previous estimate of 1.3 bcf/well; and for the Haynesville 3.5 bcf/well
versus the previous estimate of 2.7 bcf/well. Note that all of these performance well EUR values are
higher than those obtained using type-well analysis. Nonetheless, we should remember that calculated
well EURs will be significantly affected by the productive life of the wells. The Barnett is the best
documented of the plays in this respect and statistics indicate a low average well productive life of 7.5
years. This is partially due to well decline rates and to the complexity of completion methods employed
for shale plays. Table 1 provides a summary of the values discussed above.
Shale Oil Plays
The well-productivity decline trends for the two major shale oil plays, Bakken and Eagle Ford, are shown
in Fig. 4. The Bakken trendline confirms a peak of 144 b/d/well in 2011. Nonetheless, its annualized
output has grown continuously from 274 kb/d in 2010 to 836 kb/d in 2013, Fig. 1. Drilling was stepped
up considerably. There were 2,064 producing wells in 2010, 3,275 in 2011, 5.048 in 2012, and 6,824 in
2013. Present 30-day IPs of new wells in the top four producing counties covering this shale deposit
average 735 b/d per well while the overall average across the entire play is 565 b/d per well, Table 2.
The current level of drilling activity is ample enough to compensate the Bakken’s relatively soft wellproductivity decline rate of 6.7% per year and additionally provide output growth. By 2020, wellproductivity in the Bakken would have declined to 77 b/d/well. In order to sustain an output similar to its
latest year-end level of 863 kb/d would require 11,208 producing wells, nearly double the present
number!
In regard to the Eagle Ford, Fig. 1 shows a vigorous exponential growth path of its crude oil production
from barely 15 kb/d in 2010 to 717 kb/d in 2013; meanwhile its well-productivity shows a continuous
decline from a high of 270 b/d per well in 2011 to a current level of 130 b/d per well, Fig. 4. Crude oil
production, however, has increased continuously because of intense drilling activity. There were 480
producing wells in 2011, 1,742 in 2012, and 5,493 in 2013. Oil prices evidently favor the economics of
drilling more and more in-fill wells with 30-day well IPs of 812 b/d, 44% above those of the Bakken.
Wells cost on average $4-6.5 million compared to $5.5-8.5 million for its counterpart, the Bakken.
However, because of the high decline rate of Eagle Ford’s well-productivity – 36% per year – this metric
is expected to plunge to a low of 11 b/d/well by 2020; this would require an astronomical number of
producing wells, roughly 73,000, to sustain an output level of 800 kb/d!
7
There are many interesting comparisons in the development of these two shale plays. The well density in
the sweet spots of both of these plays is now approaching 40-acre levels (16 wells/sq mi). There are now
6,824 producing wells in the Bakken versus 5,493 producing wells in Eagle Ford which started
production a couple of years later. Essentially, we have been drilling to outpace the decline. Present
year-end well-productivity levels in both plays are similar: 126 b/d/well for the Bakken and 130 b/d/well
for the Eagle Ford. However, by 2020 the Bakken’s well-productivity would drop to 77 b/d/well and the
Eagle Ford’s to 11 b/d/well, in accordance with their respective decline rates of 6.7% per year and 36%
per year. Performance well EURs calculated for the Bakken and Eagle Ford are 750 kb/well and 274
kb/well, respectively. The previously estimated values (EIA/AEO2012) using type-well analysis are 550
kb/well for the Bakken and 280 kb/well for Eagle Ford.
For both the Bakken and Eagle Ford, insufficient production history precludes the use of field decline
analysis to verify their reserves. The Bakken had produced less than 1 Bbo of crude oil at the end of 2013
while Eagle Ford’s cumulative crude oil production was less than half, only 0.43 Bbo. The technical
reserves listed in Table 2 for both plays are those reported by EIA/USGS. The reserves for the Bakken
(7.4 billion barrels) include those of the contiguous Sanish and Three Forks formations according to the
latest USGS assessment of April 2013. This level of reserves would imply a production potential of
1,075 kb/d based on field developed power law algorithms relating production potential and reserves
(Sandrea, 2012). The Bakken’s 1Q14 crude oil output, as reported by the North Dakota Geological
Survey (NDGS), was 892 kb/d and growing.
In regard to the Eagle Ford, its technical reserves remain at 3.3 billion barrels according to the
EIA/AEO2012 report. This would imply a production potential of 606 kb/d but its crude oil output had
already reached 838 kb/d in 1Q14 as reported by the Texas Railroad Commission (TRRC). The
Commission also reported that the annualized output for 2014 is expected to be 803 kb/d which would
imply a slight drop off from its 1Q14 level. If we assume an apparent peak of 838 kb/d, the
corresponding reserves of Eagle Ford would be of the order of 5 billion barrels of crude oil. These are the
tentative figures listed in Table 2. Both the Bakken’s and Eagle Ford’s reserves will remain unverified
pending additional production history for an appropriate performance decline analysis. Logistic decline
analysis is the ultimate determinant of a field’s reserves.
8
Table 2 Major Shale Oil Plays: Reserves, Recovery Factors,
Production Potential, Well-Productivities – 2013
Plays
Oil-in-place1, mb/sq. mile
Yearend Crude Output, kb/d
Cumulative Production, mbo
Reserves(EUR)1, Bbo
Recovery Factor, %
Production Potential2, kb/d
PeakWell-Productivity, b/d/well
PresentWell-Productivity, b/d/well
Yearend Producing Wells
Present 30-day Well IPs, b/d
Well-Productivity Decline Rate,
%/year
Well EUR, kb
Well-Productivity by 2020,
b/d/well
Depth, feet
Pore Pressure Gradient, psi/.ft
Bakken
63
863
970
Eagle Ford
94
838
590
7.4
1.8
1,075
5
1.7
838
144 (2011)
126
6,824
565
6.7
270 (2011)
130
5,493
812
36
750
77
274
11
3,100-11,000
0.50
2,500-15,000
0.65
Notes: kb/d= 1000 b/d; mb=million barrels oil; Bbo=billion barrels oil. Well-productivity and
number of producing wells for the Bakken refer to North Dakota. Eagle Ford’s data refer to crude oil.
(1) EIA/AEO2012 reported values. (2) algorithm estimate (Sandrea,OGJ. Dec. 2012.
Sources: EIA, USGS, NDGS, TRRC
A Side Note on Definitions of Shale Gas and Shale Oil Plays
Shale gas plays are ultra tight source rocks with permeabilities in the range of 1-100 nanodarcys. Tight
gas sands have permeabilities around 1-100 microdarcys. Shale oil plays, such as the Bakken and Eagle
Ford, are defined in this study as very tight reservoirs with permeabilities in the range of 1-10
microdarcys. Oil plays such as the Permian and Austin Chalk have permeabilities between 10
microdarcys and 1 millidarcy and are termed tight oil plays, distinct from shale oil plays. For the sake of
completeness, conventional oil and gas fields generally have permeabilities around 1-100 millidarcys.
Unconsolidated oil sands such as the Canadian and Orinoco have permeabilities in the range of 0.5-15
darcys. One nanodarcy will barely allow a natural gas molecule to pass through; crude oil molecules are
more than ten times the size of gas molecules. Nano means billionth as in billionth of a meter or darcy.
Porosity measures a rock’s storage space while permeability measures the rock’s ability to allow fluids to
pass through it. The two, however, exhibit a weak correlation between each other, limited to saying that
high porosity usually results in high permeability. Shale gas plays have log porosities varying from 310% while those of shale oil plays run from 5-10%. Tight gas sands have porosities varying from 3-12%
in comparison with variations of 11-12% for tight oil sands. Porosities in conventional oil and gas
reservoirs run from 10-15%, and up to 35% for unconsolidated sands.
9
Closing Remarks
The following are some highlights of this field performance study of four leading shale gas plays and two
shale oil plays:







Three (Barnett, Fayetteville, and Haynesville) of the four leading shale gas plays are in decline,
leaving the Marcellus as the key player of future US natural gas production. The revised EUR of
the Haynesville is now about 12 tcf, a drastic drop from its previous pre-performance estimate of
66 tcf.
The short production history of the Marcellus precludes decline analysis as a tool to reassess its
performance EUR. The EIA estimates its technical reserves at 140 tcf which would indicate a
production potential of about 24 bcfd or roughly double its 2013 year-end output of 10.9 bcfd.
Based on field performance, the average recovery factor of shale gas plays stands at 5.9 %.
Well-productivity has been shown to be a powerful parameter in the performance analysis of
shale plays. It is a distinctive field-wide metric that accounts for reservoir decline which is very
different from that of individual wells. Well-productivity has proven to be a first-rate beacon of
the onset of reservoir decline, provides a field performance estimate of the average well EUR
across the entire shale play, provides a reliable field estimate of the number of new wells required
to maintain production schedules, and an equally reliable estimate of drilling capex.
Well-productivity analysis indicates that the two leading shale oil plays, Bakken and Eagle Ford,
are both in reservoir decline notwithstanding their strong output growth due to intense in-fill
drilling.
Well-productivity analysis has provided fresh values of well EURs that are much higher than
those estimated using the standard type-well analysis. As an example, the performance-based
estimate of well-EUR for the Barnett is 2.2 bcf/well, 69% higher than its previous estimate.
Likewise, the performance-based average well EUR for the Bakken is 750 kb/well compared with
its previous estimate of 550 kb/well.
Well-productivity decline behavior also provides a simple estimate of future new well
requirements. For example, based on the Barnett’s current well-productivity of 303 Mcfd/well, a
production goal of 5.6 bcfd would require 18,482 producing wells versus the current number of
17,494 wells. An additional 988 wells are needed with a capex of $3.4 billion based on average
well costs of $3.5 million. In the case of the Bakken, if an output of 863 kb/d is required by
2020, 11,208 producing wells will be needed based on its 2020 well-productivity declined value
of 77 b/d/well. This is nearly double the present number of producing wells (6,824) and would
require a drilling capex of $38 billion assuming an average well cost of $7 million.
Rafael Sandrea & Ivan Sandrea
August 29, 2014
10
References
1 Ivan Sandrea, “US Shale Gas and Tight-Oil Industry Performance – Challenges and
Opportunities”, Oxford Institute for Energy Studies, March 2014.
2 “Shale Technology Review”, World Oil, March 2014
3 John Browning et al, “ Study Develops Fayetteville Shale Reserves, Production Forecast”,
O&GJ, January 06, 2014.
4 Stephanie B, Gaswirth and Kristen R. Marra, “Bakken, Three Forks largest Continuous US Oil
Accumulation”, O&GJ, January 48, 2014.
5 James Mason, “Marcellus Shale Gas Play: Production and Price Dynamics”, O&GJ, Jan. 04, 2012.
6 Mark Kaiser and Yunke Yu, “ Haynesville Update –Low Gas Price Constrains Profitability”,
O&GJ, Feb.03, 2014.
7 John Browning et al, “Study Develops Fayetteville Shale Reserves, Production Forecast”,
O&GJ, Jan. 06, 2014.
8..Rafael Sandrea and George Peels, “Algorithm Provides New EUR Estimates for US Shale Plays”,
August 04, 2014.
9 John Browning et al, “ Barnett Shale Model – Study Develops Decline Analysis, Geologic
Parameters for Reserves, Production Forecast”, O&GJ, August 05, 2013.
10 Don Warlick, “Three Tiers of US Shale Plays”, O&GFJ, August, 2013.
11..Troy A. Cook, “ Procedure for Calculating Estimated Ultimate Recovery of Bakken and Three Forks
Formations Horizontal Wells in the Williston Basin”, USGS Report 2013-1109.
12..“An Old Formula may Overstate Oil Supplies”, Bloomberg Businessweek, April 07, 2014
11