Embed Size (px)
DESCRIPTION
A series of graphs and maps detailing production of shale gas and shale oil (tight oil) in the US, based on an analysis of over 63,000 wells in every shale play in the country.The full report can be found at shalebubble.org/drill-baby-drill.
Citation preview
0
500
1000
1500
2000
2500
2005 2010 2015 2020 2025
Thou
sand
Bar
rels
per
Day
Year
Eagle Ford
Bakken
All Other Plays
DRILL, BABY, DRILL CAN UNCONVENTIONAL FUELS USHER IN A NEW ERA
OF ENERGY ABUNDANCE?
J. David Hughes February 2013
Production Figures & Maps
Shale Gas & Tight Oil
(Data from EIA updated to September, 2011; http://www.eia.gov/oil_gas/rpd/shale_gas.jpg )
Shale gas production by play, 2000 through May 2012
(data from DIdesktop, September, 2012, fitted with 3 month centered moving average including data up to June, 2012)
0
5
10
15
20
25
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Billi
on C
ubic
Fee
t per
Day
Year
Other Austin Chalk Bone Spring Bossier Antrim Niobrara Bakken Woodford Eagle Ford Fayetteville Marcellus Barnett Haynesville
Barnett Haynesville
Shale gas produc/on appears to be plateauing as of late 2011.
0
1
2
3
4
5
6
7
Billi
on C
ubic
Fee
t per
Day
Shale Play
Shale gas production by play, May 2012
(data from DI Desktop, September, 2012, for production in most cases through May-June, 2012)
Top 3 Plays: 66% of Total Top 6 Plays: 88% of Total
0
500
1000
1500
2000
2500
3000
0
1
2
3
4
5
6
7
8
9
2008 2009 2010 2011 2012
Number of Producing W
ells Pr
oduc
tion
(Bill
ion
Cubi
c Fe
et p
er D
ay)
Year
Production
Number of producing wells
Shale gas production and number of producing wells for the Hayesville play, 2008 through May 2012
(data from DI Desktop, HPDI, September, 2012)
Produc/on peaked in December 2012, despite con/nued growth in the number of opera/ng wells.
0
1000
2000
3000
4000
5000
6000
7000
8000
1 6 11 16 21 26 31 36 41 46
Gas
Prod
uctio
n (M
cf p
er D
ay)
Months on Production
Yearly Declines: First Year = 68%
Second Year = 49% Third Year = 50%
Fourth Year = 48%
Type decline curve for Haynesville shale gas wells
(data from DI Desktop, HPDI, September, 2012)
Based on data from the four years this shale play has been in produc/on.
0
10000
20000
30000
40000
50000
0 10 20 30 40 50 60 70 80 90 100
High
est M
onth
ly P
rodu
ctio
n (M
cf/d
ay)
Percentage of Wells
Distribution of well quality in the Haynesville play, as defined by the highest one-month rate of production over well life
Median = 7954 mcf/day Mean = 8201 mcf/day
The x-‐axis indicates the cumula/ve percentage of wells, ordered from lowest to highest quality. The highest one-‐month rate of produc/on is typically achieved in the first or second month aGer well comple/on.
0
200
400
600
800
1000
1200
1400
1600
1800
2000
0
1
2
3
4
5
6
2008 2009 2010 2011 2012
Number of Operating pre-2011 W
ells Gas
Prod
uctio
n (B
illio
n cu
bic
feet
/day
)
Year
Production from pre-2011 wells Number of pre-2011 wells
Overall field decline for the Haynesville play, based on production from wells drilled prior to 2011
(data from DI Desktop, HPDI, September, 2012)
Overall Field Decline = 52%
In order to offset the 52 percent decline rate for the field, 774 new wells producing at 2011 rates are required.
Haynesville Well Quality - Top 20% with Highest One Month Production of >10989 mcf/day in black
20 miles
30 miles
0
2000
4000
6000
8000
10000
12000
14000
16000
0
1
2
3
4
5
6
7 Num
ber of Producing Wells
Prod
uctio
n (B
illio
n Cu
bic
Feet
per
Day
)
Year
Production Number of producing wells
Shale gas production and number of producing wells for the Barnett shale play, 2000 through May 2012
(data from DI Desktop, HPDI, September, 2012)
Produc/on plateaued in December 2012, despite con/nued growth in the number of opera/ng wells
0
200
400
600
800
1000
1200
1400
1600
1 6 11 16 21 26 31 36 41 46 51 56
Gas
Prod
uctio
n (M
cf p
er D
ay)
Months on Production
Yearly Declines: First Year = 61%
Second Year = 32% Third Year = 24%
Fourth Year = 18% Fifth Year = 15%
Type decline curve for Barnett shale gas wells
(data from DI Desktop, HPDI, September, 2012)
Based on data from the most recent five years of this play’s produc/on.
0
2000
4000
6000
8000
10000
12000
0 10 20 30 40 50 60 70 80 90 100
High
est M
onth
ly P
rodu
ctio
n (M
cf/d
ay)
Percentage of Wells
Distribution of well quality in the Barnett play, as defined by the highest one-month rate of production over well life
Median = 1332 mcf/day Mean = 1619 mcf/day
The x-‐axis indicates the cumula/ve percentage of wells, ordered from lowest to highest quality. The highest one-‐month rate of produc/on is typically achieved in the first or second month aGer well comple/on.
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
0
1
2
3
4
5
6
7
2006 2007 2008 2009 2010 2011 2012
Number of Operating pre-2011 W
ells Gas
Prod
uctio
n (B
illio
n cu
bic
feet
/day
)
Year
Production from pre-2011 wells
Number of pre-2011 wells
Overall field decline for the Barnett play based on production from wells drilled prior to 2011
(data from DI Desktop, HPDI, September, 2012)
Overall Field Decline = 30%
In order to offset the 30 percent decline rate for the field, 1,507 new wells producing at 2011 rates are required.
Barnett Well Quality - Top 20% with Highest One-Month Production of >2436 mcf/day in black
30 miles
5 miles
2 miles
0
500
1000
1500
2000
2500
3000
3500
4000
4500
0
1
2
3
4
5
2006 2007 2008 2009 2010 2011
Number of Producing W
ells Pr
oduc
tion
(Bill
ion
Cubi
c Fe
et p
er D
ay)
Year
Production Number of producing wells
Shale gas production and number of producing wells for the Marcellus shale play, 2006 through December 2011
(data from DI Desktop, HPDI, September, 2012)
The steep growth in produc/on during and aGer 2009 reflects the applica/on of mul/-‐stage horizontal fracturing technology.
0
200
400
600
800
1000
1200
1400
1600
1800
2000
1 6 11 16 21 26 31 36 41 46
Gas
Prod
uctio
n (M
cf p
er D
ay)
Months on Production
Yearly Declines: First Year = 47%
Second Year = 66% Third Year = 71%
Fourth Year = 47%
Type decline curve for Marcellus shale gas wells.
(data from DI Desktop, HPDI, September, 2012)
Based on data from the most recent four years of this play’s produc/on.
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
0 10 20 30 40 50 60 70 80 90 100
High
est M
onth
ly P
rodu
ctio
n (M
cf/d
ay)
Percentage of Wells
Distribution of well quality in the Marcellus play, as defined by the highest one-month rate of production over well life
Median = 1133 mcf/day Mean = 1947 mcf/day
The x-‐axis indicates the cumula/ve percentage of wells, ordered from lowest to highest quality. The highest one-‐month rate of produc/on is typically achieved in the first or second month aGer well comple/on.
0
500
1000
1500
2000
2500
3000
0
0.5
1
1.5
2
2.5
2006 2007 2008 2009 2010 2011
Number of Operating pre-2011 W
ells Gas
Prod
uctio
n (B
illio
n cu
bic
feet
/day
)
Year
Production from pre-2011 wells Number of pre-2011 wells
Overall field decline for the Marcellus play based on production from wells drilled prior to 2011
(data from DI Desktop, HPDI, September, 2012)
Overall Field Decline = 29%
In order to offset the 29 percent decline rate for the field, 561 new wells producing at 2011 rates are required.
Marcellus Well Quality - Top 20% with Highest One-Month Production of >3603 mcf/day in black
100 miles
20 miles
30 miles
0
5
10
15
20
25
May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12
Billi
on C
ubic
Fee
t per
Day
Year
Other Austin Chalk Bone Spring Bossier Antrim Niobrara Bakken Woodford Eagle Ford Fayetteville Marcellus Barnett Haynesville
Shale gas production by play, May 2011 through May 2012
(data from DIdesktop, September, 2012, fitted with 3 month centered moving average including data up to June, 2012)
Barnett
Haynesville
Marcellus
Fayetteville
Eagle Ford Woodford
Shale gas produc/on clearly peaked in December 2011 and is now on an undula/ng plateau.
0
200
400
600
800
1000
1200
1400
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Thou
sand
Bar
rels
per
Day
Year
Other Woodford Marcellus Monterey-Tremblor Austin Chalk Spraberry Barnett Permian Delaware Midland Granite Wash Niobrara Bone Spring Eagle Ford Bakken
Tight oil production by play, 2000 through May 2012
Bakken
(data from DIdesktop, September, 2012, fitted with 3 month centered moving average including data up to June, 2012)
Together the Bakken and Eagle Ford comprise 81 percent of /ght oil produc/on.
0
100
200
300
400
500
600
Thou
sand
Bar
rels
per
Day
Shale Play
Tight oil production by play, May 2012
(data from DI Desktop/HPDI, September, 2012, for production in most cases through May-June, 2012)
Top 2 Plays = 81% of Total Top 5 Plays = 92% of Total
0
1000
2000
3000
4000
5000
0
100
200
300
400
500
600
2000 2002 2004 2006 2008 2010 2012
Number of Producing W
ells Pr
oduc
tion
(Tho
usan
d Ba
rrels
per
Day
)
Year
Production
Number of producing wells
Tight oil production and number of producing wells for the Bakken shale play, 2000 through May 2012
(data from DI Desktop, HPDI, September, 2012)
0
50
100
150
200
250
300
350
400
450
500
0 12 24 36 48 60
Oil P
rodu
ctio
n (B
arre
ls p
er D
ay)
Months on Production
Yearly Declines: First Year = 69%
Second Year = 39% Third Year = 26%
Fourth Year = 27% Fifth Year = 33%
Type decline curve for Bakken tight oil wells
(data from DI Desktop, HPDI, September, 2012)
Based on data from the most recent 66 months of this play’s oil produc/on.
0
500
1000
1500
2000
2500
0 10 20 30 40 50 60 70 80 90 100
High
est M
onth
ly P
rodu
ctio
n (B
bls/
day)
Percentage of Wells
Distribution of well quality in the Bakken play, as defined by the highest one-month rate of production over well life
Median = 341 bbls/day Mean = 400 bbls/day
The x-‐axis indicates the cumula/ve percentage of wells, ordered from lowest to highest quality. The highest one-‐month rate of produc/on is typically achieved in the first or second month aGer well comple/on.
0
500
1000
1500
2000
2500
3000
3500
4000
0
50
100
150
200
250
300
350
400
2006 2007 2008 2009 2010 2011 2012
Number of Operating pre-2011 W
ells Oil P
rodu
ctio
n (T
hous
and
bbls
/day
)
Year
Production from pre-2011 wells Number of pre-2011 wells
Overall field decline for the Bakken play based on production from wells drilled prior to 2011
(data from DI Desktop, HPDI, September, 2012)
Overall Field Decline = 40%
In order to offset the 40 percent decline rate for the field, 819 new wells producing at 2011 rates are required.
0
2000
4000
6000
8000
10000
12000
14000
16000
0
100
200
300
400
500
600
700
800
900
1000
2000 2005 2010 2015 2020 2025
Number of Producing W
ells Pr
oduc
tion
(Tho
usan
d Ba
rrels
per
Day
)
Year
Production
Number of producing wells
Future oil production profile for the Bakken play, assuming current rate of new well additions
(data from DI Desktop, HPDI, September, 2012)
Peak 973 Kbbls/day in 2017 Locations run out in 2017 at 11725
operating wells
Assumptions: - Current drilling rate of 1500 wells/year maintained - EIA estimate of 9767 remaining locations as of 1/1/2010 is correct - Well quality is maintained at 2011 levels
This scenario assumes constant new well quality and EIA es/mate of remaining available well loca/ons. Produc/on declines at the overall field rate of 40 percent aGer peak in 2017.
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
0
200
400
600
800
1000
1200
2000 2005 2010 2015 2020 2025
Number of Producing W
ells Pr
oduc
tion
(Tho
usan
d Ba
rrels
per
Day
)
Year
Production at 1500 wells/year Production at 2000 wells/year Drilling Rate 1500 wells/year Drilling Rate 2000 wells/year
Future oil production profiles for the Bakken play, assuming current rate of well additions compared to a scenario of 2,000 new wells per year
(data from DI Desktop, HPDI, September, 2012)
Peak 973 Kbbls/day in 2017 if 1500
wells added each year
Peak 1099 Kbbls/day in 2015 if 2000
wells added each year
Both scenarios assume constant new well quality and the EIA es/mate of 11,725 total available well loca/ons. Produc/on declines aGer peak in both scenarios at the overall field rate of 40 percent.
Bakken Well Quality - Top 20% with Highest One-Month Production of >589 bbls/day in black
40 miles
Bakken Well Quality – Sweet Spot - Top 20% with Highest One Month Production of >589 bbls/day in black
20 miles
Distribution of horizontal wells in the Parshall “sweet spot” of the Bakken
3 Miles
See right-‐hand side of previous slide. This area is almost completely saturated with wells although there are s/ll a few loca/ons leG. Green symbols indicate rigs drilling as of December 17, 2012.
0
500
1000
1500
2000
2500
3000
3500
4000
0
100
200
300
400
500
600
2009 2010 2011 2012
Number of Producing W
ells Pr
oduc
tion
(Tho
usan
d Ba
rrels
per
Day
)
Year
Production
Number of producing wells
Petroleum liquids production and number of producing wells for the Eagle Ford shale play, 2009 through June 2012
(data from DI Desktop, HPDI, September, 2012)
0
50
100
150
200
250
300
350
400
1 13 25 37 49
Oil P
rodu
ctio
n (B
arre
ls p
er D
ay)
Months on Production
Production 2008-2011
Production first 5 months of 2012
Yearly Declines: First Year = 60%
Second Year = 64% Third Year = 72%
Fourth Year = 46%
Type decline curve for Eagle Ford tight oil wells
(data from DI Desktop, HPDI, September, 2012)
Based on data from the most recent 50 months through year-‐end 2011 of this play’s produc/on. Produc/on for the first five months of 2012 is also shown, indica/ng that IP’s are rising as drilling focuses on recently defined sweet spots.
0
1000
2000
3000
4000
5000
6000
7000
8000
0 10 20 30 40 50 60 70 80 90 100
High
est M
onth
ly P
rodu
ctio
n (B
bls/
day)
Percentage of Wells
Distribution of well quality in the Eagle Ford play, as defined by the highest one-month rate of production over well life
Median = 292 bbls/day Mean = 437 bbls/day
The x-‐axis indicates the cumula/ve percentage of wells, ordered from lowest to highest quality. The highest one-‐month rate of produc/on is typically achieved in the first or second month aGer well comple/on.
0
100
200
300
400
500
600
700
800
0
10
20
30
40
50
60
70
80
90
2008 2009 2010 2011 2012
Number of Operating pre-2011 W
ells Oil P
rodu
ctio
n (T
hous
and
bbls
/day
)
Year
Production from pre-2011 wells Number of pre-2011 wells
Overall field decline for the Eagle Ford play based on production from wells drilled prior to 2011
(data from DI Desktop, HPDI, September, 2012)
Overall Field Decline = 27%
The actual overall field decline is likely steeper than shown as many pre-‐2011 wells were being connected over the subsequent months as indicated by the rising well count in 2011 and 2012. If the 27 percent rate is accepted, it would require 723 new wells producing at 2011 rates to offset field decline each year from current produc/on levels.
Future liquids production profile for the Eagle Ford play assuming current rate of new well additions
(data from DI Desktop, HPDI, September, 2012)
0
2000
4000
6000
8000
10000
12000
14000
0
100
200
300
400
500
600
700
800
900
1000
2008 2013 2018 2023
Number of Producing W
ells Pr
oduc
tion
(Tho
usan
d Ba
rrels
per
Day
)
Year
Production Number of producing wells
Peak at 891 Kbbls/day in 2016
Locations run out in 2016 at 11406 operating wells
Assumptions: - Current drilling rate of 1983 wells/year maintained - Estimate of 11406 remaining locations as of 1/1/2010 is correct - Well quality is maintained at 2011 levels
This scenario assumes constant new well quality and EIA es/mate of remaining available well loca/ons. Produc/on declines at the overall field rate of 40 percent aGer peak in 2016.
Future oil production profiles for the Eagle Ford play assuming current rate of new well additions compared to a scenario of 2,500 wells per year
(data from DI Desktop, HPDI, September, 2012)
0
2000
4000
6000
8000
10000
12000
14000
16000
0
200
400
600
800
1000
1200
2008 2013 2018 2023
Number of Producing W
ells Pr
oduc
tion
(Tho
usan
d Ba
rrels
per
Day
)
Year
Production at 1983 wells/year Production at 2500 wells/year Drilling rate 1983 wells/year Drilling rate 2500 wells/year
Peak 891 Kbbls/day 2016 if 1983
wells added each year
Peak 1031 Kbbls/day In 2015 if 2500
wells added each year
Both scenarios assume constant new well quality at 2011 levels and the EIA es/mate of 11,406 total available well loca/ons.158 Produc/on declines aGer peak in both scenarios at the overall field rate of 40 percent.
Eagle Ford Well Quality - Top 20% with Highest One Month Production of >667 bbls/day in black
40 miles
20 miles
10 miles
0
200
400
600
800
1000
1200
1400
1600
1800
May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12
Thou
sand
Bar
rels
per
Day
Month
Eagle Ford Bakken Other Woodford Marcellus Monterey-Tremblor Austin Chalk Spraberry Barnett Permian Delaware Midland Granite Wash Niobrara
Tight oil production by play, May 2011 through May 2012
Bakken
(data from DIdesktop, September, 2012, fitted with 3 month centered moving average including data up to June, 2012)
Eagle Ford
Uncon. Oil
Yet to Find
The Bakken and Eagle Ford are clearly unique among /ght oil plays in the United States.
Projection of tight oil production by play in the U.S. through 2025
0
500
1000
1500
2000
2500
2005 2010 2015 2020 2025
Thou
sand
Bar
rels
per
Day
Year
Eagle Ford
Bakken
All Other Plays
Forecast
Nuclear
Gas
Coal
Hydro
Renewables
Oil
Transp
253, 234, 80
Residental
Industrial
Commercial
67, 112, 133
216, 178, 33
143, 189, 205
89, 108, 1
168, 163, 1
98, 98, 98
History
Based on vintaged type curve produc/on, the number of drilling loca/ons projected by the EIA for the Bakken and Eagle Ford plays, and the assump/on of con/nued recent growth rates in the other plays.
