Overview of Tight Oil/Shale Oil Worldwide
A Global Perspective for IOR and Primary in Unconventional Tight Oil and Gas Reservoirs Richard Baker May-13
1
Conclusions 1. There has been tremendous growth in tight oil and gas rates and reserves. 2. Despite the rapid oil rate well counts and wells drill in major plays are constant. 3. It is extremely difficult to forecast the future oil production because the classic “S” shaped growth curve and the Resource pyramid. 4. It is my opinion that growth in tight oil will level off • •
Constant well counts (constant production profiles) Decreasing liquids from gas (CGR ↓ )
Conclusions 5. Most of these shale plays are not really shales rather they are very low permeability plays (0.01 to 0.1 mD) 6. Estimates of recoverable oil in volumetric basis are too high. 7. Pay Cut offs are way too pessimistic
General Observations Reservoir permeability is often higher than air
permeability (small fractures contributing) inflow tests and pressure transient analysis Most of the times we have more hydraulically induced fractures than we need No strong correlation between number of induced fractures and IP or reserves number of induced fractures and IP or reserves but near wellbore permeability is huge variable
This may only be true for tight oil ( true shale gas???)
4
Presentation Flow
Big picture (countries) Medium size picture (basins) Small picture (wells) Summary
5
Making Forecast using historical data • Forecasting like this is a bit like only looking at the rudder
and determining where the boat goes – Wind + waves
6
Beware of all forecasts with developing plays/technology • Most shale oil and shale gas wells have only few years
production • Most shale plays are developed in sweet spots first • Shale plays are large areally and only portions of fields have been developed • Technology advancements will impact plays
U.S. Shale Gas and Shale Oil PlaysReview of Emerging Resources: July 2011
CAUTION STATEMENT 7
(big picture)
USA AND CANADIAN OIL RATE TRENDS 8
USA Oil and Liquids forecast from IEA July 2011
USA Oil + Liquids Production US EIA website 14000
U.S. Oil Production Jan 1994 - Jan 2013 12000
Thousands of Barrels/day
10000
8000 US Total Oil Production Crude Oil, NGPL, and Other 6000
Natural Gas Plant Liquids
4000
2000
0 1993
1997
2001
Year 2005
2009
2013
USA Oil + Liquids Production US EIA website 14000
U.S. Oil Production Jan 1994 - Jan 2013 Oil+ liq. 11.8 MM bbl/d
12000
Thousands of Barrels/day
10000
Oil+ liq. 8.5 MM bbl/d
8000
US Total Oil Production Crude Oil, NGPL, and Other 6000
Natural Gas Plant Liquids
4000
Initially liquids from gas wells Now growth from oil wells
2000
0 1993
1997
2001
Year 2005
2009
2013
CAN Historical Oil Production Mining 756000 bbl/day (2010) In-Situ stm 704000 bbl/day (2010)
Source Geoscout
All wells Canada
13
Ends in 2012
Canadian Oil Production from Hz with 5 or more fractures….includes SAGD
(medium size picture)
BASIN ANALYSIS
15
16 ©
Source; Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays July 2011
15%
Δqo= 1.6 MMbbl/d 14%
15% 7%
17
Summary of Liquids Production (oil + ngl) vs. Year Source; USA EIA
Sum of Annual Liquid Column Labels Row Labels 2005 2006 2007 2008 2009 2010 2011 2012 2013 Grand Total
18
BARNET EAGLE HAYNESVILL MARCELLUS NIOBRAR WOODFOR BAKKEN T FORD E /SH/ A D Grand Total 7,368,710 86,401 7,455,111 13,951,603 20,288 98,416 14,070,307 19,183,264 87,996 63,122 11,558 19,345,940 36,316,578 82,635 64,407 89,034 144,348 36,697,002 57,047,968 94,663 122,849 139 160,498 237,092 57,663,209 90,898,597 133,181 1,512,296 138 1,029,022 334,521 93,907,755 176,433,42 127,302,933 79,384 42,381,008 48,851 5,689,780 931,469 5 355,484,11 206,717,003 70,601 136,225,971 3,732 53,450 10,744,646 1,668,710 3 34,203,131 3,961 13,815,503 912,971 1,157 48,936,723 809,993,58 592,989,787 572,709 194,122,034 3,732 102,578 18,873,890 3,328,855 5
206 MMbbl
136 MMbbl
206/355 = 58%
= 38%
10 MMbbl = 3%
U.S. Shale Basins – 862 Tcf & 24 BBO TRR (TRR -Technically Recoverable Resources by EIA)
McClure
Wolfcamp
23 Significant Shale Basins in U.S. - over 55,000 producing wells 19
© 2013 Baker Hughes Incorporated. All Rights Reserved.
660 M bbl/d
Source: Baker Hughes 20
© 2013 Baker Hughes Incorporated. All Rights Reserved.
520 M bbl/d
Rising oil Decreasing gas
Source: Baker Hughes 21
© 2013 Baker Hughes Incorporated. All Rights Reserved.
19 M bbl/d
Decreasing oil Decreasing gas
Source: Baker Hughes 22
© 2013 Baker Hughes Incorporated. All Rights Reserved.
Note rapid decline in production
Rig Count (~drilled wells)
Jan. 2012 © 23 2012 Baker Hughes Incorporated. All Rights Reserved.
Jan. 2013
Major Shale Oil Play Data Comparison PLAY
BAKKEN
EAGLE FORD
NIOBRARA
UTICA
Depth, ft
8,500 – 10,400
4,000 - 12,000
3,000 – 14,000
2,000 – 14,000
Thickness, ft
8 - 14
300 - 475
50 - 300
70 - 500
Up to 0.13 md
0.1 - 1 md
0.0003 md
0.05 md @
Permeability, md Middle Bakken IP Rate, BOPD
200 – 1,800
250 – 1,500
+/- 600
1,000 Bopd + 6 MMcfd
Avg Lateral, ft
10,000+
5,000 – 7,000
3,300 – 10,000
5,500 – 7,500
Resources, BBO
4.5 (est to 20)
3.5
1.5
3.0 (est to 5.5)
Niobrara and Utica very “early” data Resources = Technically Recoverable (TRR) Source: EIA 24
© 2013 Baker Hughes Incorporated. All Rights Reserved.
Definitions of Low Permeability vs. Shale Permeability
© 25 2012 Baker Hughes Incorporated. All Rights Reserved.
Major Shale Oil Play Data Comparison PLAY
BAKKEN
EAGLE FORD
NIOBRARA
UTICA
Depth, ft
8,500 – 10,400
4,000 - 12,000
3,000 – 14,000
2,000 – 14,000
Thickness, ft
8 - 14
300 - 475
50 - 300
70 - 500
Up to 0.13 md
0.1 - 1 md
0.0003 md
250 – 1,500
+/- 600
1,000 Bopd + 6 MMcfd
0.05 md @
Permeability, md Middle Bakken IP Rate, BOPD
Avg Lateral, ft
200 – 1,800
10,000+
Classification of reservoir4.5 type Resources, BBO by absolute permeability. (est From to 20) Golan (1991).
Niobrara and Utica very “early” data
Permeability Classification 5,000 – 7,000
© 2013 Baker Hughes Incorporated. All Rights Reserved.
3,300 – 10,000
Very low
3.5 Low Average High
Very high Resources = Technically Recoverable (TRR) Source: EIA 26
Permeability (mD)
5,500 – 7,500 < 0.01
1.5
3.0 (est to 5.5)
0.01 – 1 1 – 100
100 – 10000 > 10000
Sample of Pembina Cardium Multi-Frac’d Wells ~65% decline rate in first year, shallow decline after that Initial rates show large scatter but similar decline trend
Total trend 81 wells
USA BAKKEN OIL RATE
~Arithmetic average~200bbl/d
28
ABCs of Reservoir and Well Dynamics: Controlling Factors •Completion •Fractures •Near wellbore permeability
•Pressure support •Drive mechanism •Far field permeability
Oil rates
time First year production
ABCs of Reservoir and Well Dynamics: Controlling Factors •Completion •Fractures •Near wellbore permeability
•Pressure support •Drive mechanism •Far field permeability
Oil rates
time First year production
Decline rate is steep ~65%/yr in first year, generally caused by: Transient effects Pressure depletion Increasing gas saturation Secondary recovery will become critical to maintain a higher plateau oil rate Lack of drive energy
Checks and Balances Use available data in many ways:
• Model Building – Image logs – Fracture reports – Shale petrophysics – Mechanical properties – Formation structure – Well geometry – Fluid characterization
31
• Model Validation – Microseismic – Tracer surveys – Production logging – Minifrac – Transient tests – Production rates and pressures
Finite difference numerical options • Can capture most flow dynamics • Need to be oriented along principle stresses
Micro Seismic Data MFrac simulations
a. Tartan Grid (SPE 125530) b. Variable Frac Conductivity (SPE 135262)
c. Affected Rock Volume Modeling (SPE 138134)
32
d. Shale Engineering (SPE 146912*)
Advanced Reservoir Engineering for Shales Shale Engineering
In-Place Description
Cash flows
Shale Engineering Modeling Based on geo-mechanics
Flow Physics Pressure-dependent properties Matches observed performance Interprets and implements micro-seismic
Optimizes well design and field development Provides early predictions of long term production behavior 33
Based on: CSUG/SPE 146912
What are the lessons learned from Fracture Diagnostics and Reservoir Simulation • Permeability is controlling factor – Primary – waterflood • In lower permeability formations natural fractures increase
permeability • Pay cut offs are way too high • Reservoir drive energy is late stage controlling factor
34
With new technology
HISTORIC GROWTH CURVES
Historic Growth Curves (organic growth)
36 Hughes Incorporated. All Rights Reserved. © 2012 Baker
Historic Growth Curves (organic growth) Only so many good fields/infrastructure/political limitations
Rapid growth Best fields being exploited
Few operators + not much experience 37 Hughes Incorporated. All Rights Reserved. © 2012 Baker
Reservoir depletion
US Thermal EOR Production Data (mainly California) Source: Strosur (2003) till 1994, Conservation Committee of California Oil and Gas Producers till 2003, DOE report till 2008 and Mohan et al (2011). 700
Thermal EOR Production 1000 bbls/day
Rapid growth 600 Best fields being exploited
Limitations on number good fields/infrasture
500
400
Reservoir depletion
300
200
Few operators + not much experience
100
0 1980
1985
1990
1995
2000 Year
2005
2010
2015
Historic Growth Curves (organic growth) Only so many good fields/infrastructure/political limitations
Rapid growth Best fields being exploited
Few operators + not much experience 39 Hughes Incorporated. All Rights Reserved. © 2012 Baker
Reservoir depletion
Note Oil rate Growth in West Texas ``s`` shaped curve in 1950’s
draft for discussion purposes only
5/27
40
Oil Production from Saskatchewan’s Horizontal Wells PTAC Report 2006 Flat plateau; decreasing costs + more poor res. quality
130 Mstb/d
Growth has been achieved by using horizontal wells 5/27/2013
draft for discussion purposes only
41
Alberta Tar Sands
750 MSTB/d Not including Cold Lake + >150 Approximately ~900 MSTB per day
Note Field Pilots, note growth oil rate 5/27/2013
draft for discussion purposes only
42
Most growth in CO2 occurred in a low price environment… US CO2 EOR Growth (2004$)
Price collapse
250
80
200
70
First large field tests
60 50
150
40 100
30 20
50
'World' Oil Price (2004$) / # of Projects
Monthly CO2 EOR Oil Production (1000 bbls/d)
infrastructure
10 0
19 7 19 2 7 19 3 19 74 7 19 5 7 19 6 7 19 7 7 19 8 19 79 8 19 0 8 19 1 8 19 2 8 19 3 19 84 8 19 5 8 19 6 8 19 7 8 19 8 19 89 9 19 0 9 19 1 9 19 2 9 19 3 19 94 9 19 5 9 19 6 9 19 7 9 19 8 20 99 0 20 0 0 20 1 0 20 2 0 20 3 20 04 0 20 5 06
0
Year Monthly CO2 Production (1000 bbls/d)
World Oil Price
# of Projects
J. Shaw EOR Presentation April 7, 2006 (Calgary EOR Forum) and WTRG Economics 5/27/2013
draft for discussion purposes only
43
There is always a much larger lower quality resources compared to high quality resources
5/27/2013 44
draft for discussion purposes only
USA Oil + Liquids Production US EIA website plus RB view 14000
U.S. Oil Production Jan 1994 - Jan 2013 12000
Why constant well Count + infrastructure
Thousands of Barrels/day
10000
8000 US Total Oil Production Crude Oil, NGPL, and Other 6000
Natural Gas Plant Liquids
4000
2000
0 1993
1997
2001
Year 2005
2009
2013
Conclusions The future forecast is sensitive to; – Oil price and – Technology – Pressure support
Not in that order
The future of tight oil forecast is a function of IP, decline rate and plateau oil rate of individual wells • Geology • Completion, well length • OOIP
Shale Oil Development Requires Large Number of Wells
46
US Tight/Shale Oil Basins An overiview
Fabián Vera (FVR) Reservoir Engineer | Unconventional Resources Team
References • Kennedy, Robert. US Shale Basin Overview. Lecture given at Shale Academy. Februrary 2013. Internal document
• http://texasalliance.org/admin/assets/Eagle_Ford_Shale_Overview_by_Ramona_Hove y,_Drilling_Info.pdf @ 03/07/2013 • http://certmapper.cr.usgs.gov/data/noga95/prov38/text/prov38.pdf @ 03/07/2013 • http://www.epa.ohio.gov/portals/30/Brownfield_Conference/docs/Presentations/1BGeology%20Updates.pdf @ 03/07/2013
48
© 2013 Baker Hughes Incorporated. All Rights Reserved.
1
Conclusions 1. There has been tremendous growth in tight oil and gas rates and reserves. 2. Despite the rapid oil rate well counts and wells drill in major plays are constant. 3. It is extremely difficult to forecast the future oil production because the classic “S” shaped growth curve and the Resource pyramid. 4. It is my opinion that growth in tight oil will level off • •
Constant well counts (constant production profiles) Decreasing liquids from gas (CGR ↓ )
Conclusions 5. Most of these shale plays are not really shales rather they are very low permeability plays (0.01 to 0.1 mD) 6. Estimates of recoverable oil in volumetric basis are too high. 7. Pay Cut offs are way too pessimistic
General Observations Reservoir permeability is often higher than air
permeability (small fractures contributing) inflow tests and pressure transient analysis Most of the times we have more hydraulically induced fractures than we need No strong correlation between number of induced fractures and IP or reserves number of induced fractures and IP or reserves but near wellbore permeability is huge variable
This may only be true for tight oil ( true shale gas???)
4
Presentation Flow
Big picture (countries) Medium size picture (basins) Small picture (wells) Summary
5
Making Forecast using historical data • Forecasting like this is a bit like only looking at the rudder
and determining where the boat goes – Wind + waves
6
Beware of all forecasts with developing plays/technology • Most shale oil and shale gas wells have only few years
production • Most shale plays are developed in sweet spots first • Shale plays are large areally and only portions of fields have been developed • Technology advancements will impact plays
U.S. Shale Gas and Shale Oil PlaysReview of Emerging Resources: July 2011
CAUTION STATEMENT 7
(big picture)
USA AND CANADIAN OIL RATE TRENDS 8
USA Oil and Liquids forecast from IEA July 2011
USA Oil + Liquids Production US EIA website 14000
U.S. Oil Production Jan 1994 - Jan 2013 12000
Thousands of Barrels/day
10000
8000 US Total Oil Production Crude Oil, NGPL, and Other 6000
Natural Gas Plant Liquids
4000
2000
0 1993
1997
2001
Year 2005
2009
2013
USA Oil + Liquids Production US EIA website 14000
U.S. Oil Production Jan 1994 - Jan 2013 Oil+ liq. 11.8 MM bbl/d
12000
Thousands of Barrels/day
10000
Oil+ liq. 8.5 MM bbl/d
8000
US Total Oil Production Crude Oil, NGPL, and Other 6000
Natural Gas Plant Liquids
4000
Initially liquids from gas wells Now growth from oil wells
2000
0 1993
1997
2001
Year 2005
2009
2013
CAN Historical Oil Production Mining 756000 bbl/day (2010) In-Situ stm 704000 bbl/day (2010)
Source Geoscout
All wells Canada
13
Ends in 2012
Canadian Oil Production from Hz with 5 or more fractures….includes SAGD
(medium size picture)
BASIN ANALYSIS
15
16 ©
Source; Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays July 2011
15%
Δqo= 1.6 MMbbl/d 14%
15% 7%
17
Summary of Liquids Production (oil + ngl) vs. Year Source; USA EIA
Sum of Annual Liquid Column Labels Row Labels 2005 2006 2007 2008 2009 2010 2011 2012 2013 Grand Total
18
BARNET EAGLE HAYNESVILL MARCELLUS NIOBRAR WOODFOR BAKKEN T FORD E /SH/ A D Grand Total 7,368,710 86,401 7,455,111 13,951,603 20,288 98,416 14,070,307 19,183,264 87,996 63,122 11,558 19,345,940 36,316,578 82,635 64,407 89,034 144,348 36,697,002 57,047,968 94,663 122,849 139 160,498 237,092 57,663,209 90,898,597 133,181 1,512,296 138 1,029,022 334,521 93,907,755 176,433,42 127,302,933 79,384 42,381,008 48,851 5,689,780 931,469 5 355,484,11 206,717,003 70,601 136,225,971 3,732 53,450 10,744,646 1,668,710 3 34,203,131 3,961 13,815,503 912,971 1,157 48,936,723 809,993,58 592,989,787 572,709 194,122,034 3,732 102,578 18,873,890 3,328,855 5
206 MMbbl
136 MMbbl
206/355 = 58%
= 38%
10 MMbbl = 3%
U.S. Shale Basins – 862 Tcf & 24 BBO TRR (TRR -Technically Recoverable Resources by EIA)
McClure
Wolfcamp
23 Significant Shale Basins in U.S. - over 55,000 producing wells 19
© 2013 Baker Hughes Incorporated. All Rights Reserved.
660 M bbl/d
Source: Baker Hughes 20
© 2013 Baker Hughes Incorporated. All Rights Reserved.
520 M bbl/d
Rising oil Decreasing gas
Source: Baker Hughes 21
© 2013 Baker Hughes Incorporated. All Rights Reserved.
19 M bbl/d
Decreasing oil Decreasing gas
Source: Baker Hughes 22
© 2013 Baker Hughes Incorporated. All Rights Reserved.
Note rapid decline in production
Rig Count (~drilled wells)
Jan. 2012 © 23 2012 Baker Hughes Incorporated. All Rights Reserved.
Jan. 2013
Major Shale Oil Play Data Comparison PLAY
BAKKEN
EAGLE FORD
NIOBRARA
UTICA
Depth, ft
8,500 – 10,400
4,000 - 12,000
3,000 – 14,000
2,000 – 14,000
Thickness, ft
8 - 14
300 - 475
50 - 300
70 - 500
Up to 0.13 md
0.1 - 1 md
0.0003 md
0.05 md @
Permeability, md Middle Bakken IP Rate, BOPD
200 – 1,800
250 – 1,500
+/- 600
1,000 Bopd + 6 MMcfd
Avg Lateral, ft
10,000+
5,000 – 7,000
3,300 – 10,000
5,500 – 7,500
Resources, BBO
4.5 (est to 20)
3.5
1.5
3.0 (est to 5.5)
Niobrara and Utica very “early” data Resources = Technically Recoverable (TRR) Source: EIA 24
© 2013 Baker Hughes Incorporated. All Rights Reserved.
Definitions of Low Permeability vs. Shale Permeability
© 25 2012 Baker Hughes Incorporated. All Rights Reserved.
Major Shale Oil Play Data Comparison PLAY
BAKKEN
EAGLE FORD
NIOBRARA
UTICA
Depth, ft
8,500 – 10,400
4,000 - 12,000
3,000 – 14,000
2,000 – 14,000
Thickness, ft
8 - 14
300 - 475
50 - 300
70 - 500
Up to 0.13 md
0.1 - 1 md
0.0003 md
250 – 1,500
+/- 600
1,000 Bopd + 6 MMcfd
0.05 md @
Permeability, md Middle Bakken IP Rate, BOPD
Avg Lateral, ft
200 – 1,800
10,000+
Classification of reservoir4.5 type Resources, BBO by absolute permeability. (est From to 20) Golan (1991).
Niobrara and Utica very “early” data
Permeability Classification 5,000 – 7,000
© 2013 Baker Hughes Incorporated. All Rights Reserved.
3,300 – 10,000
Very low
3.5 Low Average High
Very high Resources = Technically Recoverable (TRR) Source: EIA 26
Permeability (mD)
5,500 – 7,500 < 0.01
1.5
3.0 (est to 5.5)
0.01 – 1 1 – 100
100 – 10000 > 10000
Sample of Pembina Cardium Multi-Frac’d Wells ~65% decline rate in first year, shallow decline after that Initial rates show large scatter but similar decline trend
Total trend 81 wells
USA BAKKEN OIL RATE
~Arithmetic average~200bbl/d
28
ABCs of Reservoir and Well Dynamics: Controlling Factors •Completion •Fractures •Near wellbore permeability
•Pressure support •Drive mechanism •Far field permeability
Oil rates
time First year production
ABCs of Reservoir and Well Dynamics: Controlling Factors •Completion •Fractures •Near wellbore permeability
•Pressure support •Drive mechanism •Far field permeability
Oil rates
time First year production
Decline rate is steep ~65%/yr in first year, generally caused by: Transient effects Pressure depletion Increasing gas saturation Secondary recovery will become critical to maintain a higher plateau oil rate Lack of drive energy
Checks and Balances Use available data in many ways:
• Model Building – Image logs – Fracture reports – Shale petrophysics – Mechanical properties – Formation structure – Well geometry – Fluid characterization
31
• Model Validation – Microseismic – Tracer surveys – Production logging – Minifrac – Transient tests – Production rates and pressures
Finite difference numerical options • Can capture most flow dynamics • Need to be oriented along principle stresses
Micro Seismic Data MFrac simulations
a. Tartan Grid (SPE 125530) b. Variable Frac Conductivity (SPE 135262)
c. Affected Rock Volume Modeling (SPE 138134)
32
d. Shale Engineering (SPE 146912*)
Advanced Reservoir Engineering for Shales Shale Engineering
In-Place Description
Cash flows
Shale Engineering Modeling Based on geo-mechanics
Flow Physics Pressure-dependent properties Matches observed performance Interprets and implements micro-seismic
Optimizes well design and field development Provides early predictions of long term production behavior 33
Based on: CSUG/SPE 146912
What are the lessons learned from Fracture Diagnostics and Reservoir Simulation • Permeability is controlling factor – Primary – waterflood • In lower permeability formations natural fractures increase
permeability • Pay cut offs are way too high • Reservoir drive energy is late stage controlling factor
34
With new technology
HISTORIC GROWTH CURVES
Historic Growth Curves (organic growth)
36 Hughes Incorporated. All Rights Reserved. © 2012 Baker
Historic Growth Curves (organic growth) Only so many good fields/infrastructure/political limitations
Rapid growth Best fields being exploited
Few operators + not much experience 37 Hughes Incorporated. All Rights Reserved. © 2012 Baker
Reservoir depletion
US Thermal EOR Production Data (mainly California) Source: Strosur (2003) till 1994, Conservation Committee of California Oil and Gas Producers till 2003, DOE report till 2008 and Mohan et al (2011). 700
Thermal EOR Production 1000 bbls/day
Rapid growth 600 Best fields being exploited
Limitations on number good fields/infrasture
500
400
Reservoir depletion
300
200
Few operators + not much experience
100
0 1980
1985
1990
1995
2000 Year
2005
2010
2015
Historic Growth Curves (organic growth) Only so many good fields/infrastructure/political limitations
Rapid growth Best fields being exploited
Few operators + not much experience 39 Hughes Incorporated. All Rights Reserved. © 2012 Baker
Reservoir depletion
Note Oil rate Growth in West Texas ``s`` shaped curve in 1950’s
draft for discussion purposes only
5/27
40
Oil Production from Saskatchewan’s Horizontal Wells PTAC Report 2006 Flat plateau; decreasing costs + more poor res. quality
130 Mstb/d
Growth has been achieved by using horizontal wells 5/27/2013
draft for discussion purposes only
41
Alberta Tar Sands
750 MSTB/d Not including Cold Lake + >150 Approximately ~900 MSTB per day
Note Field Pilots, note growth oil rate 5/27/2013
draft for discussion purposes only
42
Most growth in CO2 occurred in a low price environment… US CO2 EOR Growth (2004$)
Price collapse
250
80
200
70
First large field tests
60 50
150
40 100
30 20
50
'World' Oil Price (2004$) / # of Projects
Monthly CO2 EOR Oil Production (1000 bbls/d)
infrastructure
10 0
19 7 19 2 7 19 3 19 74 7 19 5 7 19 6 7 19 7 7 19 8 19 79 8 19 0 8 19 1 8 19 2 8 19 3 19 84 8 19 5 8 19 6 8 19 7 8 19 8 19 89 9 19 0 9 19 1 9 19 2 9 19 3 19 94 9 19 5 9 19 6 9 19 7 9 19 8 20 99 0 20 0 0 20 1 0 20 2 0 20 3 20 04 0 20 5 06
0
Year Monthly CO2 Production (1000 bbls/d)
World Oil Price
# of Projects
J. Shaw EOR Presentation April 7, 2006 (Calgary EOR Forum) and WTRG Economics 5/27/2013
draft for discussion purposes only
43
There is always a much larger lower quality resources compared to high quality resources
5/27/2013 44
draft for discussion purposes only
USA Oil + Liquids Production US EIA website plus RB view 14000
U.S. Oil Production Jan 1994 - Jan 2013 12000
Why constant well Count + infrastructure
Thousands of Barrels/day
10000
8000 US Total Oil Production Crude Oil, NGPL, and Other 6000
Natural Gas Plant Liquids
4000
2000
0 1993
1997
2001
Year 2005
2009
2013
Conclusions The future forecast is sensitive to; – Oil price and – Technology – Pressure support
Not in that order
The future of tight oil forecast is a function of IP, decline rate and plateau oil rate of individual wells • Geology • Completion, well length • OOIP
Shale Oil Development Requires Large Number of Wells
46
US Tight/Shale Oil Basins An overiview
Fabián Vera (FVR) Reservoir Engineer | Unconventional Resources Team
References • Kennedy, Robert. US Shale Basin Overview. Lecture given at Shale Academy. Februrary 2013. Internal document
• http://texasalliance.org/admin/assets/Eagle_Ford_Shale_Overview_by_Ramona_Hove y,_Drilling_Info.pdf @ 03/07/2013 • http://certmapper.cr.usgs.gov/data/noga95/prov38/text/prov38.pdf @ 03/07/2013 • http://www.epa.ohio.gov/portals/30/Brownfield_Conference/docs/Presentations/1BGeology%20Updates.pdf @ 03/07/2013
48
© 2013 Baker Hughes Incorporated. All Rights Reserved.
