Selection Criteria
Strategic Recovery in Gas Condensate Reservoirs
Assoc. Prof. Dr. Khalik M. Sabil Institute of Petroleum Engineering School of Energy, Geoscience, Infrastructure & Society (EGIS) Heriot-Watt University Malaysia
Outline Introduction Condensate Banking Issues Field Development Techniques Selection Criteria Conclusions
Introduction In an undisturbed formation, gas condensate reservoirs are found in single gas (dense) phase since the reservoir temperature is higher that its dew point pressure. The reservoir temperature must be between critical point temperature and cricondentherm of the reservoir fluid
Table 1— Composition of Gas condensate reservoirs Res. Fluid1
Res. Fluid1
Res. Fluid1
(Mole %)
(Mole %)
(Mole %)
Methane
72.31
73.19
83.2
Ethane
6.15
7.8
7.4
Propane
3.33
3.55
2.8
Butanes
2.94
2.16
1.57
Pentanes
1.77
1.32
0.88
Hexanes
1.37
1.09
0.64
Heptanes+
9.31
8.21
2.83
CO2
2.72
2.37
0.2
N2
0.1
0.31
0.48
Dew point, psia
7588
6750
4763
Res temp, oF
285
280
213.8
Components
1.
Mokhtari et al.75
2.
Ahmed et al.76
3.
Belaifa et al.23
During production, if pressure declines to the gas dew point pressure, retrograde condensation occurs resulting in liquid condensate to occur in the reservoir
A single dense phase Dew point Maximum liquid drop-out Region of retrograde condensation Dew point
Single gas phase
Can we not just blow the reservoir down ? l
If we just deplete the reservoir, will the liquids not just vapourise and therefore be produced?????
When separation occurs in the reservoir the reservoir fluid composition changes causing the mixture to get richer More condensate produced!
will
be
Condensate Banking Issues Depletion of gas condensate reservoir below the reservoir fluid dew point pressure will result in condensate banking near well-bore region
Fig. 1— A Schematic view of region near wellbore of a Gas condensate reservoir (Modified from Marokane et al., 2002)
Fig. 2 - Oil Saturation around wellbore (Fevang & Whitson, 1996)
Condensate Banking will results in: - loss of valuable condensate and increased expenditure of condensate processing topside facilities (Havlena et al., 1967) - decrease in relative permeability of gas near the well-bore region (Hinchman & Barree, 1985) - decrease in liquid mobility with the increase of condensate accumulation (HInchman & Barree, 1985 - decrease in production with the increase in the richness of the condensate and the amount of the liquid drop-out (Jamiolahmady & Danesh, 2007) - Higher skin around the wellbore due to the liquid build-up (Hashemi et al, 2004)
Decrease in well productivity!
Field Development Techniques
Fig. 4— A Flow chart of field development techniques for resolving condensate-banking issue (Sayed & Al-Muntasheri, 2014)
PRESSURE MAINTENANCE
PRESSURE MAINTENANCE Gas Cycling Working Principle: the reservoir pressure greater than the dew point pressure of the fluid by cycling the produced lean gas (Rojey, 1998)
Probably, one of the most efficient technique to improve the well productivity. 85% recovery of gas reserve is economically viable for Bodcaw Sand Cotton Valley field (Miller & Lents, 1946) better sweep of the condensate has been achieved in Arun field by the cycling operation (Afidick et al.,1994) Simulation studies shows 100% gas injection for a period of 20 years lead to recovery of 1750 MSTCM of gas for Toual field, Algeria (Belaifa et al.,2003) and maximize condensate recovery for Hassi R’Mel field (Adel et al, 2006).
Factors affecting the process: Areal Sweep; Vertical sweep
Gas Cycling Process flow diagram
CO2 Injection Working Principle: Decrease the dew point pressure of the condensate near the wellbore thus enhancing its recovery (Odi, 2012)
Huff-n-puff process: injection of CO2 near condensate banking region-closing the well producing the vaporise condensate Assist CO2 CO corrosion rate sequestration. is highest at the depth 2
where the temperature is around 167oF (Gunaltun, 1991).
Contamination of produced gas thus reducing its calorific value.
Huff-n-puff process for CO2 injection (From Odi, 2012)
Nitrogen Injection Working Principle: Similar to gas cycling, i.e, maintaining the reservoir pressure thus preventing condensate drop out (Sänger et al., 1994)
Advantages: Cheap, Non-corrosive, readily available. Major disadvantage: Liquid drop out occurs at the region where nitrogen with the condensate. Nitrogen injectionmixes on lab studies indicated a dew point pressure increase up to 6030 psig for 638 SCF of injected Nitrogen (Moses & Wilson,1981).
Requires Cryogenic processing unit.
Comparing flue gas injection cost & recovery to different gas injections by Ahmadi (2015) Gas type
Cost of capture, compression and
Injection rate (MCF/D)
transportation ($/MCF) CO2
Total cost of
Increase in oil
injection (MM$)
recovery (%OOIP)
1
38,000
486.78
5%
N2
0.8
224,000
2296
9.70%
Natural gas
3.35
50,000
2146
5%
Flue gas
0.1
280,000
358.6
11%
PRODUCTIVITY IMPROVEMENT
Horizontal well Working Principle: Horizontal wells usually have lower drawdown pressure in comparison to vertical wells hence the time taken for the reservoir fluid to reach the dew point pressure is delayed. - condensate recovery from a horizontal well can be enhanced by a factor of 1.3 (Marir & Tiab, 2006) - water breakthrough is delayed in Horizontal well thus minimizing the effect of water coning. - showed that
horizontal well is economically admirable at lower Kv/Kh ratio. (Jamiolahmady & Danesh, 200 ) - it is critical to know the exact Kv/Kh for horizontal wells in order to prevent very optimistic results (Fevang & Whitson, 1996)
Temporary solution Expensive
PI plot of Horizontal and Vertical wells for North field, Qatar (From Miller et al., 2010)
Hydraulic Fracturing Working Principle: Increases the productivity by altering the flow capacity and increasing the effective wellbore radius (Meese et al, 1994) Temporary solution Expensive
Depends on Fracture conductivity (Indriati et al., 2002) Well deliverability of a hydraulically fractured gas condensate well increases 3 times to that of unfractured well (Al-Hashim & Hashmi, 2000). Economic analysis before and after fracturing (Uzoh et al., 2010) Before fracturing
After fracturing
Payback period
203 months
8 months
Acumulative NPV (USD)
8,776,838
61,948,687
the performance could be affected by (Rahim et al., 2012):
–Reservoir heterogeneity and permeability distribution.
-Inefficient fracture length to connect the wellbore with formation. -Ineffective fracture design and conductivity. -Improper post cleanup procedure
Matrix Acidizing Working Principle: Removes the wellbore damage and create an artificial pathway for the flow of hydrocarbon from reservoir to wellbore One of the key parameter for successful acid treatment is the length of the acid penetration into the formation (Fadele et al., 2000)
HCl for carbonate reservoirs and Mud acid for Interfacial tension of alcoholic acids is low, hence can be used for tight formations (Al-Anazi et al., 2006) sandstone reservoirs Corrosion and eaction of acids Cost of placement techniques for matrix acidizing (Uzoh et al., 2010) Placement technique
Average price 2011 USD
Average improvement %
Using drilling pipe
1195 339
249
Using coiled tubing
866 181
158
Using bull heading
628 147
25
Expensive treatment
Comparison between THREE (3) Productivity Improvement Options Recovery Option
Screening
Advantages
Limitations
Improvement
Matrix acidizing
Permeability greater than 1 mD
readily available
Acid placement, corrosive nature & unstable at high temperatures
Using chemical additives & mechanical methods, pre & post treatment analysis
Hydraulic fracturing
Permeability 0.01- Efficient above & below 10mD dew point
Horizontal wells
Low kv/kh contrast
High environmental Increasing fracture half impact & long clean up length & width, pre and periods post treatment analysis
Higher recovery & rates, Expensive, difficult to low condensate drill & non uniform saturation drainage
Increasing well length, smart technology & multi stage fracturing
Chemical Injection/Reservoir Alteration
Solvent Injection Working Principle: Decrease the Interfacial tension between condensate and gas or by dissolving the solvent with the condensate
Methanol, ethanol and Isopropyl alcohol are used. Methanol is flammable in nature. Methanol treatment rise the relative gas permeability by a Temporary solution factor of 1.2-2.5 (Du et al., 2000).
Effect on gas end-point relative permeability by Methanol treatment for low permeability Limestone cores (Al-Anazi et al. (2002)
Core Perm. (mD)
Initial water saturation (Swi)
Gas relative Gas relative Gas relative perm. before perm. after first perm. after Methanol Methanol second Methanol treatment (Krg) treatment (Krg) treatment (Krg)
2.32
0
0.517
0.647
0.704
4.43 4.5
0.2 0.54
0.675 0.529
0.829 0.819
0.916 -
Effect on gas end-point relative permeability by Methanol treatment for high permeability sandstone cores
Core Perm. (mD)
Initial water saturation (Swi)
Gas relative perm. before Methanol treatment (Krg)
Gas relative Gas relative perm. after first perm. after Methanol second Methanol treatment (Krg) treatment (Krg)
246
0
0.05
0.43
0.48
378
0.38
0.02
0.21
0.3
Wettability Alteration Working Principle: wettability of the rocks are changed from liquid wettability to intermediate gas wettability through chemical injection. Fluoro-surfactants and Fluoropolymers are injected Can be implemented on high or low permeability reservoirs Flexible, robust and permanent solution Wettability alteration by use of fluorinated surfactants in solvent mixtures of isopropanol and 2-propylene glycol can result in flow conductivity increase by a factor of 2 (Bang et al., 2008).
Summary of wettability alteration using Fluoro-surfactants Note: * – Oil/gas, ** – water/gas 1 Kewen & Abbas65 2 Fahes & Firoozabadi69 70 3 Noh & Firoozabadi 4 Wu & Firoozabadi71 Type of Chemical
Formation
Perm. (mD)
754
Kansas chalk Berea sandstone
5 1000
211-12P
Berea sandstone reservoir rock
600 10
311-12P
Berea sandstone reservoir rock
500 20
4Z8
Berea sandstone reservoir rock
700 5
1FC
Temp. (°C)
Fluid conc. (% wt.)
Contact angle alteration 0o- 60o *
20
0.1
50o- 90o ** 0o- 60o *
140
140
140
2-8
50o- 150o**
4
0o- 60o * 90o150o**
0.33
0o- 80o * 50o140o**
Selection Criteria -
Development around the world Development Strategy
Selection Criteria
Cost of treatment
Field applications
Gas cycling
Gas availability and good capital
High
Arun field (Indonesia) Hassi R’Mel south field (Algeria) Toual field (Algeria)
CO2 injection
Proper storage and transportation availability for CO2
Moderate
West Australian field
Nitrogen Injection
Lack of gas availability for cycling
Cheap
Abu Dhabi field
Horizontal well
Low permeability reservoirs and heterogeneous reservoirs
High
North field, Qatar
Selection Criteria Development Strategy
Selection Criteria
Cost of treatment
Field applications
Hydraulic fracturing
High skin and tight formations
Moderate
Smorbukk field in North Sea Yamburskoe artic field in Russia
Matrix acidizing
Availability of different acids and medium to high permeability formations
Moderate
California field
Solvent injection
Availability of solvent
High
Saudi Arabian gas field
Wettability alteration
Depending on the formation the availability of chemicals
High
____
To be considered: Development Strategy Gas cycling
CO2 injection
Advantages
Disadvantages Income from gas sales is delayed, expensive if gas needs to be purchased from external Ideal technique for condensate-banking issue source, considerable investment on compressors Highly corrosive, reduces calorific value of Sequestration of CO2, reduction in pollution or produced gas, storage and transportation is greenhouse effect expensive and difficult
Nitrogen Injection
Non-corrosive, available abundantly, cheap and environmental friendly
Cost on cryogenic processing unit and liquid drop out where it mixes with condensate
Horizontal well
Lower drawdown decline rate, productivity higher than vertical well
Can be expensive, not a permanent solution
Hydraulic fracturing
Productivity better than unfractured well
Not a permanent solution and can cause formation damage
Matrix acidizing
Good productivity and acids are available cheaply
Corrosive and reaction of acids with formation
Solvent injection
Inexpensive and increases gas relative permeability
Inflammable nature of Methanol and not a permanent solution
Wettability alteration
Flexibility, reliability and permanent solution
Environmental issues and expensive
.... perhaps, a combination of methods?
24
Thank You!
Assoc. Prof. Dr. Khalik M. Sabil Institute of Petroleum Engineering School of Energy, Geoscience, Infrastructure & Society (EGIS) Heriot-Watt University Malaysia
Outline Introduction Condensate Banking Issues Field Development Techniques Selection Criteria Conclusions
Introduction In an undisturbed formation, gas condensate reservoirs are found in single gas (dense) phase since the reservoir temperature is higher that its dew point pressure. The reservoir temperature must be between critical point temperature and cricondentherm of the reservoir fluid
Table 1— Composition of Gas condensate reservoirs Res. Fluid1
Res. Fluid1
Res. Fluid1
(Mole %)
(Mole %)
(Mole %)
Methane
72.31
73.19
83.2
Ethane
6.15
7.8
7.4
Propane
3.33
3.55
2.8
Butanes
2.94
2.16
1.57
Pentanes
1.77
1.32
0.88
Hexanes
1.37
1.09
0.64
Heptanes+
9.31
8.21
2.83
CO2
2.72
2.37
0.2
N2
0.1
0.31
0.48
Dew point, psia
7588
6750
4763
Res temp, oF
285
280
213.8
Components
1.
Mokhtari et al.75
2.
Ahmed et al.76
3.
Belaifa et al.23
During production, if pressure declines to the gas dew point pressure, retrograde condensation occurs resulting in liquid condensate to occur in the reservoir
A single dense phase Dew point Maximum liquid drop-out Region of retrograde condensation Dew point
Single gas phase
Can we not just blow the reservoir down ? l
If we just deplete the reservoir, will the liquids not just vapourise and therefore be produced?????
When separation occurs in the reservoir the reservoir fluid composition changes causing the mixture to get richer More condensate produced!
will
be
Condensate Banking Issues Depletion of gas condensate reservoir below the reservoir fluid dew point pressure will result in condensate banking near well-bore region
Fig. 1— A Schematic view of region near wellbore of a Gas condensate reservoir (Modified from Marokane et al., 2002)
Fig. 2 - Oil Saturation around wellbore (Fevang & Whitson, 1996)
Condensate Banking will results in: - loss of valuable condensate and increased expenditure of condensate processing topside facilities (Havlena et al., 1967) - decrease in relative permeability of gas near the well-bore region (Hinchman & Barree, 1985) - decrease in liquid mobility with the increase of condensate accumulation (HInchman & Barree, 1985 - decrease in production with the increase in the richness of the condensate and the amount of the liquid drop-out (Jamiolahmady & Danesh, 2007) - Higher skin around the wellbore due to the liquid build-up (Hashemi et al, 2004)
Decrease in well productivity!
Field Development Techniques
Fig. 4— A Flow chart of field development techniques for resolving condensate-banking issue (Sayed & Al-Muntasheri, 2014)
PRESSURE MAINTENANCE
PRESSURE MAINTENANCE Gas Cycling Working Principle: the reservoir pressure greater than the dew point pressure of the fluid by cycling the produced lean gas (Rojey, 1998)
Probably, one of the most efficient technique to improve the well productivity. 85% recovery of gas reserve is economically viable for Bodcaw Sand Cotton Valley field (Miller & Lents, 1946) better sweep of the condensate has been achieved in Arun field by the cycling operation (Afidick et al.,1994) Simulation studies shows 100% gas injection for a period of 20 years lead to recovery of 1750 MSTCM of gas for Toual field, Algeria (Belaifa et al.,2003) and maximize condensate recovery for Hassi R’Mel field (Adel et al, 2006).
Factors affecting the process: Areal Sweep; Vertical sweep
Gas Cycling Process flow diagram
CO2 Injection Working Principle: Decrease the dew point pressure of the condensate near the wellbore thus enhancing its recovery (Odi, 2012)
Huff-n-puff process: injection of CO2 near condensate banking region-closing the well producing the vaporise condensate Assist CO2 CO corrosion rate sequestration. is highest at the depth 2
where the temperature is around 167oF (Gunaltun, 1991).
Contamination of produced gas thus reducing its calorific value.
Huff-n-puff process for CO2 injection (From Odi, 2012)
Nitrogen Injection Working Principle: Similar to gas cycling, i.e, maintaining the reservoir pressure thus preventing condensate drop out (Sänger et al., 1994)
Advantages: Cheap, Non-corrosive, readily available. Major disadvantage: Liquid drop out occurs at the region where nitrogen with the condensate. Nitrogen injectionmixes on lab studies indicated a dew point pressure increase up to 6030 psig for 638 SCF of injected Nitrogen (Moses & Wilson,1981).
Requires Cryogenic processing unit.
Comparing flue gas injection cost & recovery to different gas injections by Ahmadi (2015) Gas type
Cost of capture, compression and
Injection rate (MCF/D)
transportation ($/MCF) CO2
Total cost of
Increase in oil
injection (MM$)
recovery (%OOIP)
1
38,000
486.78
5%
N2
0.8
224,000
2296
9.70%
Natural gas
3.35
50,000
2146
5%
Flue gas
0.1
280,000
358.6
11%
PRODUCTIVITY IMPROVEMENT
Horizontal well Working Principle: Horizontal wells usually have lower drawdown pressure in comparison to vertical wells hence the time taken for the reservoir fluid to reach the dew point pressure is delayed. - condensate recovery from a horizontal well can be enhanced by a factor of 1.3 (Marir & Tiab, 2006) - water breakthrough is delayed in Horizontal well thus minimizing the effect of water coning. - showed that
horizontal well is economically admirable at lower Kv/Kh ratio. (Jamiolahmady & Danesh, 200 ) - it is critical to know the exact Kv/Kh for horizontal wells in order to prevent very optimistic results (Fevang & Whitson, 1996)
Temporary solution Expensive
PI plot of Horizontal and Vertical wells for North field, Qatar (From Miller et al., 2010)
Hydraulic Fracturing Working Principle: Increases the productivity by altering the flow capacity and increasing the effective wellbore radius (Meese et al, 1994) Temporary solution Expensive
Depends on Fracture conductivity (Indriati et al., 2002) Well deliverability of a hydraulically fractured gas condensate well increases 3 times to that of unfractured well (Al-Hashim & Hashmi, 2000). Economic analysis before and after fracturing (Uzoh et al., 2010) Before fracturing
After fracturing
Payback period
203 months
8 months
Acumulative NPV (USD)
8,776,838
61,948,687
the performance could be affected by (Rahim et al., 2012):
–Reservoir heterogeneity and permeability distribution.
-Inefficient fracture length to connect the wellbore with formation. -Ineffective fracture design and conductivity. -Improper post cleanup procedure
Matrix Acidizing Working Principle: Removes the wellbore damage and create an artificial pathway for the flow of hydrocarbon from reservoir to wellbore One of the key parameter for successful acid treatment is the length of the acid penetration into the formation (Fadele et al., 2000)
HCl for carbonate reservoirs and Mud acid for Interfacial tension of alcoholic acids is low, hence can be used for tight formations (Al-Anazi et al., 2006) sandstone reservoirs Corrosion and eaction of acids Cost of placement techniques for matrix acidizing (Uzoh et al., 2010) Placement technique
Average price 2011 USD
Average improvement %
Using drilling pipe
1195 339
249
Using coiled tubing
866 181
158
Using bull heading
628 147
25
Expensive treatment
Comparison between THREE (3) Productivity Improvement Options Recovery Option
Screening
Advantages
Limitations
Improvement
Matrix acidizing
Permeability greater than 1 mD
readily available
Acid placement, corrosive nature & unstable at high temperatures
Using chemical additives & mechanical methods, pre & post treatment analysis
Hydraulic fracturing
Permeability 0.01- Efficient above & below 10mD dew point
Horizontal wells
Low kv/kh contrast
High environmental Increasing fracture half impact & long clean up length & width, pre and periods post treatment analysis
Higher recovery & rates, Expensive, difficult to low condensate drill & non uniform saturation drainage
Increasing well length, smart technology & multi stage fracturing
Chemical Injection/Reservoir Alteration
Solvent Injection Working Principle: Decrease the Interfacial tension between condensate and gas or by dissolving the solvent with the condensate
Methanol, ethanol and Isopropyl alcohol are used. Methanol is flammable in nature. Methanol treatment rise the relative gas permeability by a Temporary solution factor of 1.2-2.5 (Du et al., 2000).
Effect on gas end-point relative permeability by Methanol treatment for low permeability Limestone cores (Al-Anazi et al. (2002)
Core Perm. (mD)
Initial water saturation (Swi)
Gas relative Gas relative Gas relative perm. before perm. after first perm. after Methanol Methanol second Methanol treatment (Krg) treatment (Krg) treatment (Krg)
2.32
0
0.517
0.647
0.704
4.43 4.5
0.2 0.54
0.675 0.529
0.829 0.819
0.916 -
Effect on gas end-point relative permeability by Methanol treatment for high permeability sandstone cores
Core Perm. (mD)
Initial water saturation (Swi)
Gas relative perm. before Methanol treatment (Krg)
Gas relative Gas relative perm. after first perm. after Methanol second Methanol treatment (Krg) treatment (Krg)
246
0
0.05
0.43
0.48
378
0.38
0.02
0.21
0.3
Wettability Alteration Working Principle: wettability of the rocks are changed from liquid wettability to intermediate gas wettability through chemical injection. Fluoro-surfactants and Fluoropolymers are injected Can be implemented on high or low permeability reservoirs Flexible, robust and permanent solution Wettability alteration by use of fluorinated surfactants in solvent mixtures of isopropanol and 2-propylene glycol can result in flow conductivity increase by a factor of 2 (Bang et al., 2008).
Summary of wettability alteration using Fluoro-surfactants Note: * – Oil/gas, ** – water/gas 1 Kewen & Abbas65 2 Fahes & Firoozabadi69 70 3 Noh & Firoozabadi 4 Wu & Firoozabadi71 Type of Chemical
Formation
Perm. (mD)
754
Kansas chalk Berea sandstone
5 1000
211-12P
Berea sandstone reservoir rock
600 10
311-12P
Berea sandstone reservoir rock
500 20
4Z8
Berea sandstone reservoir rock
700 5
1FC
Temp. (°C)
Fluid conc. (% wt.)
Contact angle alteration 0o- 60o *
20
0.1
50o- 90o ** 0o- 60o *
140
140
140
2-8
50o- 150o**
4
0o- 60o * 90o150o**
0.33
0o- 80o * 50o140o**
Selection Criteria -
Development around the world Development Strategy
Selection Criteria
Cost of treatment
Field applications
Gas cycling
Gas availability and good capital
High
Arun field (Indonesia) Hassi R’Mel south field (Algeria) Toual field (Algeria)
CO2 injection
Proper storage and transportation availability for CO2
Moderate
West Australian field
Nitrogen Injection
Lack of gas availability for cycling
Cheap
Abu Dhabi field
Horizontal well
Low permeability reservoirs and heterogeneous reservoirs
High
North field, Qatar
Selection Criteria Development Strategy
Selection Criteria
Cost of treatment
Field applications
Hydraulic fracturing
High skin and tight formations
Moderate
Smorbukk field in North Sea Yamburskoe artic field in Russia
Matrix acidizing
Availability of different acids and medium to high permeability formations
Moderate
California field
Solvent injection
Availability of solvent
High
Saudi Arabian gas field
Wettability alteration
Depending on the formation the availability of chemicals
High
____
To be considered: Development Strategy Gas cycling
CO2 injection
Advantages
Disadvantages Income from gas sales is delayed, expensive if gas needs to be purchased from external Ideal technique for condensate-banking issue source, considerable investment on compressors Highly corrosive, reduces calorific value of Sequestration of CO2, reduction in pollution or produced gas, storage and transportation is greenhouse effect expensive and difficult
Nitrogen Injection
Non-corrosive, available abundantly, cheap and environmental friendly
Cost on cryogenic processing unit and liquid drop out where it mixes with condensate
Horizontal well
Lower drawdown decline rate, productivity higher than vertical well
Can be expensive, not a permanent solution
Hydraulic fracturing
Productivity better than unfractured well
Not a permanent solution and can cause formation damage
Matrix acidizing
Good productivity and acids are available cheaply
Corrosive and reaction of acids with formation
Solvent injection
Inexpensive and increases gas relative permeability
Inflammable nature of Methanol and not a permanent solution
Wettability alteration
Flexibility, reliability and permanent solution
Environmental issues and expensive
.... perhaps, a combination of methods?
24
Thank You!
