shales
SPE DISTINGUISHED LECTURER SERIES is funded principally through a grant of the
SPE FOUNDATION The Society gratefully acknowledges those companies that support the program by allowing their professionals to participate as Lecturers. And special thanks to The American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME) for their contribution to the program.
CSIROPETROLEUM
Wellbore Stability Issues in Shales or Hydrate Bearing Sediments Reem Freij-Ayoub CSIRO Petroleum Australia Dr Reem Freij-Ayoub Tel: 61864368631 [email protected], http://www.dpr.csiro.au/
2
Acknowledgements Geomechanics team at CSIRO petroleum with > 17 years of industry supported research (e.g. PETRONAS, PDVSA Intevep, Woodside ..etcÆ millions of savings /project Xavier Choi Chee Tan and Bailin Wu (currently Schlumberger) Mohammed Amanullah
3
Outline When
do we need Geomechanics? Consequences of wellbore instability Wellbore stability model data Wellbore stability in shale formations – Main processes – Modelling results – Key Messages Wellbore
stability in hydrate bearing sediments Further challenges in Geomechanics 4
When do we need Geomechanics? Wellbore
C4
stability in difficult formations Æ loss of
US$ 2 billions/yr – Shale formations Æ 90% of incidents
shales
– Hydrate bearing sediments (HBS) – Salt formations – HPHT reservoirs – Brown fields Sand
production Æ US$ billions/yr
Reservoir Fault
subsidence
seal analysis
5
Diapositiva 5 C4
for the analysis an d prediction of
CSIRO, 08/09/2006
Consequences of wellbore instability Sloughing Packoffs,
blowouts, or mud losses
Increased Stuck Side
or caving
mud treatment cost
pipe and loss of equipment
tracks or well abandonment
6
Wellbore stability model data In-situ stresses Regional data Leakoff test Breakouts Fractures
Reservoir pressure Rock mechanics data Log dynamic properties Lab tests Correlations Stability prediction model
Petrophysical data Porosity Permeability Bulk density
Chemical properties Thermal properties Specific heat Conductivity
Salt concentration Reflection coefficient
7
Processes affecting wellbore stability in shale formations when using water based mud Swelling or Shrinkage pr es su re
Hy dr Po atio na re ls pr es tr es su s re
Fluid Flow & Mud Pressure penetration
Po re
shales
Mechanical Deformation (Poro - elasticity) P
e Th
s al rm
Heat Transfer
ss e tr
r Po
e
p
re u ss e r
or e
pr es su r
e
Chemical Potential Mechanism
8
shales
Mud pressure penetration mechanism C2
Overbalance drilling conditions mean Mud filtrate (viscosity, adhesion and density) will invade the formation Reduction of differential pressure leads to reduction of the mechanical support to the wellbore wall To ensure high breakthrough pressure – Optimize drilling mud properties – Consider the formation pore size distribution
9
Diapositiva 9 C2
talk about function of drilling mud mech support but not invasion of formation CSIRO, 07/09/2006
shales
Chemical potential mechanism
have fine pores and (-) charges, they act asC1a semipermeable membrane
Shales Ideal
semi-permeable membranes permit flow of water but not salt ions (osmosis)
The
chemical potential controls direction of flow
– The chemical potential of a fluid = F (dissolved ion concentration) – Water flows from low to high salt concentration The
membrane can be non-ideal or leaky 10
Diapositiva 10 C1
Shales act like a semi-permeable membrane due to their fine pore size and the negative charges on the clay platelets Semi-permeable membranes permit the flow of water molecules and inhibit the flow of dissolved salt ions (osmosis) Direction of flow is determined by the chemical potential, water activity The water activity of a fluid is determined by its dissolved ion concentration Water will flow across this membrane from the medium of high water activity (low salt concentration) to the medium of low water activity (high salt concentration) The membrane can be non-ideal or leaky where solute transport can take place CSIRO, 23/06/2006
shales
Heat transport mechanism
The
drilling mud and formation differ in temperature – Geothermal gradient: the drilling mud is cooling the bottom and heating the top of the wellbore
the formation Æ thermal expansion of formation & pore fluid: thermal stresses develop.
Heating Pore
fluid & formation have different coefficients of thermal expansion Æ pore pressure increases.
Hydraulic
and thermal diffusivities are different leading to pressure build-up.
Other
effects on drilling mud characteristics…. 11
shales
Swelling mechanism
shales + non-inhibitive muds Æ pore pressure increase & adsorption of water
Reactive
This
leads to hydrational strain=swelling or hydrational stresses & a possible shear failure
Water
is reactive with shales, low viscosity, high wetting characteristics i.e., non-inhibitive
Inhibitive
water based mud with low wetting characteristics reduces the risk of wellbore instability 12
shales
Modelling results: mud chemical composition
Drilling mud has 20% higher salt concentration
Drilling mud has 20% lower salt concentration Mud weight 45 MPa
31
70
30
65
0.0008 hr
60
0.1 hr
55
0.266 hr
50
17.5 hr
29 28 27 0.0008 hr 26
0.1 hr
25
0.266 hr 17.5 hr
Pore Pressure (MPa)
Pore Pressure (MPa)
Mud weight 45 MPa
45 40 35 30
24
25
23
1 1
1.5
2
2.5
3
Normalized Radial Distance From Wellbore Centre
1.5
2
2.5
3
Normalized Radial Distance From Wellbore Centre 13
Comparison between high and low salt concentration mud Mud weight 45 MPa L at 0.0008 hr
70
L at 0.1 hr
Pore Pressure (MPa)
65
L at 0.266 hr
60
L at 17.5 hr
55
H at 0.0008 hr
50
H at 0.1 hr
45
H at 0.266 hr
40
H at 17.5 hr
35 30 25 20 1
1.2
1.4
1.6
1.8
2
Normalized Radial Distance From Wellbore Centre
14
shales
Modelling results: mud temperature Hot mud
Cold mud
Temperature
Temperature
50 37 20
50 37 20 wellbore wall
Temperature (ºc) contours Pore Pressure
Pore Pressure
31.3 30.65 30
30 29.4 28.69
Pressure (MPa) contours
15
shales
Modelling results: mud temperature
Pore Pressure evolution Pressure change due to 30º (heating or cooling) > 2 MPa Hot mud
Cold mud
16
Modelling results: swelling shales Safety Factor in Shear
shales
1.4
Soft shale & inhibitive mud
1.3
Stiff shale & inhibitive mud
1.2
Soft shale & noninhibitive mud
1.1
Stiff shale & noninhibitive mud
1 0.9 0.8 0.7 0
0.5
1
1.5
2
2.5
Time (hrs)
Swelling is significant when non-inhibitive mud is used with 17 highly stiff reactive shales
C3
Diapositiva 17 C3
(stiff formation is 20 times stiffer than the other one). CSIRO, 07/09/2006
shales
Key Messages
Careful design of water base drilling fluids is needed to control PP and SF evolution Drilling fluid pressure = 45 MPa Formation Pressure =30 MPa
Time=0.0025 hour
Time=0.1 hour
Drilling Fluid
Pressure
Pressure
Safety Factor
Water
33.37
1.36
42.39
1.07
Low filtrate invasion
31.25
1.42
38.05
1.19
Lower salt concentration than the formation
36.55
1.28
54.42
0.76
Higher salt concentration than the formation
29.80
1.48
25
1.60
Hot water
38.33
1.25
43.71
1.02
Cold water
28.41
1.48
41.07
1.11
Cold-low filtrate invasion-higher salt concentration than formation
23.76
1.62
23.2
1.72
Safety Factor
Results at 5% well radius inside the formation
18
shales
Drillers’ wellbore stability tool High pressure triaxial cell
Mud weight vs. well orientation σH
N
Lower bound N
1 0.95 0.9
σh
σ h/σ v
0.85 0.8
Upper bound N
In-situ stress bounds Hydraulic fracture limit (standard leak-off test)
Permissible horizontal stresses
0.75 0.7
Lower bound σh/σv
0.65 0.6
Normal fault condition 0.55 0.5 1
1.1
1.2
1.3
1.4
1.5
N
1.6
1.7
1.8
1.9
19
2
What are hydrates and why are hydrate bearing sediments (HBS) important ? Hydrate stability domain • • • • • •
Hydrates are Source of energy Way to transport natural gas Geohazard Climate change Drilling hazard Problem in flow assurance
Hydrates on sea bed (USGS)
20
Hydrate stability domain Depressurization
stimulation
Chemicals
Chemical inhibition
affect hydrate stability:
– Thermodynamic inhibitors (salts, alcohols, glycols) can inhibit hydrate formation in the mud – Kinetic additives (eg lecithin + poly N-vinyl pyrrolidone (PVP)) stabilize hydrates in the formation
With inhibitor
1250
1000 Thermal Pressure (Psia)
Thermal
No inhibitor
Hydrates stable
750
DeDe-pressurization 500 Hydrates unstable
250
0 10
20
30
40
50
60
70
80
Temperature (° (°F) http://www.ench.ucalgary.ca/~hydrates/kinetics.html#E
21
90
100
Constrained modulus of HBS Results of confined compression tests on natural gas hydrate bearing silica sands (In collaboration with Heriot-Watt University) Post-dissociation (after hydrates dissociated) constrained modulus dependence on hydrate saturation Post-Dissociation Constrained Modulus (GPa)
Pre-Dissociation Constrained Modulus (GPa)
Pre-dissociation (with hydrates stable) constrained modulus dependence on hydrate saturation 5 4 3 2 1 0 0
10
20
30
Hydrate Saturation (%)
40
1 0.8 0.6 0.4 0.2 0 0
10
20
30
40
Hydrate Saturation (%)
22
HBS well control problems
Hydrates are sensitive to the drilling mud: – Pressure – Temperature – Chemical composition
Hydrate destabilization Æ – Drilling mud contamination with gas ) Reduction of mud density ) Change of mud rheology – Decrease of formation strength & loss of mud support Æ wellbore instability Gas hydrate-related drilling problems (Adapted from Maurer Engineering, Inc.)
23
HBS and casing integrity
During hydration of casing cement During circulating of hotter drilling mud Casing collapse
Production facilities
Free-gas Free Gas Hydrate Cased borehole Borehole
Collapsed casing
Circulation Productionof of hot hot fluid hydrocarbons
Gas hydrate-related casing problems (Adapted from Maurer Engineering, Inc.)
24
Wellbore stabilization strategies Optimal
design of the drilling mud to enhance hydrate stability (use kinetic additives e.g.: lecithin, etc.)
Selection Use
of casing cement with low hydration heat
predictive modeling
– Analyze stability of the wellbore formation using coupled mechanical-thermal-chemical/kinetic – Assess conductor integrity when circulating hot fluid through the hydrates zone. 25
Wellbore stability in HBS: heating the wellbore walls Relative Porosity Profiles
after excavation
N o rm a liz e d P o ro s ity
1
at 0.14 hrs
0.9
at 0.28 hrs
0.8
at 1.39 hrs
0.7
at 5.56 hrs
Cohesion: reduced in near wellbore region by hydrate melting
0.6
Min
Max=initial
0.5 0.4 1
1.1
1.2 1.3 1.4
1.5 1.6 1.7 1.8
1.9
2
Normalized Distance Inside Formation Hydrates Dissociation Profiles after excavation
% Hydrates Disssolved
100 80 60 40 20 0
at 0.14 hrs at 0.28 hrs
Porosity: increased in near wellbore region by hydrate melting
at 1.39 hrs at 5.56 hrs
Max
Min=initial
1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2
Normalized Distance Inside Formation
26
Key messages: stability of wellbores in HBS Radius of Plasticity Normalised by Wellbore Radius
Radius of Plasticity-Failure Zone
Shear failure zone
4
Hot permeable HBS 3.5 3
Failure zone
Hot permeable sediments
2.5
Hot impermeable HBS 2 1.5
Hot impermeable sediments
1 0
0.5
1
1.5
2
Time (hrs)
Encountering
hydrates in the sediments while drilling a wellbore can increase the size of the yield zone by 32% The importance of employing techniques to stabilize HBS in deep water drilling. 27
Further challenges and future trends in Geomechanics HPHT reservoirs
Æ narrow or nonexistent mud window
Brown fields and tail production Æ sand & water production and management issues Æ formation strengthening issues Rock properties measurements Æ cuttings instead of coring Deep water drilling
Æ one trip well 28
SPE FOUNDATION The Society gratefully acknowledges those companies that support the program by allowing their professionals to participate as Lecturers. And special thanks to The American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME) for their contribution to the program.
CSIROPETROLEUM
Wellbore Stability Issues in Shales or Hydrate Bearing Sediments Reem Freij-Ayoub CSIRO Petroleum Australia Dr Reem Freij-Ayoub Tel: 61864368631 [email protected], http://www.dpr.csiro.au/
2
Acknowledgements Geomechanics team at CSIRO petroleum with > 17 years of industry supported research (e.g. PETRONAS, PDVSA Intevep, Woodside ..etcÆ millions of savings /project Xavier Choi Chee Tan and Bailin Wu (currently Schlumberger) Mohammed Amanullah
3
Outline When
do we need Geomechanics? Consequences of wellbore instability Wellbore stability model data Wellbore stability in shale formations – Main processes – Modelling results – Key Messages Wellbore
stability in hydrate bearing sediments Further challenges in Geomechanics 4
When do we need Geomechanics? Wellbore
C4
stability in difficult formations Æ loss of
US$ 2 billions/yr – Shale formations Æ 90% of incidents
shales
– Hydrate bearing sediments (HBS) – Salt formations – HPHT reservoirs – Brown fields Sand
production Æ US$ billions/yr
Reservoir Fault
subsidence
seal analysis
5
Diapositiva 5 C4
for the analysis an d prediction of
CSIRO, 08/09/2006
Consequences of wellbore instability Sloughing Packoffs,
blowouts, or mud losses
Increased Stuck Side
or caving
mud treatment cost
pipe and loss of equipment
tracks or well abandonment
6
Wellbore stability model data In-situ stresses Regional data Leakoff test Breakouts Fractures
Reservoir pressure Rock mechanics data Log dynamic properties Lab tests Correlations Stability prediction model
Petrophysical data Porosity Permeability Bulk density
Chemical properties Thermal properties Specific heat Conductivity
Salt concentration Reflection coefficient
7
Processes affecting wellbore stability in shale formations when using water based mud Swelling or Shrinkage pr es su re
Hy dr Po atio na re ls pr es tr es su s re
Fluid Flow & Mud Pressure penetration
Po re
shales
Mechanical Deformation (Poro - elasticity) P
e Th
s al rm
Heat Transfer
ss e tr
r Po
e
p
re u ss e r
or e
pr es su r
e
Chemical Potential Mechanism
8
shales
Mud pressure penetration mechanism C2
Overbalance drilling conditions mean Mud filtrate (viscosity, adhesion and density) will invade the formation Reduction of differential pressure leads to reduction of the mechanical support to the wellbore wall To ensure high breakthrough pressure – Optimize drilling mud properties – Consider the formation pore size distribution
9
Diapositiva 9 C2
talk about function of drilling mud mech support but not invasion of formation CSIRO, 07/09/2006
shales
Chemical potential mechanism
have fine pores and (-) charges, they act asC1a semipermeable membrane
Shales Ideal
semi-permeable membranes permit flow of water but not salt ions (osmosis)
The
chemical potential controls direction of flow
– The chemical potential of a fluid = F (dissolved ion concentration) – Water flows from low to high salt concentration The
membrane can be non-ideal or leaky 10
Diapositiva 10 C1
Shales act like a semi-permeable membrane due to their fine pore size and the negative charges on the clay platelets Semi-permeable membranes permit the flow of water molecules and inhibit the flow of dissolved salt ions (osmosis) Direction of flow is determined by the chemical potential, water activity The water activity of a fluid is determined by its dissolved ion concentration Water will flow across this membrane from the medium of high water activity (low salt concentration) to the medium of low water activity (high salt concentration) The membrane can be non-ideal or leaky where solute transport can take place CSIRO, 23/06/2006
shales
Heat transport mechanism
The
drilling mud and formation differ in temperature – Geothermal gradient: the drilling mud is cooling the bottom and heating the top of the wellbore
the formation Æ thermal expansion of formation & pore fluid: thermal stresses develop.
Heating Pore
fluid & formation have different coefficients of thermal expansion Æ pore pressure increases.
Hydraulic
and thermal diffusivities are different leading to pressure build-up.
Other
effects on drilling mud characteristics…. 11
shales
Swelling mechanism
shales + non-inhibitive muds Æ pore pressure increase & adsorption of water
Reactive
This
leads to hydrational strain=swelling or hydrational stresses & a possible shear failure
Water
is reactive with shales, low viscosity, high wetting characteristics i.e., non-inhibitive
Inhibitive
water based mud with low wetting characteristics reduces the risk of wellbore instability 12
shales
Modelling results: mud chemical composition
Drilling mud has 20% higher salt concentration
Drilling mud has 20% lower salt concentration Mud weight 45 MPa
31
70
30
65
0.0008 hr
60
0.1 hr
55
0.266 hr
50
17.5 hr
29 28 27 0.0008 hr 26
0.1 hr
25
0.266 hr 17.5 hr
Pore Pressure (MPa)
Pore Pressure (MPa)
Mud weight 45 MPa
45 40 35 30
24
25
23
1 1
1.5
2
2.5
3
Normalized Radial Distance From Wellbore Centre
1.5
2
2.5
3
Normalized Radial Distance From Wellbore Centre 13
Comparison between high and low salt concentration mud Mud weight 45 MPa L at 0.0008 hr
70
L at 0.1 hr
Pore Pressure (MPa)
65
L at 0.266 hr
60
L at 17.5 hr
55
H at 0.0008 hr
50
H at 0.1 hr
45
H at 0.266 hr
40
H at 17.5 hr
35 30 25 20 1
1.2
1.4
1.6
1.8
2
Normalized Radial Distance From Wellbore Centre
14
shales
Modelling results: mud temperature Hot mud
Cold mud
Temperature
Temperature
50 37 20
50 37 20 wellbore wall
Temperature (ºc) contours Pore Pressure
Pore Pressure
31.3 30.65 30
30 29.4 28.69
Pressure (MPa) contours
15
shales
Modelling results: mud temperature
Pore Pressure evolution Pressure change due to 30º (heating or cooling) > 2 MPa Hot mud
Cold mud
16
Modelling results: swelling shales Safety Factor in Shear
shales
1.4
Soft shale & inhibitive mud
1.3
Stiff shale & inhibitive mud
1.2
Soft shale & noninhibitive mud
1.1
Stiff shale & noninhibitive mud
1 0.9 0.8 0.7 0
0.5
1
1.5
2
2.5
Time (hrs)
Swelling is significant when non-inhibitive mud is used with 17 highly stiff reactive shales
C3
Diapositiva 17 C3
(stiff formation is 20 times stiffer than the other one). CSIRO, 07/09/2006
shales
Key Messages
Careful design of water base drilling fluids is needed to control PP and SF evolution Drilling fluid pressure = 45 MPa Formation Pressure =30 MPa
Time=0.0025 hour
Time=0.1 hour
Drilling Fluid
Pressure
Pressure
Safety Factor
Water
33.37
1.36
42.39
1.07
Low filtrate invasion
31.25
1.42
38.05
1.19
Lower salt concentration than the formation
36.55
1.28
54.42
0.76
Higher salt concentration than the formation
29.80
1.48
25
1.60
Hot water
38.33
1.25
43.71
1.02
Cold water
28.41
1.48
41.07
1.11
Cold-low filtrate invasion-higher salt concentration than formation
23.76
1.62
23.2
1.72
Safety Factor
Results at 5% well radius inside the formation
18
shales
Drillers’ wellbore stability tool High pressure triaxial cell
Mud weight vs. well orientation σH
N
Lower bound N
1 0.95 0.9
σh
σ h/σ v
0.85 0.8
Upper bound N
In-situ stress bounds Hydraulic fracture limit (standard leak-off test)
Permissible horizontal stresses
0.75 0.7
Lower bound σh/σv
0.65 0.6
Normal fault condition 0.55 0.5 1
1.1
1.2
1.3
1.4
1.5
N
1.6
1.7
1.8
1.9
19
2
What are hydrates and why are hydrate bearing sediments (HBS) important ? Hydrate stability domain • • • • • •
Hydrates are Source of energy Way to transport natural gas Geohazard Climate change Drilling hazard Problem in flow assurance
Hydrates on sea bed (USGS)
20
Hydrate stability domain Depressurization
stimulation
Chemicals
Chemical inhibition
affect hydrate stability:
– Thermodynamic inhibitors (salts, alcohols, glycols) can inhibit hydrate formation in the mud – Kinetic additives (eg lecithin + poly N-vinyl pyrrolidone (PVP)) stabilize hydrates in the formation
With inhibitor
1250
1000 Thermal Pressure (Psia)
Thermal
No inhibitor
Hydrates stable
750
DeDe-pressurization 500 Hydrates unstable
250
0 10
20
30
40
50
60
70
80
Temperature (° (°F) http://www.ench.ucalgary.ca/~hydrates/kinetics.html#E
21
90
100
Constrained modulus of HBS Results of confined compression tests on natural gas hydrate bearing silica sands (In collaboration with Heriot-Watt University) Post-dissociation (after hydrates dissociated) constrained modulus dependence on hydrate saturation Post-Dissociation Constrained Modulus (GPa)
Pre-Dissociation Constrained Modulus (GPa)
Pre-dissociation (with hydrates stable) constrained modulus dependence on hydrate saturation 5 4 3 2 1 0 0
10
20
30
Hydrate Saturation (%)
40
1 0.8 0.6 0.4 0.2 0 0
10
20
30
40
Hydrate Saturation (%)
22
HBS well control problems
Hydrates are sensitive to the drilling mud: – Pressure – Temperature – Chemical composition
Hydrate destabilization Æ – Drilling mud contamination with gas ) Reduction of mud density ) Change of mud rheology – Decrease of formation strength & loss of mud support Æ wellbore instability Gas hydrate-related drilling problems (Adapted from Maurer Engineering, Inc.)
23
HBS and casing integrity
During hydration of casing cement During circulating of hotter drilling mud Casing collapse
Production facilities
Free-gas Free Gas Hydrate Cased borehole Borehole
Collapsed casing
Circulation Productionof of hot hot fluid hydrocarbons
Gas hydrate-related casing problems (Adapted from Maurer Engineering, Inc.)
24
Wellbore stabilization strategies Optimal
design of the drilling mud to enhance hydrate stability (use kinetic additives e.g.: lecithin, etc.)
Selection Use
of casing cement with low hydration heat
predictive modeling
– Analyze stability of the wellbore formation using coupled mechanical-thermal-chemical/kinetic – Assess conductor integrity when circulating hot fluid through the hydrates zone. 25
Wellbore stability in HBS: heating the wellbore walls Relative Porosity Profiles
after excavation
N o rm a liz e d P o ro s ity
1
at 0.14 hrs
0.9
at 0.28 hrs
0.8
at 1.39 hrs
0.7
at 5.56 hrs
Cohesion: reduced in near wellbore region by hydrate melting
0.6
Min
Max=initial
0.5 0.4 1
1.1
1.2 1.3 1.4
1.5 1.6 1.7 1.8
1.9
2
Normalized Distance Inside Formation Hydrates Dissociation Profiles after excavation
% Hydrates Disssolved
100 80 60 40 20 0
at 0.14 hrs at 0.28 hrs
Porosity: increased in near wellbore region by hydrate melting
at 1.39 hrs at 5.56 hrs
Max
Min=initial
1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2
Normalized Distance Inside Formation
26
Key messages: stability of wellbores in HBS Radius of Plasticity Normalised by Wellbore Radius
Radius of Plasticity-Failure Zone
Shear failure zone
4
Hot permeable HBS 3.5 3
Failure zone
Hot permeable sediments
2.5
Hot impermeable HBS 2 1.5
Hot impermeable sediments
1 0
0.5
1
1.5
2
Time (hrs)
Encountering
hydrates in the sediments while drilling a wellbore can increase the size of the yield zone by 32% The importance of employing techniques to stabilize HBS in deep water drilling. 27
Further challenges and future trends in Geomechanics HPHT reservoirs
Æ narrow or nonexistent mud window
Brown fields and tail production Æ sand & water production and management issues Æ formation strengthening issues Rock properties measurements Æ cuttings instead of coring Deep water drilling
Æ one trip well 28
