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CSIROPETROLEUM Wellbore Stability Issues in Shales or Hydrate Bearing Sediments Reem Freij-Ayoub CSIRO Petroleum Australia Dr Reem Freij-Ayoub Tel: 61864368631 Reem.freij-ayoub@csiro.au, 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..etc 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 stability in difficult formations loss of US$ 2 billions/yr Shale formations 90% of incidents shales Hydrate bearing sediments (HBS) Salt formations HPHT reservoirs Brown fields Sand production US$ billions/yr Reservoir subsidence Fault seal analysis 5
Consequences of wellbore instability Sloughing or caving Packoffs, blowouts, or mud losses Increased mud treatment cost Stuck pipe and loss of equipment Side tracks or well abandonment 6
Wellbore stability model data In-situ stresses Regional data Leakoff test Breakouts Fractures Petrophysical data Porosity Permeability Bulk density Reservoir pressure Stability prediction model Thermal properties Specific heat Conductivity Rock mechanics data Log dynamic properties Lab tests Correlations Chemical properties Salt concentration Reflection coefficient 7
shales Processes affecting wellbore stability in shale formations when using water based mud Swelling or Shrinkage Hydrational stress Pore pressure Pore pressure Fluid Flow & Mud Pressure penetration Heat Transfer Thermal stress Mechanical Deformation (Poro - elasticity) Pore pressure Pore pressure Chemical Potential Mechanism 8
shales Mud pressure penetration mechanism 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 e high breakthrough pressure Optimize drilling mud properties Consider the formation pore size distribution 9
shales Chemical potential mechanism Shales have fine pores and (-)( ) charges, they act as a semi- permeable membrane 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
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 Heating the formation thermal expansion of formation & pore fluid: thermal stresses develop. Pore fluid & formation have different coefficients of thermal expansion pore pressure increases. Hydraulic and thermal diffusivities are different leading to pressure build-up. up. Other effects on drilling mud characteristics. 11
shales Swelling mechanism Reactive shales + non-inhibitive inhibitive muds pore pressure increase & adsorption of water 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 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 Mud weight 45 MPa Drilling mud has 20% lower salt concentration Mud weight 45 MPa 31 70 Pore Pressure (MPa) 30 29 28 27 26 25 24 23 0.0008 hr 0.1 hr 0.266 hr 17.5 hr 1 1.5 2 2.5 3 Normalized Radial Distance From Wellbore Centre Pore Pressure (MPa) 65 60 55 50 45 40 35 30 25 0.0008 hr 0.1 hr 0.266 hr 17.5 hr 1 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 Pore Pressure (MPa) 70 65 60 55 50 45 40 35 30 25 20 1 1.2 1.4 1.6 1.8 2 Normalized Radial Distance From Wellbore Centre L at 0.0008 hr L at 0.1 hr L at 0.266 hr L at 17.5 hr H at 0.0008 hr H at 0.1 hr H at 0.266 hr H at 17.5 hr 14
shales Modelling results: mud temperature Hot mud Temperature 50 37 20 Cold mud Temperature 50 37 20 wellbore wall Temperature (ºc) contours Pore Pressure 31.3 30.65 30 Pore Pressure 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
shales Modelling results: swelling shales Safety Factor in Shear 1.4 1.3 1.2 1.1 1 0.9 0.8 0.7 Soft shale & inhibitive mud Stiff shale & inhibitive mud Soft shale & noninhibitive mud Stiff shale & noninhibitive mud 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
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 Safety Factor 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 Higher salt concentration than the formation 36.55 1.28 54.42 0.76 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 Results at 5% well radius inside the formation 18
shales Drillers wellbore stability tool Mud weight vs. well orientation High pressure triaxial cell σ H In-situ stress bounds N 1 σ h σh/σv 0.95 0.9 0.85 0.8 0.75 Lower bound N Upper bound N Hydraulic fracture limit (standard leak-off test) Permissible horizontal stresses 0.7 0.65 0.6 0.55 Lower bound σ h /σ v Normal fault condition 0.5 1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2 N 19
Hydrate stability domain What are hydrates and why are hydrate bearing sediments (HBS) important? 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 Thermal stimulation Chemicals affect hydrate stability: Thermodynamic inhibitors (salts, alcohols, glycols) g can inhibit hydrate formation in the mud Kinetic additives (eg lecithin + poly N-vinyl N pyrrolidone (PVP)) PVP)) stabilize hydrates in the formation Pressure (Psia) 1250 1000 750 500 250 0 No inhibitor Hydrates stable Chemical inhibition 10 20 30 40 50 60 70 80 90 100 Temperature ( F)( With inhibitor Thermal De-pressurization Hydrates unstable http://www.ench.ucalgary.ca/~hydrates/kinetics.html#e 21
Constrained modulus of HBS Results of confined compression tests on natural gas hydrate bearing silica sands (In collaboration with Heriot-Watt University) Pre-dissociation (with hydrates stable) constrained modulus dependence on hydrate saturation Post-dissociation (after hydrates dissociated) constrained modulus dependence on hydrate saturation Pre-Dissociation Constrained Modulus (GPa) 5 4 3 2 1 0 0 10 20 30 40 Hydrate Saturation (%) Post-Dissociation Constrained Modulus (GPa) 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 Drilling mud contamination with gas Reduction of mud density Change of mud rheology Decrease of formation strength & loss of mud support 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 Free Free-gas Gas Hydrate Production facilities Collapsed casing Casing collapse Cased Borehole borehole Circulation Production of hot of 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 of casing cement with low hydration heat Use predictive modeling Analyze stability of the wellbore formation using coupled mechanical-thermal thermal-chemical/kinetic Assess conductor integrity when circulating hot fluid through the hydrates zone. 25
Wellbore stability in HBS: heating the wellbore walls N o rm alized Porosity 1 0.9 0.8 0.7 0.6 0.5 0.4 Relative Porosity Profiles 1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2 Normalized Distance Inside Formation after excavation at 0.14 hrs at 0.28 hrs at 1.39 hrs at 5.56 hrs Cohesion: reduced in near wellbore region by hydrate melting Min Max=initial % Hydrates Disssolved 100 80 60 40 20 0 Hydrates Dissociation Profiles 1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2 Normalized Distance Inside Formation after excavation at 0.14 hrs at 0.28 hrs at 1.39 hrs at 5.56 hrs Porosity: increased in near wellbore region by hydrate melting Max Min=initial 26
Key messages: stability of wellbores in HBS Radius of Plasticity-Failure Zone Radius of Plasticity Normalised by Wellbore Radius 4 3.5 3 2.5 2 1.5 1 Hot permeable HBS Hot permeable sediments Hot impermeable HBS Hot impermeable sediments 0 0.5 1 1.5 2 Shear failure zone Failure zone 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
Casing Integrity in HBS: 20in API casing Strong cement Thermal conductivity 0.66 Wm - 1 K -1 Modulus of elasticity 55.16 GPa Poisson s s ratio 0.4 cohesion 11.4 MPa Friction angle 10º Tensile strength 2.6 MPa Weak cement Modulus of elasticity 0.4 GPa Poisson s s ratio 0.2 Cohesion 1.2 MPa. Friction angle 10º Tensile strength 0.379 MPa Strong cement shear tension Progress of shear failure inside the strong cement and tension failure inside the HBS as the cement and the formation heat up 8.33 hrs after heat application to the casing. Isotropic stress field, K0=0.5 28
Weak cement Results for 20in API casing Mixed mode shear Shear failure of all the weak cement and further part of the HBS and a band of mixed mode: tension and shear failure develops at the boundary of the cement 15minutes after heat application to the casing. No change is observed at 8.33 hours. Isotropic stress field, K0=0.5. Casing Safety Factor 1.5 1.4 1.3 1.2 1.1 1.0 0.9 0.8 Casing Safety Factor for HBS and NHBS with Weak Cement- Isotropic Stress Field-Various Stress Ratios 0 0.5 1 1.5 2 2.5 3 Time (Days) WS_H_K=0.5 WS_H_K=1.0 WS_H_K=2.0 WS_NH_K=0.5 WS_NH_K=1.0 WS_NH_K=2.0 Casing safety factors for a wellbore drilled in NHBS or HBS and cased with 0.635in casing using weak cement. The strength degradation resulting from hydrate dissociation in the HBS upon heating reduce the SF for all stress ratios considered. Note that cases with lower stress ratios K0 have higher SF than cases with higher K0. 29
Further challenges and future trends in Geomechanics HPHT reservoirs Brown fields and tail production Rock properties measurements narrow or nonexistent mud window sand & water production and management issues formation strengthening issues cuttings instead of coring Deep water drilling one trip well 30