5/21/2010
Global Research & Technology Centre/ GRTC Training Department
Drilling Fluids: Design & Selection SCOMI OILTOOLS
Key elements of a successful Drilling Fluid Operation
HS&E Drilling Fluid Design & Selection
Tender
Rig & Mud Plant Specs
Successful Drilling Fluid Process
Quality Control
Personnel
Drilling Fluid Design & Selection
Technical Service Solids Control
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There are only two reasons why we drill a hole in the ground:
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To collect geological and reservoir data
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To successfully exploit and produce oil & gas
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Primary operational goals ● ●
Deliver quality geological and reservoir data Minimise reservoir damage to optimise oil & gas recovery
Secondary operational goals ●
Achieve “technical limit” drilling performance
Note: The considerable reduction in operational costs as a consequence of “technical limit” drilling performance is valid only to the degree that the primary operational goals are successfully met! Appropriate drilling fluid design and selection is a prerequisite in order to fully meet both our primary and secondary goals SCOMI OILTOOLS
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Primary factors that impact drilling fluid design & selection
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Primary functions of a drilling fluid Minimise fluid invasion into formations
Prevent the flow of oil and gas while drilling Lubricate the drill string – Lubricate & cool the drill bit Transmit Hydraulic Horsepower (HHP) to the bit
Maintain a stable in gauge well bore Minimise shale hydration & dispersion Efficiently transport cuttings to surface Minimise reservoir damage
Maximise Rate or Penetration (ROP)
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Drilling fluid design & selection considerations Are mud losses expected?
Do you want to be first to try something new? Risk management
Cost of Fluid
Formation damage Lubrication
Waste disposal options Local regulations Shale inhibition Completion design
Mud weight
Company policy
Who has the fluids contract? What has worked before? Who needs to be involved? Temperature and pressure SCOMI OILTOOLS
Primary drilling fluid design and selection GOALS ●
To fully meet all regulatory and internal HSE guidelines and goals.
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To provide a stable wellbore to facilitate the successful running / retrieval of quality geological and reservoir data.
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To minimise reservoir damage and thereby optimise well productivity and profitability.
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To optimise drilling performance and thereby reduce overall drilling
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Framework for drilling fluid design, testing & selection ●
Test, evaluate and select drilling fluid systems that will fully meet all regulatory and internal HSE guidelines.
This is especially applicable to synthetic oil based muds.
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Test & analyse the physical & electro-chemical characteristics of the clays, shales, mudstones and reservoir sequences to be drilled.
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Design & test for the best synergy between the clays, shales or mudstones with various water based mud system options in order to minimise hydration & control dispersion.
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Framework for drilling fluid design, testing & selection ●
Test various water based and / or synthetic oil based mud formulations for their tolerance to: • Drill solids • Barite “weight up” • Applicable drilling fluid contaminants including cement • Temperature stability at anticipated BHT
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On the basis of the test results evaluate, optimise and then select the appropriate water based or synthetic oil based mud system to meet your “well specific” drilling and reservoir challenges.
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Thoroughly review the following key elements ● ● ●
Environmental regulations & guidelines. Offset well data, ie well programs / well summaries and drilling fluid specific programs / summaries. Reservoir data: • offset reverse permeability test data • mercury injection data for reservoir pore throat size range • prognosed in-situ shales or shale beds present in reservoir sands • anticipated pore pressure gradient and temperature gradient in the reservoir
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Thoroughly review the following key elements ●
Logging plan, ie duration & prognosed maximum bottom hole temperature.
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Testing plan, ie special fluid and “kill pill” requirements.
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Development well - completion plan, ie perforated liner, expandable or fixed screens, sliding sleeve, etc. Well “clean up” and fluid design program to be based on completion design criteria.
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Thoroughly review the following key elements ●
Potential for the presence of acid gasses, CO2 & H2S.
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Prognosed fractured and / or faulted zones with the potential for lost circulation
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Maximum prognosed temperature for each hole section.
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Thoroughly review the following key elements ●
Deep water wells: ● Seabed depth ● Seabed temperature ● In-situ gas hydrates ● potential for formation of gas hydrates
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Drilling fluid lubricity: A key element in terms of potential torque & drag limitations when planning to drill a long reach “step out” well. ● Note: Lubricity is also a significant factor when drilling deviated wells through “hard rock”, eg granite.
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Thoroughly review the following key elements ●
Exploration well, ie “wildcat “ or mature exploration area.
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Detailed lithology profile.
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Casing design options.
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Hole sizes / depths MD & TVD as applicable.
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Directional plan – inclination & azimuth.
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Wellbore stress modeling data, ie in-situ vertical stress & minimum / maximum horizontal stress prediction.
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Thoroughly review the following key elements ●
Pore pressure prediction, ie mud weight range for each hole section. ● Data sources used to predict pore pressure gradient: ● Sonic / resistivity logs, seismic data analysis, micro hydraulic fracturing (MDT), drilling records and bore hole modeling.
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Offset well “leak off” & F.I.T. test data.
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Mud plant capacities / warehouse facilities, product availability and “lead times”.
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Rig specifications / limitations, ie tank capacities, solids control equipment and rig mixing / delivery systems.
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Risk management in drilling fluid design & selection
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Risk management in drilling fluid design & selection Management of risk Lower O P TI M U M
Lower
Higher
Risk
Choice of drilling fluid systems: Synthetic oil based mud
D RI LL IN G P E R F O R M A N C E
Higher
Overall well costs
Enhanced KCL / Polymer / Glycol & Surfactants KCL / Polymer / Glycols
F A IL U R E
Silicates Dispersed muds Exception: Dispersed muds are often the most economical low risk option for drilling shallow, young, weakly consolidated shales
C R IT I C A L
Brine systems Fully dispersed fresh water / lignosulfonate / Lime / gyp muds Bentonite muds / spud muds
LI N E
• • • • •
Poor shale inhibition Hole stability problems Stuck pipe Low ROPs Consequences of poor drilling practices
• Failure to run & retrieve quality logging data • Reservoir damage, etc
SW / viscous sweeps
Higher
Inhibitive properties
Lower
I N C R E A S E D H & S R I S K S
Evaluate risk ie potential value of success vs the potential cost of failure SCOMI OILTOOLS
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Risk management in drilling fluid design & selection Management of risk 160 140 120 100
Hours
C R I T I C A L
Example – “lost time” analysis for an offshore well
80 60
F A I L U R E
40
I N C R E A S E D H & S
20 0
R I S K S
L I N E
The cost of failure !
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Advantages & disadvantages of SBM & WBM
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Advantages & disadvantages of SBM & WBM
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Advantages & disadvantages of SBM & WBM
SBM
WBM
Environmental
Environmental
• Moderate to significant environmental impact, however this impact can be managed, e.g. cuttings re-injection, ship to shore, etc.
Hole stability & hole gauge • Open hole stability sustainable for long periods of time. • Close to gauge well bore.
Accretion / bit balling • Minimal to zero accretion / bit balling.
• Moderate environmental impact. Dependant upon type of WBM system.
Hole stability & hole gauge • Open hole stability “very time dependent”. • From close to gauge to out of gauge well bore dependent upon appropriate water based mud system design & selection requirements.
Accretion / bit balling • Severe to minimal accretion/ bit balling problems. Dependant upon appropriate water based mud system design & selection.
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Advantages & disadvantages of SBM & WBM SBM
WBM
ROPs
ROPs
• Higher ROPs in most drilling environments.
Torque & drag • Lower torque & drag values.
Temperature stability • High thermal stability 450°F +
• Lower Rops in most drilling environments.
Torque & drag • Higher torque & drag values.
Temperature stability • Lower thermal stability, ie above 280° F require special H.T. products for thermal stability to +/400 ° F. Potential problems maintaining stable mud properties at very high temperatures.
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Advantages & disadvantages of SBM & WBM SBM ROPs • Higher ROPs in most drilling environments.
Torque & drag • Lower torque & drag values.
Temperature stability • High thermal stability 450°F +
WBM ROPs • Lower Rops in most drilling environments.
Torque & drag • Higher torque & drag values.
Temperature stability • Lower thermal stability, ie above 280° F require special H.T. products for thermal stability to +/400 ° F. Potential problems maintaining stable mud properties at very high temperatures.
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Advantages & disadvantages of SBM & WBM SBM
WBM
Lubricity
Lubricity
• Lower coefficient of friction = good lubricity
• Higher coefficient of friction = poor lubricity
0.45
Coefficient of Friction
0.4 0.35 0.3 0.25 0.2 0.15 0.1 0.05 0
SBM SBM
Metal to sandstone
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WBM with lubricant WBM + lubricant
Metal to shale
Advantages & disadvantages of SBM & WBM SBM Risk of unscheduled events • Low risk of costly “unscheduled” events, e.g. hole stability problems, stuck pipe, etc. Subject to good “drilling practices” due to close to gauge hole.
WBM Risk of unscheduled events • Much higher risk of costly “unscheduled” events, e.g. hole stability problems, stuck pipe, etc.
Long reach “step out” wells
Long reach “step out” wells
• Extended long reach “step out” range (distance) due to the lower co-efficient of friction ie lubricity significantly reduces torque & drag values.
• Diminished long reach “step out” range (distance) due to the higher co-efficient of friction ie higher torque & drag values and potential hole stability problems related to time!
Stuck pipe
Stuck pipe
• Generally easier to recover from mechanically stuck pipe and “twist off” type incidents, i.e lubricious, stable & close to gauge well bore conducive to more successful “jarring/ fishing” operations.
• Generally more difficult to recover from mechanically stuck pipe and “twist off” type incidents, i.e less lubricious, hole stability “time” dependant and possibility of “out of gauge” well bore results in a more challenging “jarring/ fishing” environment.
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Advantages & disadvantages of SBM & WBM SBM
WBM
Hole stability (time)
Hole stability (time)
• Extended “time period” before the onset of hole instability problems. Especially significant when unscheduled events are encountered, eg pipe twist off, rig shut down for cyclones, etc.
• Limited “time period” before onset of open hole stability problems. High risk of unscheduled events resulting in stuck pipe and probable requirement to side track.
Fluid loss
Fluid loss
• Low invasion rates ( fluid loss properties) moderate the rate at which the rock matrix weakens followed by hole stability problems.
• Higher invasion rates ( fluid loss properties) accelerates the rate at which the rock matrix weakens followed by hole stability problems.
Tools – Corrosion & frictional wear
Tools – Corrosion & frictional wear
• Minimal corrosion and frictional wear of tools & equipment due to a lower co-efficient of friction and the preferential “oil wetting” of steel surfaces.
• Increased corrosion rates and higher frictional wear on tools and equipment due to a higher co-efficient of friction and a water / seawater environment.
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Advantages & disadvantages of SBM & WBM SBM
WBM
Fluid loss
Fluid loss
• Low invasion rates ( fluid loss properties) moderate the rate at which the rock matrix weakens followed by hole stability problems.
• Higher invasion rates ( fluid loss properties) accelerates the rate at which the rock matrix weakens followed by hole instability problems.
FL Value, dP 500psi @300F - cc
PPA spurt loss & total fluid loss SBM vs WBM 18 16 14 12 10 8 6 4 2 0
HtHp fluid loss graphs SBM
16.8
WBM
3.2 0.2
0.6
Bridging agent PSD optimised to minimise invasion at assumed 60 micron pore throat size SCOMI OILTOOLS
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Advantages & disadvantages of SBM & WBM SBM
WBM
Fluid loss
Fluid loss
• Low invasion rates ( fluid loss properties) moderate the rate at which the rock matrix weakens followed by hole stability problems.
• Higher invasion rates ( fluid loss properties) accelerates the rate at which the rock matrix weakens followed by hole instability problems.
FL Value, dP 500psi @250F - cc
HtHp fluid loss SBM vs KCL / Glycol / polymer WBM 11.0
12 10
SBM
8
WBM
6 4
1.0
2 0
Mud weight 10 ppg - High-mod prima clay 35 ppb – Hot rolled @ 250 deg F for 16 hrs SCOMI OILTOOLS
Advantages & disadvantages of SBM & WBM SBM
WBM
Inhibition & dispersion properties
Inhibition & dispersion properties
• Continuous oil phase is non-polar, ie does not react with clays, shales and mudstones.
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Shale in oil
• Continuous water phase does react with clays, shales and mudstones, resulting in significant hydration and dispersion. The degree of hydration and dispersion depends upon the type of WBM system selected.
Shale in fresh water
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Advantages & disadvantages of SBM & WBM SBM
WBM
Logging
Logging
• Petrophysical log evaluation more demanding. However gauge hole & minimal invasion / filter cake thickness requires less rigorous correction & correlation of log data, e.g. neutron density, gamma ray, resistivity, sonic, etc.
• Enhanced petrophysical log evaluation. However, out of gauge hole & higher invasion / filter cake thickness requires careful and rigorous correction & correlation of log data, e.g. neutron density, gamma ray, resistivity, sonic, etc. * Hole gauge depends upon type of WBM system used.
• New logging tools have been successfully developed to provide reasonable image log quality.
• Excellent image log quality.
Mud weight
Mud weight
• Generally lower mud weight overbalance required to maintain well bore pressure support over time. Minimal invasion = low pore pressure penetration.
• Generally higher mud weight overbalance required to maintain well bore pressure support over “time”, ie higher invasion rates = higher pore pressure penetration. Invasion rates are dependant upon type of WBM system.
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Advantages & disadvantages of SBM & WBM SBM
WBM
Gasses
Gasses
• High hydrocarbon gas solubility in oil at down hole pressures. Minimal reaction time due to rapid expansion of gas near surface. • H2S soluble in oil but comes out of solution when mud alkalinity is depleted, ie excess lime content. Serious health & safety implications for rig personnel if H2S is not managed properly at surface.
Gas solubility in mineral oil, ester & olefin
1600
Gas Oil Ratio (scf/stb)
1400
Bubble point, ie gas coming out of solution near the surface as the pressure diminishes
• Hydrocarbon gasses insoluble. Acid gasses H2S & CO2 soluble in water, resulting in serious mud problems together with H2S health and safety implications for rig personnel.
Olefin
1200
Mineral oil
Ester
1000 800 600 400 200 0
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0
2000
4000
6000
8000
10000
12000
Pressure (psi)
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Advantages & disadvantages of SBM & WBM
SBM
WBM
Identifying hydrocarbons
Identifying hydrocarbons
• Some difficulty identifying hydrocarbon shows but can be managed with preparatory GC scan and analysis of synthetic oil properties.
• Less difficulty identifying hydrocarbon shows but some WBM additives can interfere with hydrocarbon analysis.
Elastomers (rubber parts)
Elastomers (rubber parts)
• Low elastomer resistance to solvents in SBM. Requirement for rigorous testing of selected base oil at maximum prognosed BHT.
• Higher elastomer resistance to most WBM additives.
Temperature conductivity
Temperature conductivity
• Temperature conductivity high. Significant mud temperature increases when drilling and circulating mud at high pump rates for long periods of time.
• Temperature conductivity lower. Not as significant when drilling and circulating at high pump rates for long periods of time.
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Advantages & disadvantages of SBM & WBM SBM
WBM
Drill solids tolerance
Drill solids tolerance
• High tolerance to drill solids.
• Low tolerance to drill tolerance.
SBM – drill solids contamination test
WBM – drill solids contamination test YP
60
60
50
50
40
40
30 20
YP PV
YP
PV
10
YP
30
PV 20
PV
10
0
0
Base mud SCOMI OILTOOLS
+ 45 ppb Drill Solids
Base mud
+ 45 ppb Drill Solids
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Advantages & disadvantages of SBM & WBM SBM
WBM
Sensitivity to common drilling fluid contaminants
Sensitivity to common drilling fluid contaminants
• SBM impervious to most common contaminants.
•
Exceptions: - Ester oil / cement contamination will cause the ester to hydrolise ie “waxing out” - Substantial / rapid influx of water can lead to severe “water wetting” of drill solids and barite as a result of severe emulsion instability.
High, but dependant upon type of WBM selected. Examples: • Reaction to clays, shales and mudstones - Potential for clays, shales and mudstones to hydrate and disperse • Calcium contamination (eg cement, anhydrite) - Retards performance of most polymers - Flocculates Bentonite based systems • Carbonate/bicarbonate contamination - Flocculates Bentonite based systems
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Advantages & disadvantages of SBM & WBM
SBM
versus
WBM
?
Potentially good drilling performance. Hole stability time dependant & dependant upon appropriate mud system design
Lower overall risks and well costs in challenging drilling environments
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Higher overall risks and well costs in challenging drilling environments
Moderate to significant environmental impact. Various options available to manage environmental impact, eg dependant upon type of base oil and physical environment, ie seawater temperature, seawater current activity, depth of deposition, etc
?
Moderate environmental impact dependant upon type of WBM system used
Optimum drilling performance
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