Oil Base Muds
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Transcript of Oil Base Muds
History
1920’s -Origin of non-aqueous drilling fluids - crude
1940’s -DIESEL BASED muds developed - emulsifiers
1980’s -Environmental concerns lead to the use of MINERAL OILS – ‘Lo Tox’
1990’s -Environmentally acceptable replacement for mineral oils. SYNTHETICS
Zero Discharge operations becoming the norm. This is leading to a re-appraisal of cheaper systems.
Oil & Synthetic Mud Applications
Shale inhibition
High temperature wells
Lubricity
High angle extended reach wells
Contaminates, evaporites and acid gases
Spotting fluids
Workover, completion & packer fluids
Typical Oil Base Mud Cuttings With
PDC Bit
Oil & Synthetic Mud
LimitationsEnvironmental
Cost
Hydraulics, hydrostatic pressure, and ECD
calculations are complicated
Increased consequences of lost circulation
Gas solubility makes kick detection difficult
Wireline Logs are more complicated
Invert Emulsion Muds
THREE PHASE SYSTEM - Two immiscible fluids, and the solids phase
OIL / SYNTHETIC FLUID - continuous - external
phase, lipophilic liquid product additives.
WATER - emulsified droplets (CaCl2 brine), as
internal phase, soluble lime.
SOLIDS - barite, organophilic clays, drill solids, insoluble additives - fluid loss control products, LCM, etc. (soluble additives)
Continous Phase
OILSDIESEL
MINERAL OILS
SYNTHETIC FLUIDSESTER
LP’s - Linear Paraffin's
Linear Paraffins
Sarapar 147
Typical Properties:
Chemical Composition (% m):
N- Paraffi ns 95 min
I so - paraff fi ns <5
Napthanics <0.1
Aromatics <0.01
Density 773 kg/ m3 at 15 degrees C
Sulphur <3 ppm
Saybolt Colour 30
Boiling Range 258 - 293 degrees C
Flash Point 120 degrees C
Pour Point 12 degrees C
Vk40 2.5 mm2/ s
Water Phase
CALCIUM CHLORIDE BRINE:
Ca(Cl)2 Reduces the activity(Aw) of the water
phase.
Fresh Water (Aw) = 1.0
NaCl (Aw) =1.0 - 0.75 (26% = saturation)
Ca(Cl)2 (Aw) =1.0 - 0.39 (40% = saturation)
25%-30% By wt. Ca(Cl)2 (Common range for oil muds)
(Aw) = 0.74 - 0.637
Water phase salinity
The water phase salinity is controlled to provide an osmotic force that will tend to draw water from the formation to the water phase of the mud.
Water phase salinity (WPS)
The osmotic potential of the mud is the salinity of the water phase. This has to be greater than the osmotic potential from the formation
The water phase salinity must be greater than the shale salinity and the shale suction potential
Osmotic pressure of a shale
The osmotic pressure of a shale is generated in two ways. Firstly, during diagenesis, water is forced out of the shale because of compaction (or generation of matrix stress).
Diagenetic water leaving the shale has a lower salinity than water remaining in the pore spaces. The resultant shale salinity will be higher.
Osmotic pressure of a shale
During compaction, pore spaces are reduced.
In drilling a shale, there will be a tendency for the rock to be released from stress at and near the bore hole wall.
This release of stress will tend to cause expansion and resulting increase in pore volume.
Osmotic pressure of a shale
If there were to be an increase in pore volume, there would be a suction potential for water into the shale.
If water can be prevented from entering the shale, the suction potential will provide stabilisation by minimising pore volume expansion.
Water phase salinity
Emulsions
Oil External Phase
Oil wet solids & surfaces
Desirable for Drilling
Water
Oil Phase
Oil
Water Phase
Water External Phase
Water-wet solids & surfaces
Cementing / Stimulation
WBM Emulsion
Invert Emulsion
Solids Phase
Weight Material - Barite, Haematite, CaCo3
Organophilic clays
Drill Solids
Insoluble Additives - LCM Products
Soluble Additives
CaCl2, Lime
Oil Water Ratio
OIL WATER RATIO
The relative proportions of oil and water in the fluid.
Both the water and the solids phases are inside the oil, therefore the more of each will require more oil to maintain the same rheology.
If density is increased then usually more oil is needed. The oil water ratio is increased.
Emulsifiers
SURFACTANTS - Surface Active Agents.
Act by Reducing the Interfacial
Tension Between Two Liquids or
Between a Liquid and a Solid.
Emulsifiers Soaps Wetting Agents
SURFACTANTS - Surface Active Agents Have a hydrophilic polar head and an organophilic non-polar
tail.
HYDROPHILIC HEAD
(WATER LOVING)
(OIL LOVING)
ORGANOPHILIC TAIL
CC CC CC C C C C
CC C C C C C C
OO
CC
OHOH
Emulsifiers
WATERWATER
DROPLETDROPLET
OILOIL
Emulsifiers
WATERWATER
DROPLETDROPLET
WATERWATER
DROPLETDROPLET
INSUFFICIENT
EMULSIFIER CONCENTRATION
COALESCINGCOALESCING
OF DROPLETSOF DROPLETSWorstWorst
CaseCase
Emulsifiers
SOLID’S SURFACESOLID’S SURFACE
- Designed to Oil Wet solids- Designed to Oil Wet solids
Emulsifiers
Viscosifiers
VISCOSIFIERS:
Are usually bentonite based with an oil wetting agent added.
They need a small quantity of water to allow hydration.
They take time to fully yield.
Fluid Loss Reducers
FLUID LOSS REDUCERS:
Asphalt
Gilsonite
Amine treated lignite
Calcium carbonate/marble – bridging agents
Supplementary Additives
OTHER PRODUCTS:
Lime - Ca(OH)2
Quick Lime - CaO
Standard API Tests for Inverts
Mud weightRheology @ 120o, 150o or 180oFHTHP Filter Press @ 300°F or bottom hole temperatureElectrical Stability (ES) @ 120° or 150oFRetort (% oil/synthetic, %water, %solids)Pom, PsmCl- (whole mud)
Retort Analysis of Inverts
Accuracy!Retort allows us to determine:
% Solids% Oil or Synthetic fluid% Water Salt content
Watch for trends and major changes
Problems: Oil / Synthetics
Insufficient Viscosity
Excessive Viscosity
Solids Contamination
Salt Water Flows
Water Wet Solids
Carbon Dioxide - CO2
Hydrogen Sulfide - H2S
Massive Salts and Salt Stringers
Barite Sag / Settling
Lost Circulation
Insufficient Viscosity
Barite Settling
Inadequate Hole Cleaning
Treatment:Add Viscosifiers - Clay, Polymer, Mod.
Add Water(Brine)
Shear Brine
Excessive Viscosity
Solids - High, Fines, Water Wet.
High Water Content.
High Temperature Instability.
Acid Gasses.
Water wet Solids.
Over-treatment with Viscosifiers.
Treatment:Remove / Dilute - Solids,Water Content.
Add - Emulsifier,Wetting Agent,Versathin, Lime, Increase mud weight.
Solids Contamination
High viscosity
Thick filter cake
Treatment:Finer mesh shaker screen
Tandem centrifuges
Dilute with base fluids and add emulsifier
Wetting agent
Salt Water Flows
Increased % water and decreased oil:water ratio
High viscosity
Water wet solids
Lower Electrical Stability
Water in HTHP filtrate
Treatment:Emulsifier and lime
Wetting agent for weight up or water wet solids
Barite to adjust weight and stop influx
Water Wet Solids
Increased viscosity
Decreased Electrical Stability
Grainy appearance
Settling
Shale shaker screen blinding
Test
Treatment:If brine phase salt saturated, add fresh water
Wetting agent
Carbon Dioxide CO2
Decrease in POM Decrease in lime contentDecrease in Electrical StabilityTreatment:
Add lime to maintain an excess, use caution to control excess lime in ester based fluidsIncrease mud weight to control influx
Hydrogen Sulfide, H2S
Sulfides detected with Garrett Gas Train
Decrease in POM Decrease in lime contentDecrease in Electrical StabilityMud may turn blackTreatment:
Inorganic zinc scavengerMaintain excess lime contentIncrease mud weight to control influx
Massive Salts & Salt Stringers
Salts are insoluble, may become a low gravity solids problem
Formation CaCl2 and MgCl2 may cause water wetting of solids
Sticking from plastic flow (not differential)Displace annulus from bit to free point with fresh water spot
Barite Sag / Settling
Sag, uneven mud weights on bottoms up after tripsTreatment:
Increase Low Shear Rate Viscosity
Settling, static conditions and pits
Normal, increase Low Shear Rate ViscosityExcess wetting agent (hard pack), add organophilic clay and polymer. Do not add wetting agent.Water wet barite indicated by tests - add wetting agent
Lost Circulation
Compressibility increases density at depth and the likelihood of fracturing formation
Some LCM such as cellophane and cane fiber can break the emulsion
Treatment:Mica, nut hullsReverse gunk squeeze (organophilic clay in water - No Cement)
Displacement
Meet, communicate, organize.
Condition displaced mud to lowest rheology and displacing fluid with higher rheology.
Do not begin until all displacing fluid is on location.
Spacer to cover 500’ to 1,000’ of annulus.
Pump at a rate approaching turbulence.
Do Not Stop circulating once displacement has started.
Rotate / Reciprocate Pipe
Displacement
Place bit near bottom as oil mud clears.
Change screens.
Add Wetting agent.
Monitor with Stability meter.