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.