Some Basics on OBM

8/9/2019 Some Basics on OBM

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OIL-BASED MUDS & SYNTHETIC-BASED MUDS:

Formulation, Engineering, Field habits and Recommendations.

Through this memo, we expect:

• to present the materials oil-based muds (OBMs) or synthetic-based muds (SBMs) are made of

(most of the time, such muds are water-in-oil, 'invert', emulsions),

• to give information about basic engineering calculations in the lab, including units conversions,

•

to give adequate information and field habits to effectively solve formulating problems.

Some of these information are also included in an XL-based program (currently under

development) to design drilling fluids.

I. Applications of OBMs.

OBM offers many advantages over water muds. Cost and environmental disposals can be factors in

not selecting this type of mud system.

Some of the advantages of OBMs are described in table 1.

Some information have beenremoved to respect confidentiality(e.g. structure shown in picture 1)

Do not hesitate to contact me [email protected] foradditional information or details.


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Shale stability

Oil-muds are most suited for drilling water sensitive shales. Indeed, oil is the

continuous phase and water is dispersed in it: the whole mud results non reactive

towards shales.

Even if water is dispersed, it is however desirable to have enough salinity to

prevent water migration into the shale without dehydrating it. This is the

"balanced activity" concept(1). The adequate salinity is to be determined through

field experience.

Penetration rate Oil-muds usually allows to drill faster than with water-muds, still providing

excellent shale stability.

High

Temperatures

Oil-muds are suited to drill formations where BHT(2) exceeds WBMs tolerances,

especially in the presence of contaminants, e.g. water, gases, cement, salts, up to

550 F.

Drilling salts

Invert oil-muds do not leach out formation salts. The addition of salt to the water

phase prevents the formation salts from dissolving into the emulsified water

phase.

Lubricity An oil-mud has a thin filter cake and the friction between the pipe and thewellbore is minimized, thus reducing the risk of differential sticking.

Especially suited for highly deviated and horizontal wells.

Low pore

pressure

formations

The ability to drill low pore pressure formations is easily accomplished since the

mud weight can be maintained at a weight less than that of water (as low as 7.5

ppg).

Corrosion

control

Corrosion of pipe is controlled since oil is the external phase and coats the pipe.

The most interesting properties regarding corrosion are that oils are non-

conductive, additives are thermally stable and do not form corrosive products,

and bacteria do not thrive in oil-muds.

Re-Use

Oil-muds are well-suited to be used over and over again. They can be stored for

long periods of time since bacterial growth is suppressed.

Packer fluids

Oil-mud packer fluids are designed to be stable over long periods of time even

when exposed to HT(3). Oil-muds provide long-term stable packers since the

additives are extremely temperature-stable.

Since oil is the continuous phase, corrosion is almost negligible compared to

WBMs in the same conditions. Properly designed, such packer fluids can

suspend weighting materials over long periods of time.Table 1: Some advantages of Oil-Based Muds.

II. OBMs Basic Chemistry.

Invert emulsions (the most common OBMs) are formulated to contain moderate to high

concentrations of water (up to 60% in extreme conditions).

Special emulsifiers are added to emulsify the water as the internal phase and prevent the water from

breaking out and coalescing into larger droplets.

These water droplets, if not tightly emulsified, can water-wet the already oil-wet solids and

dramatically affect the emulsion stability.

(1) The balanced activity concept is shortly described in annex 1. Shale swelling is a required notion to explain the needof this concept: it is briefly explained in annex 2.(2)

BHT = Bottom Hole Temperature.(3)

HT = High Temperatures.


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Tables 2 and 3 present chemicals entering in the composition of OBMs.

Base Oil

In many areas, though quite detrimental to environment, diesels were used to

formulate and maintain OBMs. Crude oils had sometimes been used too, instead

of diesel, but posed tougher safety problems.

Thus today, mineral oils & new synthetic fluids replace diesel and crude due to

their lower toxicity, new synthetic fluids being of course farther less toxic than

any other base oil.

WaterWater is an integral part of the invert emulsion and can contain salts such as

calcium or sodium chloride. Sea-Water is often used offshore.Table 2: continuous and dispersed phases of OBMs.

Oil muds require special products to ensure that the emulsion is extremely stable and can

withstand conditions of HT and contaminants. Every single product must be dispersible in the

external oil phase.

Emulsifying

Systems

Calcium soaps are the primary emulsifier in oil muds. These are made in the

mud by reaction of lime and long-chain fatty acids. Soap emulsions are strong

emulsifying agents but may take reaction time before emulsion is actually

formed.

Thus secondary emulsifiers are used : they consist in very powerful oil-wetting

chemicals which generally do not form emulsions but wet solids before the

emulsion is formed. Also used to prevent from any water intrusion.

Lime

Lime is essential in OBMs. It neutralizes fatty acids in the fluid, stabilizes the

emulsion when present in excess, and controls alkalinity. In the field, it alsoneutralizes acid gases (H2S and/or CO2)

Fluid Loss

Reduction

Additives

Many types of chemicals can be used as Fluid Loss control agents. They are

usually organophilic lignites (amine-treated lignites), Gilsonite or Asphalt

derivatives, or special polymers (polyacrylates, ...).

The impact of such products on rheology depend on their nature. For instance,

lignites (even used at high concentration) do not affect viscosity, whereas asphalt

derivatives can cause excessive viscosity and/or gelation.

Wetting AgentsSupplemental additives to quickly and effectively oil-wet solids that became

water-wet.

Chemicals to

control rheology

Additives that build the viscosity of the mud.

Bentonite, hectorite or attapulgite, treated with amine to make them oil-dispersible, are the commonly used organophilic gellants. When their properties

are reduced by HT, polymeric viscosifiers are added.

Other rheological modifiers increase the viscosity at low shear without

increasing total mud viscosity, e.g. low molecular weight fatty acids. Deviated

wells are good conditions of use for such products.

Weighting

agents

Used to increase the density of the oil mud. The most commonly used are

Calcite (M.W. up to 10.8 ppg), Barite (M.W. up to 21 ppg), and Hematite (M.W.

up to 24 ppg).Table 3: main chemicals to prepare OBMs.


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III. Synthetic-Based Fluids for Oil Muds Replacement.

The first use of oil as a drilling fluid is not known. It is likely, however, that someone thought of

using produced crude to drill the well, assuming that this would eliminate wellbore damage that can

occur with water contact.

Crude oils were difficult to use as drilling fluids, so refined oils and processed asphalts replaced

them. A number of mud products came into, being to control the normal mud properties of viscosity

and fluid loss and to emulsify water.

However, even mineral oils were cast in unfavourable light as being non-biodegradable, and indeed

some regulators did not like the use of any petroleum hydrocarbon oil in offshore drilling, both

from a spill standpoint and due to discharges of oil-covered cuttings. For instance:

•

discharge of oil-wet cuttings is not tolerated anyway in the North Sea Regions

• in the Gulf of Mexico, discharge of oily cuttings is more or less tolerated depending on the

amount and the type of oil that wets the particles:

• not tolerated if the oil is mineral oil or diesel,

• tolerated for Internal Olefins (IO) if cuttings are covered with a maximum of 6% of oil,

• tolerated for esters oils if cuttings are covered with a maximum of 9% of oil.

A variety of synthetic materials have been developed since 1993 to replace diesel and mineral oils.Some of these newer materials sometimes behave more as water-based muds than oil-based muds.

The particular type of fluids chosen is based upon many factors, not the least of which is cost.

• Chemistry.

The toxicity of diesel oil is due to its high aromatic hydrocarbon content. All of the diesel

replacements either eliminate or minimize the aromatic content, thereby making the material non-

toxic or less toxic. As long as the material is within the guidelines established by regulatory toxicity

tests, the material can be used.

Biodegradation and bioaccumulation, however, depend more on the chemistry of the molecular

character of the base fluid. In general, those green materials containing oxygen within their

structure degrade easier.

Degradation, though, is highly dependent upon the specific conditions impacting the fluid.

Laboratory tests do not necessarily reflect the conditions found at the bottom of the ocean. A lab

test is however the only way we have of judging these materials and determining relative rankings.


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The following are basic descriptions of the chemical characteristics of the synthetic base fluids used

to make a SBM:

• water insoluble:

• Ester: made from vegetable oil by reacting the fatty acid with an alcohol, e.g.:

• PETROFREE™

• FINAGREEN™ (fatty acid esterified with 2-ethylhexanol, R # C18 including one

double-bond C=C)

Picture 1: FINAGREEN™ chemistry.

• ECOGREEN™

• Di-ether: ethers are made by reacting the proper alcohols to give the mono-ether which is

then converted into the di-ether, e.g. AQUAMUL II™,

• PAO: polyalphaolefin is a straight chained hydrocarbon made from ethylene (in fact, from

the catalytic dimerization of LAOs such as 1-octene – see below). The resulting product

has no aromatic content, e.g. NOVADRIL™,

• Linear Alpha Olefin (LAO): LAOs are the result of the oligomerization (low molecularweight polymerisation) of ethylene molecules,

• Internal Olefin (IO): IOs are isomers (same chemical formula with different structures,

e.g. the position of or carbon double-bond) of the LAOs, e.g. NOVAPLUS™,• Linear Paraffin (LP) are saturated linear polymers made from ethylene, e.g.

PARADRIL™,

• Detergent alkylate: also known as a linear detergent alkylate (Linear Alkyl Benzene,

LAB), these materials are widely available and do not cost as much as the other synthetics.

They are used as an intermediary in the production of various detergents. LABs are

manufactured by reacting a saturated hydrocarbon with benzene. They do contain a small

amount of aromatics.

• water soluble or partially soluble:

• Polyols: polyhydric alcohols, chemicals with multiple OH groups attached, include glycols

(dihydric) and glycerols (trihydric) as well as a variety of sugar alcohols. Polyols for muduse refer to the polymeric form of these polyhydric alcohols. They can be manufactured to

a variety of molecular weights from a variety of raw materials. Some commercial products

are BIO-DRIL 1402™ or HYDRA-FLUIDS HF-100™,

• Methyl Glucoside (MEG): This product is a derivative of the sugar glucose. It has a

methoxy side group (-OCH3) on the glucose ring that stabilises the molecule. The molecule

itself has four hydroxyl groups (OH) attached to the ring. Example: GEO-MEG™.

Any of these materials can be manufactured to varying carbon chain lengths and differing amounts

and types of side chains and hydroxyl, oxygen, ester or ether components.


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Amoco researchers in various IADC/SPE Drilling Conferences and papers(4) stated that: "SBMs are

safer to work with, more biodegradable in seawater than conventional OBMs. On the other hand,

SBMs are more viscous at low temperatures, thin more with increasing temperature, have lower

thermal stability and do not dehydrate shales as readily as conventional OBMs. By adjusting the

emulsifier package in each mud, these properties may be brought more in line with those of

conventional OBMs."

• Solubility, Dispersibility and Field Use.

The functionality of these synthetics and the manner in which muds are formulated and handled

depend primarily upon their solubility in water.

The water insoluble chemicals are more analogous to conventional oil muds in that they are run as

water emulsions in the synthetic fluid. They need additives similar to the OBMs' emulsifier package

and special viscosifiers.The water soluble chemicals, however, can be run like WBMs, using regular fluid loss additive and

polymer viscosifiers.

Bentonite will not yield in these fluids, but can be used in the water soluble SBMs if pre-hydrated.

SBMs were proved to all be more dispersible in sea water than mineral or diesel muds. This is very

positive since it allows easier removal of the SBMs from drilled cuttings. Lab tests gave relative

ease-to-removal rankings of:

Ester > Di-ether > LAB > PAO > mineral oil > diesel > Crude oil

The polyols and MEG are different in that they are either soluble or partially soluble in water. This

means they are more like WBMs in how they are handled and in the additives used to make a mud

formulation.

Lab tests have shown that formulating muds with greater than 60 v. % MEG stabilises in a manner

similar to OBMs, but still gives the handling properties of WBMs. We do not have any information

about potential field tests using such fluids.

• Cost factors.

From the point of view of the cost of raw materials to prepare muds, SBMs are significantly more

expensive than either diesel oil or mineral oils on initial purchase: SBMs per-barrel costs are four tofive times greater than that for OBMs. The initial cost of muds can be ranked as shown below:

Water-Based Muds < Oil-based Muds < Synthetic-Based Muds

On the other hand, SBMs are less toxic and thus less restrictive towards regulation. Therefore, they

induce lower costs for cleaning, disposal of leftover mud, etc… Moreover, SBMs can be reusedmuch as OBMs are reused, as long as care is taken with fine solids loading, etc…

(4) especially in "Physiochemical properties of synthetic drilling fluids," by Growcock & Andrews, Amoco (918-660-

4224), IADC/SPE paper 27450, 1994 Drilling Conference; see also IADC/SPE paper 27496, 1994 Drilling Conference;

and IADC/SPE paper 2714, 1994 HS&E Conference, Jakarta.


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Conclusion is that many parameters linked to the mud impact the total cost of a drilling operation:

nature of the base fluid, ROP allowed due to the fluid, safety and environmental problems, nature of

the formation, etc… Every drilling operation is a single case to be considered individually.

• Other factors.

• Rheology: At ambient temperatures, SBMs base viscosity is 2 to 4 times higher than

mineral oil.

At increasing temperatures, however, SBMs thin significantly more than the oils. The

insoluble SBMs rely on regular oil mud additives for viscosity control, whereas the polyols

and MEG can be viscosified with materials such as xanthan gum.

• Shale dehydration potential : Available SBMs, but MEG ones, do not dehydrate shales as

readily as OBMs.

• Materials compatibility:

• Di-ethers and PAO react to elastomers exactly as mineral oils do.

• Esters are compatible with a wide range of elastomers.

• Detergent alkylates are likely to be less compatible due to their aromatic content.

IV. Basic Engineering Calculations.

This section discusses basic engineering calculations required in the lab. We do not deal with the

ones corresponding to situations at the rig.

A. Units Conversions.

At the beginning, the difficulties are the 'exotic' units used in the oilfield application. Tables 4 and 5

present conversions factors for metric and British units. This is required to better understand the

following sections.


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U N I T C O N V E R S I O N S

Conversion from metric to Conversion from English to

English unit metric unit

Metr.symbol Multiply by Eng.name Eng.symbol Multiply by Metr.symbol

mm 0,03937 Inches in 25,4 mm

m 3,28084 Feet ft 0,3048 m

m 1,09361 yards yd 0,9144 m

km 0,621373 miles(land) mile(st) 1,60934 km

l 0,264178 gallons(US) gal(US) 3,78533 l

l 0,0353147 cubic feet cu.ft 28,3168 l

m3 6,28994 barrel bbl 0,158984 m3

N 0,224809 pounds lbs 4,44822 N

kg 2,20462 pounds lbs 0,453592 kg

kPa 0,145038 psi psi 6,894745 kPaMpa 145,038 psi psi 0,0068947 Mpa

bar 14,5038 psi psi 0,0689475 bar

N.m 0,737561 foot pounds ft.lb 1,35582 N.m

kg.m 7,23301 foot pounds ft.lb 0,138255 kg.m

kg/m 0,671971 pounds/foot lb/ft 1,48816 kg/m

kg/l 8,34523 pounds/gallon ppg 0,119829 kg/l

kg/l 62,4278 pounds/cu.ft pcf 0,0160185 kg/l

kg/m3 0,3505 pounds/barrel lb/bbl 2,85307 kg/m3

m3 /h 150,959 barrel/day bbl/day 0,00662433 m3 /h

l/m 0,001917 barrel/foot bbl/ft 521,601 l/m

l/m 0,0107640 cu foot/foot cu.ft/ft 92,090289 l/ml/m 0,0805214 US gallon/foot gal/ft 12,4191 l/m

l/m 0,0062899 barrel/meter bbl/m 158,984 l/m

kPa/m 0,0442076 psi/foot psi/ft 22,62055 kPa/m

bar/m 4,42076 psi/foot psi/ft 0,2262055 bar/m

kPa/m 0,145038 psi/meter psi/m 6,894745 kPa/m

bar/m 14,5038 psi/meter psi/m 0,0689475 kPa/m

kW 1,34102 horse power hp 0,7457 kW

103daN.km 0,69832 Ton.mile Ton.mile 1,43201 10

3daN.km

Table 4: conversion factors.


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U N I T C O N V E R S I O N S

Conversion between metric units

"A" "B" "C" "D" "E" "F"

Metr.symbol Multiply by Metr.symbol Metr.symbol Multiply by Metr. Symbol

bar 100 kPa kPa 0,01 bar

bar 0,1 MPa MPa 10 bar

N 0,102 kg kg 9,80665 N

daN 1,02 kg kg 0,980665 daN

N.m 0,102 kg.m kg.m 9,80665 N.m

Conversion between British units

"A" "B" "C" "D" "E" "F"

Eng.symbol Multiply by Eng.symbol Eng.symbol Multiply by Eng.symbol

in 0,0833333 ft ft 12 in

ft 0,333333 yd yd 3 ft

yd 0,0005682 Mile (stat) Mile (stat) 1760 yd

yd 0,0004929 Mile (naut.) Mile (naut.) 2029 yd

sq in 0,0069444 sq ft sq ft 144 sq in

sq ft 0,111111 sq yd sq yd 9 sq ft

sq yd 0,0002066 acre acre 4840 sq yd

acres 0,0015625 sq mile(stat) sq mile(stat) 640 acre

cu in 0,0005787 cu ft cu ft 1728 cu in

gal(US) 0,1336777 cu ft cu ft 7,48068 gal(US)

cu ft 0,1781113 bbl bbl 5,614467 cu ft

gal(US) 0,0238095 bbl bbl 42 gal(US)

oz 0,0625 lbs lbs 16 oz

lb 0,0005 sh. tn sh. tn 2000 lbs

gal/ft 0,1336777 cu.ft/ft cu.ft/ft 7,48068 gal/ft

cu.ft/ft 0,1781113 bbl/ft bbl/ft 5,614467 cu.ft/ft

gal/ft 0,0238095 bbl/ft bbl/ft 42 gal/ft

ppg 7,48068 pcf pcf 0,1336777 ppg

Table 5: conversion factors.

B. Specific Gravity.

The density of any material is derived by multiplying the specific gravity by the density of pure

water (8.32 ppg(5)).

Density = SG x 8.32

For example, the average specific gravity of barite is 4.2 and its density is equal to (4.2 x 8.32) # 35

ppg.

Conversely, to convert from density to specific gravity, divide the density of a material or mud by

the density of pure water.

As an example, a 17.5 ppg mud has a specific gravity of 2.1 (=17.5/8.32).

(5) ppg = pounds per gallon


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To determine the weight of 1 bbl (6) of barite, determine the density of 1 bbl of pure water and

multiply the result by the specific gravity of barite.

weight of 1 bbl of pure water = 8.32 ppg of water x 42 gal/bbl # 350 lb/bbl (7)

⇒ weight of 1 bbl of barite = 350 lb/bbl x 4.2 SG # 1470 lb/bbl

=> Weight of 1 bbl of material = 350 x SGmaterial

C. Weight up and Dilution.

1. Weight Up.

• Volume increase: the general mud weight increase formula is used for any weighting materialwhere SGWM is the specific gravity of the weighting material, MW i and MWf are the initial and

final mud densities in ppg. It calculates the volume increase of mud once a weighting agent is

added.

Volume increase, bbl = total pounds weighting material / (350 x SGWM)

For barite, this becomes:

Volume increase, bbl = total pounds barite / 1470

• No volume increase: addition of weighting agent leads to volume increase. To determine theinitial volume of mud, Vi, to start with to attain a final volume V f without volume increase, the

starting volume is defined by:

Vi / Vf = [(8.32 x SGWM)-MWf ] / [(8.32 x SGWM)-MWi]

For barite, this becomes:

Vi / Vf = (350-MWf ) / (350-MWi)

To calculate the pounds of weight material required per final barrel of mud :

weight material, lb/bbl = [(350 x SGWM) (MWf - MWi)] / [(8.32 x SGWM) – MWi]

For barite, SGWM = 4.2, the equation becomes:

weight of barite, lb/bbl = [1470 x (MWf - MWi)] / (35.0 - MWi)]

2. Density reduction with oil addition.

volume of dilution, bbl = [(Vi x (MWi – MWf )] / [MWf – (SGo x 8.32)]

(6) lb = pound ; bbl = barrel (blue barrel in fact)

(7) gal = gallon


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SGo the specific gravity of oil depends on the chemical nature of oil. For diesel it is approximately

0.84. If the specific gravity is unknown, density may be measured and substituted for (SGo x 8.32)

in the equation.

D. Concentrations – Weight percent and volume percent.

The concentrations of components in mixtures or solutions can be expressed as weight percent or

volume percent.

Percentages of components in a mud can be calculated if the mud density and the specific gravity of

the components are known for a two-part system (liquid + solids). An average specific gravity of

solids must be assumed for calculating percent solids in a mud. The following are general equations

for volume percent (v.%) and weight percent (w%).

•

volume percent of solids (S = solids, l = liquid).

v.%S = [12 x (MW – 8.32 SGl)] / (SGS – SGl)

• weight percent of solids.

w.%S = (8.32 x SGS x v.%) / MW

• Example: In a sea water (SW) mud, calculate the v.% and w.% of the solids assuming that

MW=10.4 ppg, SGSW = 1.04, SGS = 2.6.

v.% = [12 x (10.4 – 8.32 x 1.04)] / (2.6 – 1.04) = 13.4w.% = (8.32 x 2.6 x 13.4) / 10.4 = 27.8

• Parts per Million (ppm) and Milligrams per liter (mg/l).

Milligrams per liter is a weight per volume measurement. On the other hand, parts per million refers

to a weight per specified weight measurement or a volume-per-volume measurement. Basically,

ppm is a ratio. It is very important to understand the difference between the two units. The

following equations will contrast the difference in the two measurements.

ppm = (mg/l) / SGw

SGw = 1 + (1.94 10-6

[Cl-]0.95

), where [Cl-] is expressed in mg/l

• Example: How many ppm of NaCl are in 1 cm3 of filtrate that contains 140 000 mg/l chlorides ?

SGw = 1 + (1.94 10-6 x 140000 0.95) = 1.1502

[Cl-] = 140 000 / 1.1502 = 121 718 ppm.

⇒ NaCl = 121 718 x 1.65 = 200 835 ppm.


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E. Material Balance.

Material balance concepts are useful to the driller for solving many field problems that can be

represented as simple mathematical balance method are :

• weight up,

• dilution,

• mixing two fluids,

• system building,

• solid analysis.

• Weight up – Volume increase.

old fluid weight material new fluid

Volume, bbl Vi X -

Density, ppg MWi MWWM MWf

Since it is not known how much weighting material will be needed, its volume is represented by X.

Thus the new fluid volume equals Vf = Vi + X

old fluid + weight material = new fluid

Vi MWi + X MWWM = (Vi+X) MWf

⇒⇒⇒⇒ X, bbl = Vi (MWf -MWi)/(MWWM-MWf )

For barite this becomes, X, bbl barite = Vi (MWf -MWi)/(35.0-MWf )

1 bbl of barite ↔1470 lb

• Weight up – No volume increase.

old fluid weight material new fluid

Volume, bbl Vi X Vi

Density, ppg MWi MWWM MWf

Since it is not known how much weighting material will be needed, its volume is represented by X.

old fluid + weight material = new fluid

(Vi-X) MWi + X MWWM = Vi MWf

⇒⇒⇒⇒ X, bbl = Vi (MWf -MWi)/(MWWM-MWi)

For barite this becomes, X, bbl barite = Vi (MWf -MWi)/(35.0-MWi)

1 bbl of barite ↔1470 lb


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F. Oil Mud calculations.

The following set of calculations describes how to either raise or lower the oil/water (O/W) ratio of

an oil-based mud. If water enters an oil mud, the O/W ratio will decrease and if the O/W ratio is to

be raised, then oil will have to be added. The amount of oil required to raise the O/W ratio can be

calculated as follows:

• Raise O/W ratio – addition of oil.

(%oil + x) / %water = O/W desired

• If the O/W ratio is desired to be lowered, then water must be added based on the followingequation:

(%water + x) / %oil = O/W desired

• Example: a retort analysis gives : 52% v. of oil and 10% v. of water. How much oil is needed to

increase the O/W ratio to 88/12 ?

Therefore, (52+x) / 10 = 88 / 12

x = 21.3 %, i.e. 0.213 bbl oil / bbl mud

The resulting volume is 1 bbl mud + 0.213 bbl oil = 1.213 bbl.

To get one barrel of the final mud, we then need :

• 1 / 1.213 = 0.82 bbl mud

• 0.213 / 1.213 = 0.18 bbl mud.

V. Oil-Muds Formulating Problems.

The difficulties encountered when formulating both OBMs and SBMs are essentially linked to the

presence of a dispersed phase (brine) in the oily continuous phase. Moreover, every single OBM is

different from the other and require a dedicated mixing procedure.

We decided to write this document in order to assist people when formulating OBMs. The set of problems encountered when preparing SBMs are the same than those met with OBMs. Though they

are chemically and environmentally very different, we do not distinguish SBMs from OBMs in the

next sections.

A Mixing Procedure.

The addition of components in their proper sequence when initial mixing an oil mud, will optimize

the performance of each product. The order of addition as listed later in this paragraph is the most

common procedure for the preparation of oil-based muds, though each mud system may requiresome modifications of the procedure:


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• the mixing time may vary depending upon the amount of shear either at the rig or at the liquidmud plant,

• organophilic viscosifiers require considerable quantity of shear to fully develop their viscosity.

Therefore, more of this additive may be required on initial mixing.

•

as the oil mud is used over the first couple of days, the emulsion stability and fluid loss controlfor instance will vastly improve compared to what the mud was when initially mixed.

• this list of optimizations is not exhaustive and will be discussed later in this document.

General trends to prepare oil-based muds are:

• Add the required quantity of base oil to the mixing vessel,

• add the primary and secondary emulsifiers as required,

• add the organoclay gellant as required,

• add filtration control additives,

• add lime in excess,

• add required amount of brine,

• mix for a long time to ensure a good emulsion is formed. At the rig, this can be several hours,

• add weighting material as required for the desired density,

• note that other chemicals may added before brine (drilled solids simulator, TEA, …) or once the

emulsion is formed (thinners, corrosion inhibitors, …).

B Optimizing the rheology.

The first parameter to control is obviously the rheology.

The presence of an organoclay (it can be hectorite, montmorillonite, but most of the time, it consists

of treated hectorite of which most common product is known as bentone 38™), is essential in a

design.

However, bentone 38™ does not develop viscosity when dispersed in the oil phase. Viscosity

actually increases when the invert emulsion is formed, the organoclay being dispersed at the

interface between oil and water droplets.

Four components are then essential to develop viscosity:

• the oil phase,

• the water phase,

• the emulsifying package,• the organoclay.

Usual concentrations for the organoclay are 3-6 lb/bbl. Once brine is added, the viscosity increases.

Sometimes a very strong gel develops, depending upon the chemistry of the surfactants and/or the

nature of the oil. The mudman must then decide to act in one of the following way:

• if the mud has already been prepared and if it is not possible (cost, volumes, environment, …)

to prepare the whole mud again, then alternatives are:

• to add some thinners, preferably chrome-free; these additives reduce interactions at the

interfaces, but are often used as the last solution,


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• to add some emulsifying surfactants to thin the emulsion. This is effective only if theemulsion is quite big because one of the critical limitation is the mixing equipment

available at the rig. It must be kept in mind that muds designed in the lab must be easily

reformulated on the field.

• to remove low gravity solids with solids control equipment and/or to dilute the mud,

• to increase the O/W ratio if water content is too high.

• if the mud has not been prepared yet and if gelation is supposed to occur, the solution is to add

the organoclay once the emulsion is formed. This helps reducing the strength of the gel

developed. The role of the salt (nature, amount) which is contained in the water phase is critical

in the process of gel strength reduction.

Bivalent and trivalent ions-based brines are then more effective than monovalent brines. But

usually, on the field, invert emulsions are Sea Water-based. The complex and various

compositions of Sea Waters make this Gel-Strength reduction process very effective most of

the time.

On the other side, if viscosity is too low, it is to:• add water, emulsifier and gellant,

• if temperature is very high, add polymeric viscosifier.All of these affect the low-shear viscosity, gel strength and yield-point farther more than the plastic

viscosity.

C Stability of the emulsion.

1. Tests and definitions.

The stability of the mud is the critical parameter for mudmen.• Rheology: there are different ways to check the stability but the first one is the rheology.

Procedures are those described by the API Recommendations 13B-2 (available in the lab).

• Settling: another key-point is settling . Practically, we can consider that if no sag appears whenthe mud is heated at 120 F in the cup before measuring the rheology, the mud is considered as

stable regarding settling (see picture 2).

This test is, most of the time, sufficient to check potential sag.

Picture 2: photo and schematic representation of sag in a well.

• Suspending Ability: An additional test using a sand tube ("sand content kit") can be set up to

evaluate the ability of the mud to suspend sand grains. This can be a good way to study settling.

The principle is to measure the time a determined quantity of calibrated sand needs to settledown. The sand tube is graduated in volume fraction.

Clarified FluidSuspension Zone

Sag (Sediment) Bed

Slump

Barite bed formed in an inclined wellbore


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• The Electrical Stability (ES) is the standard procedure to decide whether an emulsion is stableor not. One will refer to the API 13B-2 for additional information.

We can consider a mud is stable when its ES is above 700 V, but this is only a relative

indication which depends on the nature of the oil, and thus has no significant meaning.

• It is possible to check visually the stability of the mud. Of course, if the emulsion is clearly broken, the design must be optimized, but that is not the only observation to be made. Visual

indicators can also prove a mud is dramatically weakened:

• A very bright mud is up to break,

• If grains or flocs are visible, the mud must be considered as unstable.

• The Bentonite contamination is not a very famous test but it is very useful to check thestability of the emulsion as it is consistent, most of the time, with stability field observations.

The procedure is the following:

• for 1 liter of mud, add 75 g/l of bentonite and mix for 5 min with the Hamilton Beach,

• go on adding bentonite, mixing for 5 min when 75 g/l have been added. Do it again, untilthe mud becomes unstable.

• it is of convenience that if the tolerance of an emulsion (no breaking) is at least 225 g/l of bentonite, this emulsion is stable.

2. How to control stability ?

As previously seen, the stability is linked to various aspects of the design. We can however define a

few key-points:

• Check the amount of surfactants: the first key-point is to check the amount of surfactants

(and their nature) used to make the invert emulsion.

• Check Lime content: once the amount of emulsifiers is designed it is of primary importance tooptimize the lime content of the mud. Lime is essential to the mud stability and mudmen use to

say that excess of lime benefits the mud whereas lack is detrimental to its stability.

It is thus to calculate the amount of lime required to both neutralize the acid functions of the

surfactants and control the alkalinity. It is easier to first express the amount of lime as a

function of the volume of brine, for the calculation, before converting it into ppb of mud for the

design; this is usually done because lime is actually essentially stored in the water phase.

Nowadays, some contractors may use TEA(8) to assist or even replace lime.

• Settling: if sag is observed while the viscosity is sufficient, the solution is to add some wettingchemicals. Indeed, in this situation, settling means most of the time that solids are water-wet.

We have to keep in mind that, in OBMs, every particle must be oil-wet. Sometimes a dilutionof the mud in oil is required before treating with wetting agents.

• Low Electrical Stability: water-wet solids, undissolved solids, inadequate concentration ofemulsifiers, inadequate concentration of lime for emulsifiers, and some weighting materials

(such as hematite) generate low ES readings. All except hematite require chemical treatment.

However:

• most muds made with mineral oil will have lower electrical stability than those made with

diesel.

• Low viscosity muds usually have low ES readings.

• Presence of gas: Another problem linked to the stability of the mud is the presence of bubbles,whatever they are air or acid gas. To face this problem, we can use scavengers (e.g. zinc oxide)

to degas the mud, or dilute the mud to proceed a spontaneous degassing.

(8) TEA = TriEthanolAmine


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Gas solubility is the other problem as it is many times greater in OBMs than in WBMs. Gas

solubility is indeed a function of the amount of the oil phase, and once saturation is reached, no

further gas will go into solution. Further influx of gas will behave like a gas kick in a water

mud.

If Garrett Gas Train(9) (see API Recommendations 13-B2) detects H2S, increase lime additions.

If carbon dioxide is present, lime is again the best solution.

D Alkalinity Control.

Every fluid pumped in the well must be alkaline. The additives used to control alkalinity are lime,

TEA, soda ash or potash, essentially.

The difficulty in invert emulsion is that we can not measure pH (it has no sense !) directly as the

continuous phase is oil. Below is a standard procedure to titrate the alkalinity of the mud:

•

In a 250 ml beaker, add 20 ml of a blend of toluene/IPA

(10)

(1/1). Disperse 1 ml of mud and add75 ml of de-ionized water.

• Add 10 droplets of phenolphthalein and homogenize.

• Titrate slowly with a N/10 sulfuric acid solution, until the red color of the chemical in water is

observed.

• The alkalinity can be expressed:

• in ml of H2SO4 ,

• in lb/bbl of lime: 1.3 x VH2SO4, N/10, V being in ml,

• in kg/m3 of lime: 3.7 x VH2SO4, N/10, V being in ml.

E Loss circulation & Fluid loss.

A low filtration rate and water-free filtrate are critical properties of oil muds to ensure the well is

stable (no fluid invasion through the formation, no shale swelling, …).

Fluid loss control agents are used in muds to get good filtration properties and these chemicals are

most of the time very effective.

However troubleshootings may occur depending on the pertinence of the formulation, on the mud

history, or on the operating conditions of the well (temperature, pressure). Here are some examples:

•

If the emulsion is too weak, the filtration rate increases dramatically and moreover some watercan be found in the filtrate. The solution is then to treat the mud with the primary emulsifier

and lime (systematically, when a mud is treated with the primary emulsifier, lime must be

added).

Organolignites will also emulsify water and lower filtrate, but are not effective when BHT is

lower than 150 F.

(9)An instrument used for quantitative analyses of sulfides and carbonates. Specific test methods have been published by

API. The oil-mud procedure analyzes active sulfides and uses whole mud samples, whereas the water-base mud

procedure tests filtrate. The GGT unit is a clear, plastic block (2.5 in. x 4 in. x 6 in.) that contains three interconnected

chambers. A carrier gas is used to flow an inert gas through the chambers. The sample is placed in chamber #1 and isacidified to release sulfides as H2S and carbonates as CO2. The appropriate Drdger tube is used to measure the effluent

gas that is evolved from the sample(10)

IPA = Iso Propylic Alcohol.


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• If the filtration properties were good and that, due to the high temperature downhole, the rateincreases, then the mud needs to be stabilized. Usual treatment is to add some emulsifier,

eventually combined with a wetting agent, plus lime and an organophilic fluid loss control

agent (polymer). The habits must be similar when ageing the mud at quite high temperatures.

It is not possible to predict the respective amounts of additives as every single situation requires

a specific study.

• One of the process involved in the loss circulation control is the presence of particles whichmake the filtration cake poorly porous. Sometimes particles are not well-sized and the filtration

rate is huge. One solution is then to combine the action of a fluid loss control additive with

bridging (or even weighting) materials one.

If loss is not complete, use oil-wettable fibrous material or solid bridging material (such as calcite).

Use same technique for seepage losses to minimize thick filter cake and differential sticking.

If losses are complete, consider organophilic clay squeeze, cement or displacement to water-based

muds until loss zone is cased off.

F Free Top-Oil.

After periods of inactivity, free oil may cover the surface of the pits. Agitate the mud in the pits or

add organophilic clay to increase viscosity if required.

The situation is the same in the lab.

VI. Comparative oil mud products by function and company.

Table 6 presents a non exhaustive list of OBM products by function in the three majors drilling

companies.

Function M-I BHI BAROID

Primary emulsifier VERSAMUL™ CARBOTEC L™ INVERMUL™

Secondary emulsifier VERSACOAT™ CARBOMUL™ EZ MUL™

Organolignite VERSALIG™ CARBOTROL A9™ DURATONE E™

Asphaltic FLA

GilsoniteVERSATROL™ CARBOTROL™ BARABLOK™

Organophilic bentonite VG-69™ CARBO VIS™ GELTONE II™

Organophilic hectorite - CARBOGEL™ BENTONE 38™

Wetting agent VERSAWET™ SURFCOTE™ DRILTREAT™

Rheological modifier VERSAMOD™ SIX-UP™ RM 63™

Polymeric viscosifier VERSA HRP™ CARBOVIS HT™ X-VIS™

oil mud thinner VERSA THIN™ SURFCOTE™ OMC™Table 6: most famous OBM commercial products – Cross Table.

Below are brief descriptions of some of the chemicals presented in table 6.


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• M-I Chemicals.

VERSAMUL™ multi-purpose emulsifier is a liquid blend of selected emulsifiers, wetting agents,

gelling agents and fluid stabilizers in a mineral oil base. VERSAMUL™ is used as the basic

emulsifier for the VERSADRIL™, VERSACLEAN™ and VERSAPORT™ oil mud systems.

VERSAMUL™ provides excellent emulsion stability, secondary wetting, viscosity, filtration

control and temperature stability. Packaging: 55-gal (208.2-l) drums.

VERSACOAT™ organic surfactant is a multi-functional additive which serves as an emulsifier

and wetting agent in the VERSA oil mud systems. Secondary benefits include improved thermal

stability and high-temperature, high-pressure (HTHP) filtration control. The product is effective

over a wide temperature range and in the presence of contaminants, and for reducing the adverse

effects of water contamination. Packaging: 55-gal (208.2-l) drums and 5-gal (18.9-l) cans.

VERSALIG™ amine-treated lignite is a filtration-control additive designed for use in all VERSAoil-base systems, as well as NOVA synthetic-base systems. It is an effective alternative to asphalt or

gilsonite where their use is undesirable. VERSALIG™ is effective and applicable in all oil- and

synthetic-base drilling fluids, and is compatible with other additives. Packaging: 50-lb (22.7-kg)

and 25-kg (55.1-lb) multi-wall, paper sacks.

VERSATROL™ gilsonite is a natural occurring asphalt used for high-temperature, high-pressure

(HTHP) filtration control in all VERSA oil-base systems. It is often used to seal low-pressure and

depleted formations. It is compatible with all VERSA systems and can be used in the initial

formulation or added later. Packaging: 50-lb (22.7-kg) and 25-kg (55-lb) multi-wall, paper sacks.

VG-69™ organophilic clay is a viscosifier and gelling agent used in VERSA oil-base and NOVAsynthetic-base systems. This amine-treated bentonite is used to increase carrying capacity and

suspension properties, providing support for weight materials and improved cuttings removal.

VG-69™ also aids in filter cake formation and filtration control. Packaging: 50-lb (22.7-kg) multi-

wall, paper sacks.

VERSAWET™ organic surfactant is a concentrated and powerful oil-wetting agent for oil-base

muds. It is used primarily in relaxed-fluid-loss, lower-lime VERSA oil mud systems which use

VERSACOAT™ as the emulsifier. VERSAWET™ is an excellent wetting agent which is

especially effective in systems using difficult-to-wet solids (e.g. hematite). It is also effective at oil-

wetting barite and drill solids, and at reducing the adverse effects of water contamination.

Packaging: 55-gal (208.2-l) drums and 5-gal (18.9-l) cans.

VERSAMOD™ organic gelling agent is a liquid rheology modifier used in VERSADRIL™ and

VERSACLEAN™ oil-base mud systems. It increases low-shear-rate viscosities (LSRV) and gel

strengths for improved hole cleaning. The primary application for VERSAMOD™ is in large-

diameter, high-angle, horizontal and extended-reach wells to increase cuttings-carrying capacity.

This permits higher rates of penetration while maintaining wellbore stability. Packaging: 55-gal

(208.2-l) drums and 5-gal (18.9-l) cans.


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VERSA-HRP™ polymeric viscosifier provides elevated yield-point and gel strengths with minimal

increase in plastic viscosity for all VERSA and NOVA systems. It is frequently used to increase the

hole-cleaning capacity, for sweeps in directional or horizontal wells and for gelling freshly prepared

muds being transported to the well. VERSA-HRP™ is a versatile additive which works in

conjunction with organophilic clay and can be used to minimize the amount of clay in a particular

formulation. Time and shear or chemical treatments can be used to later thin a fluid treated with

VERSA-HRP™. The product increases low-shear-rate viscosity (LSRV) to improve shear thinning

and thixotropic characteristics. Packaging: 5-gal (18.9-l) cans and 55-gal (208.2-l) drums.

VERSATHIN™ deflocculant is used as a thinner and conditioner for oil-base muds and has

application in all VERSA systems. It reduces viscosity and gel strengths through the action of

macro-molecules which deflocculate solids in the mud without the need for dilution or changing the

oil-to-water ratio. Packaging: 55-gal (208.2-l) drums and 5-gal (18.9-l) cans.

•

BAROID Chemicals.

INVERMUL™, a blend of oxidized tall oil and polyaminated fatty acid, is the primary emulsifier

for Baroïd OBMs. It stabilizes emulsion, aid suspending properties and reduces filtration.

INVERMUL™ needs to be combined with lime (0.5 lb/bbl of lime per lb of INVERMUL™) to

produce a calcium soap in situ. INVERMUL™ resists electrolyte contamination. Flash Point: 156

F. Packaging: 55-gal drums and in bulk.

EZ MUL™ is a polyaminated fatty acid used as secondary emulsifier in oil-based muds. It is used

to improve the fluid's oil-wetting characteristics and is designed for use in emulsions containing

high amounts of divalent salts. Combined with INVERMUL™, EZ MUL™ aids in producing astable invert emulsion system with low filtration rate. Thermally stable above 500 F. Packaging: 55-

gal drums.

DURATONE E™ organophilic lignite is used to control filtration rates in ester and olefin based

drilling fluids. DURATONE E™ is stable at high temperatures and can be used to control filtration

rates in deep, hot wells. It can also be used to improve emulsification of water and to promote fluid

stability. Another advantage of DURATONE E™ is that it meets the environmental requirements

for the North Sea. Packaging: 50-lb sacks.

BARABLOK™, a powdered hydrocarbon resin (asphaltite), is a natural bitumen with high

softening point that permits the product to extrude into formation fractures and bedding planes, and bond the matrix to prevent sloughing. BARABLOK™ does not contains chemical treatment and

can be used up to 350 F. Another version of the product, BARABLOCK 400™, permits

applications with temperature up to 400 F. Packaging: 50-lb sacks.

GELTONE™, an organophilic clay, imparts viscosity and suspension properties to OBMs.

GELTONE™ is a bentonite clay that has been treated with an amine compound to promote its

dispersion/yield in oils, particularly when temperature exceeds 120 F. Packaging: 50-lb sacks.


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DRILTREAT™, a lecithin liquid dispersion, can quickly change the natural water-wetting

characteristics of drilled solids and weighting agents in oil muds, making them preferentially oil-

wetting. DRILTREAT™ is used as a supplementary additive for improving flow properties and

emulsion stability. With its oil-wetting characteristics, DRILTREAT™ can be used both in the

preparation and maintenance of oil-based drilling and completion fluids. It also reduces the

interparticle forces when formulating very high density OBMs. Packaging: 5-gal pails and 55-gal

drums.

RM-63™, a blend of dimer and trimer fatty acids, improves rheological and suspension

characteristics of invert emulsion fluids. RM-63™ increases low-shear rheological properties for

enhanced suspension with minimal effect on high shear properties. Using the RM-63™ modifier

when drilling with weighted mud in deviated boreholes minimizes the tendency for sag. Stable at

temperatures approaching 450 F. Packaging: 400-lb drums.

X-VIS™, dimerized fatty acids, promotes the dispersion and yield or organoclays under low shear

conditions and optimizes suspension properties of oil-muds, especially those formulated withmineral oil. X-VIS™ can be used in high temperature (above 400 F) systems to improve rheological

properties, filtration control and emulsion stability. Packaging: 55-gal drums.

OMC™, oligomeric fatty acid, is effective in lowering rheological properties in OBMs. OMC™ is

recommended for fluids containing organoclays and large quantities of drilled solids. Specially

designed for PETROFREE™ system, but effective with any oil-based system. Packaging: 5-gal

pails and 40-gal drums.

VII. Examples of oil-mud formulations.

Below are examples of oil-mud formulations. These formulations are based on lab conditions I used

to experience in the past.

Product requirements are listed for each company over the temperature range noted.

The field requirement is generally lower because of the incorporation of drill solids, particle size of

the weighting agent, and longer periods of shear experienced while drilling.

The formulations listed below can be either formulated in diesel or mineral oil (it was Ultidrill

C380™ base oil) with very small modifications. Concentrations of products in tables 7, 8, 9 and 10

are expressed in lb/bbl.

• M-I

Product 200 F 300 F 400 F

VERSAMUL™ 5 7 10

VERSACOAT™ 2 3 4

ECOTROL™ 2 5 10

LIME 5 5 7Table 7: M-I oil mud.

VG-69™ is used at the concentration of 3-4 lb/bbl when O/W = 75/25 – 80/20.

VG-69™ is used at the concentration of 4-6 lb/bbl when O/W = 85/15 – 90/10.


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VIII. Description of the most famous commercial synthetic-based mud systems.

Below are general information concerning NOVADRIL™, PETROFREE™ and AQUAMUL II™.

• NOVADRIL™ (M-I Drilling Fluids):

Commercialised by M-I Drilling Fluids, this system is an emulsion which utilises a

specially manufactured polyalphaolefin (PAO) as the continuous phase and brine as the

internal phase.

The NOVADRIL™ drilling fluids criteria are:

• benefits obtainable from a low toxic mineral oil-mud, including lubricity,

temperature stability, alkalinity tolerance and rheological stability.

• success to the present day toxicity tests required to allow the discharge of the fluid oncuttings in environmentally sensitive countries of the world.

• substantial improvement over previously used mineral oils with regard to health and

safety considerations.

• biodegradability and no bioaccumulation.

• volumes available and prices allow it to be a cost efficient fluid.

NOVADRIL™ has proved successful in drilling highly reactive, pressured gumbo

shales and highly depleted permeable sands with differential pressures over 4000 psi.

• PETROFREE™ (BAROID):

PETROFREE™ ester-based system has been used on over 100 wells drilling over 900

000 feet of hole ranging in size from 22 to 4 ¾ inches in diameter. PETROFREE wells

have been drilled in most of the active offshore fields of the world, including the UK,

Norwegian and Dutch sectors of the North Sea, Malaysia, Australia and Western Gulf of

Mexico.

PETROFREE™ has proven to be a performing system due to overall savings on total

well cost (elimination of wiper trips and delays associated to reactive formations, faster

ROPs (11), etc. …) and reducing long term liabilities associated with cuttings discharge

by the drilling operations.

PETROFREE™ offers unsurpassed lubricity and excellent hole stabilisation.

Moreover, being a vegetable d erivative, PETROFREE™ is not classified as an oil,

passes the static sheen test(12), and is both aerobically and anaerobically readily

biodegradable.

(11) ROPs: rates of penetration.

(12) The static sheen test determines the prohibition of the discharge of the free oil. It indicates the presence of free oil

when drilling mud, drilled cuttings, deck drainage, well treatment fluids, completion and workover fluids, produced

water or sand or excess cement slurry, are discharged into offshore waters.

The visual sheen test consists of an observation made when surface and atmospheric conditions permit watching the

ocean water for a sheen around the point where the discharge entered the water.

When the conditions do not permit visual observations, a static sheen test is conducted. This test uses sea water in a

shallow pan (not more than 30 cm deep) with 1000 cm2 surface area. Either 15 cm

3 of fresh mud or 15 g fresh cuttings

are injected below the surface of the water. An observer watches for up to 1.0 hour for a silvery, metallic, colored or

iridescent sheen. If sheen covers 50% of the area, the mud or cuttings cannot be discharged.

However this standard test seems not to be suited for the environmental evaluation of SBMs. The presence ofcontaminants in SBMs is not effectively determined because the very low molecular weight of the continuous phase can

cause the formation of a film on the water. Such a film could result in failure of the sheen test and prelude on site

discharge of the associated cuttings.


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• AQUAMUL II ™ (ANCHOR Drilling Fluids):

The development of the AQUAMUL II™ system was approached from "the viewpoints

of drilling fluid stability and formulation flexibility as well as the environmental

impact".The continuous phase consists of a low toxic and highly biodegradable multi-ether

(acetal). Previous version AQUAMUL I™ was an ether-based continuous phase.

The AQUAMUL B2™ ether is a chemically pure, stable, liquid. It has been tested and

shown to be less irritating to personnel and less reactive towards elastomers and plastics

than mineral oil. The AQUAMUL™ system can be formulated and controlled at

extreme of ether/water ratio from 50/50 to 95/5.

Field drilling experience with the AQUAMUL II™ system is characterised by high

system stability, high ROPs, highly stable hole conditions and low maintenance

treatments. The stable properties of the fluid have been apparent at a wide range of

ether/water ratios and mud weights while drilling in areas with very different lithologies

(claystone intervals, complex evaporite sequences, …).

The AQUAMUL II™ drilling fluid can be reused on subsequent wells eliminating

dumping mud or eliminating the disposal costs associated with standard OBMs.


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Water in pores

Shale formation

Brine

phase

Annex 1: BALANCED ACTIVITY CONCEPT.

This concepts deals with shale stability. Picture 1 below is a schematic representation of contacts

between an oil-muds and a shale formation.

Picture 1: schematic representation of interactions between oil-muds and shale formations.

Shale formations have a natural potential to adsorb water that is developed during the consolidation

process of the formation.

This sets up a "suction potential" also called demand for water. The surfactants around the water

droplets act as a semi-permeable membrane (osmotic membrane) and water can transfer between

the emulsified water and the water in the pores of the shale.

The solution is to balance the demand for water, i.e. the activity between the shale and the

emulsified water, and then no exchange will take place(13).

The brine phase activity is thus primordial: addition of salt to water combines the water molecules

to reduce the vapor pressure (the activity !). It is to know that activity is approximately inversely proportional to chloride content. Divalent ions (calcium and magnesium) suppress activity further

than saturated sodium ions. Because most of the time calcium soaps are major part of the

emulsifying system, calcium chloride brines are preferred brine phase.

(13) Basic notions of shale swelling is given in annex 2.


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- - - - - - - - -- - - - - - - - -

+

+

+ +

+

+

+++

++

++

Annex 2: MECHANISMS OF SHALE SWELLING.

There are two swelling mechanisms well known today :

• Osmotic swelling,

• Hydration swelling.

• Osmotic swelling.

As shown in picture 1 below, a clay is dispersed in water.

Picture 1 : schematic representation of a clay particle dispersed in water.

Sufficient exchangeable cations are attracted by a net-negative charge in the clay particle in order to

constitute an electrically neutral system. This system is called the clay "micelle". The ions and

water within the micelles constitute the "double layer".

Osmotic swelling occurs because the ion concentration in the double layer water of the claymicelles is higher than the free pore water. Therefore, water is drawn towards the clay surface,

diffusing the ions and giving rise to the double layer repulsive potential, which causes the mineral

lattice to expand.

When the aqueous solution is separated from pure water by a semi-permeable membrane, the water

tends to pass through it into the solution, thereby diluting it.

• Hydration swelling.

Surface hydration, also called crystallization swelling, is an interfacial phenomenon common to

many materials but especially to clays due to their high specific area. Water is absorbed between the

lattice layers of the clay crystal and also on the surface of the particles. The hydration energy of the

interlayer cations and the charge density on the clay crystal surface determines the degree of water

absorption.

Monovalent cations, particularly in the case of sodium montmorillonite, permit more fluid to be

absorbed on the outer surfaces of the clays minerals far in excess of the amount adsorbed in the

inter-crystalline swelling. With divalent cations, osmosis takes place only between the particles.

The exchangeable cations that bond the two clay platelets together are located on the surface of

each platelet.


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If the crystal comes into contact with water, the water penetrates between adjacent silica layers and

spreads the platelets apart. The formation of a film of water on the outer surface and between the

layers of clay is a result of the negative distribution on the clay surface and hydration of the

exchangeable cations. This film of water that is oriented and actually bonded to the clay particle has

its greatest thickness between plates and is somewhat thinner on the outer plane surfaces.

These associated cations, depending on their charge and concentration, may be held very close to

the clay surface, causing an increase in the attractive forces between particles and allow only this

film of water to develop. However, if these cations dissociate from the particle (Ca2+ dissociates

less than Na+), the attractive forces are decreased and allow large volumes of water to penetrate into

the inner layers of the clay.

The hydration of the clay particles is also determined by the cation concentration of the surrounding

fluid. When the cation concentration is too high, the associated cations are forced closer to the clay

surfaces, increasing the attractive forces between particles, thus reducing swelling.

Some Basics on OBM

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