Introduction to Drilling Fluids – Part 1 5/31/2005

G Daccord

Schlumberger Private
Introduction to Drilling Fluids
Gérard Daccord
SRPC

Schlumberger Private
This is an introductory presentation on drilling fluids, to be presented in the frame of the
SRPC Physics métiers series of internal training sessions.

Prepared in January 2005 by G. Daccord.

Personal expertise in drilling fluids: about 6 years of R&D work in DF engineering,

monitoring methods, review of physical models for the various processes, development of
new models and approach for solids control management.

1
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Schlumberger Private

Schlumberger Private
2 GD
5/31/2005

You recognize here a view of a land-drilling rig. In this presentation, we will focus on the
parts that lie behind the rig itself, colored in brown.

The photograph shows the mud tanks on the right side, with the flow line – big inclined
pipe going from underneath the drill floor towards the mud tanks - clearly visible.
The second photograph shows two helpers climbing a ladder, on an artic drilling rig.

Origin of the word “mud”: the legend is that, for drilling a 1000 ft well through loose sand in
1901, the driller ran cows through a pond to create a muddy water supply that was pumped
down the hole to keep the hole stable. The well produced 50,000 b/d oil.

DF: short for “drilling fluid”, not “derrick floor” that is commonly used as depth origin on logs

2
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Targeted Audience & Objectives

n New technical personnel with no or little knowledge of domain

n More experienced personnel with fragmented knowledge

Schlumberger Private
Objective
n Provide an overall introduction about drilling fluids*, biased towards what
matters for SLB daily activity …

*Sufficient to understand a DMR

Schlumberger Private
3 GD
5/31/2005

This presentation is an introduction, with very little details on specific areas. Its intended
audience is thus young engineers or more senior personnel who wish to have a general
view.

3
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Introduction

Agenda Part 1 – Function, properties

Part 2 – DF management on surface
Part 3 – DF chemistry
Part 4 – A few downhole problems
Introduction: When / where DF’s are found, vocabulary, typical numbers
1. Functions, properties, composition of DF’s
HSE, monitoring, classification of DF’s, mud types, etc.

Schlumberger Private
2. DF at the rig site, surface view
Drilling fluid maintenance, process & techniques, Drilling Fluid Company
mud circuit, solids circuit
3. DF Chemistry
Clays, polymers, WBM’s and OBM’s, filtrate
4. DF at the rig site, a few downhole problems DF company - SLB
DF in movement: circulation, solids transport, displacement,
T&P effects, filtration, formation damage, etc.
Interactions of DF’s with SLB operations Schlumberger

Schlumberger Private
D&M, GP’s, tools and measurements
4 GD
5/31/2005

The presentation is structured as follows:

. A brief introduction to introduce some basic vocabulary, describe the mud circuit and give
rough numbers

. The largest part will detail the functions expected from drilling fluids, then their properties
and a brief outline of their composition.

. In Part 2, we will describe the management of the drilling fluid on surface: a large part is
dedicated to solids control and environmental constrains

. Part 3 contains a description of DF’s chemistry, mainly focused on clays – bentonite and
shales - and polymers.

. Part 4 is an overview of the main processes taking place downhole: hydraulics, solids
transport, etc. This part ends up with the interaction of drilling fluids with Schlumberger
Operations and services.

Each sub-part of this presentation could be expanded to a full 1-to-2 hours presentation: it
is not the objective of this presentation to go in these details. A few references are
provided at the end that provide more details in these specific fields.

4
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Basic Vocabulary
Inlet Mud Circuit

Schlumberger Private
Most of times, the Drilling
Fluid is recycled, after
treatment on surface to
maintain or adjust its
properties

Schlumberger Private
5 GD
5/31/2005

This picture shows half of the mud circuit:

The mud is pumped from the mud tank on surface through the standpipe and down the drill
string.

5
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Return Mud Circuit

Schlumberger Private
“active system”

Schlumberger Private
Cycle time ~ 2-3 hours
6 GD
5/31/2005

The second half of the mud circuit starts at the drill bit, then upward through the annulus.
The mud exits the hole through the flow line and is treated through the various pieces of
solids control equipment, positioned on top of mud tanks.

The other picture shows a simplified view of the mud circuit, without the rig itself.

The active system is defined as the circuit in which the DF is being recirculated; the typical
cycle time is 2-3 hours = (tank volume + well volume) / flow rate

6
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Typical Numbers

n Volumes handled
– Surface: active = 500 bbl, reserve = 1000 bbl

Schlumberger Private
– Hole volume: 8 ½ in, 10000 ft -> 3000 bbl (500 m3)
n Drilling Fluid Cost
– Fluid alone: from 5 to a few 100’s $/bbl
– Fluid management equipments
– Fluid maintenance + disposal costs
n “Mud Bill”: can reach 10-20% of well cost

Schlumberger Private
7 GD
5/31/2005

A few basic and typical numbers about drilling fluids:

The active volume that must be handled on surface is about 150 m3 / 500 bbls. This
represents the surface part of the DF that is recirculated.

The volume underneath the ground surface is much larger and depends whether the well
is just starting or close to completion. E.g. for an intermediate 8 ½ in section, the hole
volume is typically 500 m3 / 3000 bbl

The drilling fluid represents by itself a significant capital: the mud cost ranges from a few
US dollars/bbl (for spud muds) up to a few 100’s dollars/bbl. Multiplied by the volume of
the active system (surface + downhole), you may have a few 100’s k$ drilling fluid.

The mud bill represents the total of the costs related to the drilling fluid, including
• The fluid itself,
• The additives required for drilling the well
• The specialized equipment required to manage the fluid (mainly solids control
equipment).
• The cost of uploading and downloading the fluids to/from the rig
• The disposal cost for the wastes.
• The personnel needed to run this system

This mud bill ranges from 10 to 20% of the well cost.

7
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Example of Well
Cost Summary

Schlumberger Private
DF = 13 % of well cost
(logging = 7%, cementing = 3.5 %)

Schlumberger Private
8 GD
5/31/2005

For this land well, the DF is the second largest expense after rig rental costs.

8
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Drilling Fluids within Schlumberger

R&D activities in

Schlumberger Private
Montrouge STE SRPC & St Austell Cambridge

Sedco Forex “Dowell” SCR

1992 1993 1999

Smith-SLB JV

IDF Smith Market Share ~40-50%

Market share ~10 % International

Schlumberger Private
Smith Schlumberger
2003 2004 2003 2004
9 GD Revenue (billlion $) 3.6 4.4 10.1 11.5
5/31/2005 Net Income (million $) 124 182 382 1223

This slide shows an historical view of the implication of Schlumberger in drilling fluids

Up to about 1990, Sedco Forex had a DF engineering activity, focused on solids control. This
was an engineering activity, supporting their drilling rigs.
In the early 90’s Schlumberger invested in drilling fluids by acquiring a mud company,
International Drilling Fluids (IDF, based in Saint Austell, Cornwall, UK) and moving the mud
engineering of SF towards Dowell (located in Saint Etienne, France): the objective was to
take advantage of the synergy between cementing and drilling fluids.
The activity of the St Etienne center was transferred to Clamart in 1993. St Austell was in
charge of the chemistry of mud systems and SRPC of the modeling and software part.
In 1999, Schlumberger formed a Joint venture with Smith International by acquiring 40% of
M-I drilling fluids (previously owned by Halliburton, which just acquired Baroid): all
engineering work of DF’s was transferred to Houston.
At the time, the JV also included a solids control branch, called SWACO. This branch has
since been closely incorporated into M-I: they are called MI SWACO.

Smith Schlumberger
2003 2004 2003 2004
Revenue (billlion $) 3.6 4.4 10.1 11.5
Net Income (million $) 124 182 382 1223

M-I SWACO represents 50% of the revenue (I.e. 890 M$ for SLB part, for 2004).

9
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Introduction
Part 1 – Function, properties
Part 2 – DF management on surface
Part 3 – DF chemistry

Part 1 Part 4 – A few downhole problems

Schlumberger Private
Functions, Properties, Composition
of Drilling Fluids

Mud types

Schlumberger Private
This module will look at the basic functions of a drilling fluid.

10
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

“Mud” Functions, Properties and Composition

What is a Drilling Fluid or mud?

n It is a mixture of liquids and chemicals that allows the drilling and
completion of a well, safely and at minimum cost

Schlumberger Private
The Drilling Fluid has to provide many functions in order to reach these
objectives

These functions are enabled by the fluid properties

Properties are adjusted and maintained through the fluid composition

Schlumberger Private
11 GD

Origin of the term “mud”: the top sections of the hole are initially drilled with water. As the soil
mixes with water, this fluid looks like a mud. By extension, drilling fluids are called muds, DF
engineers are “mud engineers”, DF companies are “mud companies”, etc.

This is somehow a pejorative term and we will use Drilling Fluid instead. Also, for a fluid that
costs a few 100’s US$/bbl, this is quite a costly mud!!

Drilling fluids are complex mixtures that are expected to provide a variety of functions, subject
to constrains. The two major constrains are nowadays HSE – S&E first of all - and cost.

Important key words:

These functions are set in order to reach drilling objectives, and they are achieved by
assigning desired properties to the DF. The DF company select the DF chemistry and
composition in order to best match these desired properties, subject to the two above
constrains.

The properties are usually defined by the client in terms of API properties + a few others that
are not normalized.

Functions – properties: the link is through physics and “hard” science

Properties – composition: this is the art of the chemist

11
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Primary Functions Negative Functions

Drilling Objectives (constrains)

1. Lift and Carry Drilled Cuttings from the bit to 1. Not injure people or be damaging to the
Surface environment
Permit separation of solids at surface 2. Non damaging to the fluid bearing formation

Schlumberger Private
2. Control Formation Pressures 3. Not corrode or cause excessive wear
Maintain a Stable “In Gauge” Hole (abrasion) of drilling equipment
3. Cool and Lubricate the Bit 4. Not require unusual or expensive methods of
completion
Lubricate the Drill String
5. Not too sensitive to contamination, withstand
4. Secure Hole Information
well temperature
Power / Transmit signals from Downhole Tools
6. Ridiculously expensive
Prevent fluid from entering the formation
5. Hydraulic efficiency

Schlumberger Private
12 GD

This is self-explanatory.
A few of these functions are not direct drilling objectives but “enablers”, e.g. “permit solids
separation on surface”

An in- gauge hole is especially important for most subsequent operations:

•Better hole cleaning,
•Easier casing running
•Better cement quality and zone isolation

12
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Well cleaning
Hole control

Schlumberger Private
Lubrication
Hole Information

Schlumberger Private
Oilfield Review, April 1994

13 GD
5/31/2005

This is another way of showing the same requirements as on previous slide, the time when
these requirements appear and the close link between mud properties and the well
parameters:
•Required function vs. potential problem

In this respect, this slide introduces next slides where each function is further analyzed in
terms of potential problems

13
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Well cleaning
Carry Cuttings out of Hole (Hole Cleaning) Hole control
without re-introducing them later Lubrication
Hole Information

Potential problem Severity Probability Actions Main Fluid

Properties
• Cuttings remain in hole High High • Keep annular Rheology: yield
velocity above

Schlumberger Private
ØHole is “packed” minimum value stress high
ØReduced ROP • Lower ROP enough
ØIncreased drag • Pipe rotation
• Special DP
• Viscous sweeps
• Cuttings remain in the fluid High High • Separate solids on Rheology as low
ØFluid density & rheology increases surface, as soon as as possible
ØHigh “EMW” and “ECD” possible
ØFormation breakdown, losses • Dump / Dilute mud

Schlumberger Private
ØAll other fluid properties are
affected
14 GD
5/31/2005

This slide and next ones aims at analyzing the underlying reasons for each key function.
This is presented in the HARC form (Hazard Analysis and Risk Control) or FMECA
(Failure Modes Effects and Criticality Analysis). In short, each risk the function aims at
preventing is quantified in terms of both severity (in case the problem actually happens)
and probability (of occurrence). The risk is the combination of both criteria. This is a
recognized way of prioritizing actions.

Proactive actions must be taken according to the risk, in order to reduce all major risks
areas.

On this slide and next ones, the severity and probability ranking are heavily dependent on
well parameters: such an analysis could be done per section. This is outlined in the slides
at the end of Part 1.

Detail on this slide:

. Viscous sweeps are a common way of helping cleaning deviated sections.
This consists in pumping a slug of viscous mud that helps maintaining cuttings in
suspension while rotating the drill section at maximum possible ROP to put cuttings in
suspension. The slug is relatively short in order not to induce too much friction pressure
drop and rise the ECD.
. The key proactive action is keeping the mud clean, I.e. separate cuttings
as soon as possible on surface.
Other means are not relevant to the DF engineer: use of special BHA (Weatherford
hydroclean DP) or drilling technique (rotary steerable).

14
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Well cleaning

Control Formation Pressure and Hole control

Lubrication
“In-Gauge” Wellbore Hole Information

Potential problem Severity Probability Actions Main Fluid Properties

• Influx from formation: High Medium to Maintain adequate fluid Density

“gas kick”, Well Control low density

Schlumberger Private
HSE if H2S
• Connection gas Low Low to M. Low gel values Rheology
• Unstable wellbore: Medium Medium to Maintain adequate fluid Density
Wash outs, well collapse low density
“Cavings” in the wellbore
Hole cleaning
• Swelling formations: High Low • Select mud type Inhibition
“Tight spots”, large drag • Increase inhibition

• Losses to the formation: High to Medium • Maintain adequate Density

Cost low fluid density Rheology

Schlumberger Private
Potential for kicks • Keep low rheology • yield stress
15 GD • LCM’s • viscosity
5/31/2005
• gel strength

This function is more about “hole quality” and well safety

Connection gas in itself is not a big risk, this is used as an indicator of more serious
potential problems to come.

Losses are classified in broad categories, from seepage losses to total losses. Seepage
losses may just be due to high filtration rate

Potential for kicks if the fluid level in the well is too low (due to losses), decreasing the
hydrostatic pressure in front of gas zones.

15
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Well cleaning

Lubrication Hole control

Lubrication
Hole Information

Potential problem Severity Probability Actions Main Fluid

Properties

Schlumberger Private
• At the bit Medium Low • Decrease solids • Nature of
Premature bit wear content continuous
Low ROP • Clean hole from phase
• Along drill string High Low solids and weak mud • Lubricant
Low WOB cake • Filter cake
Unable to reach TD • Add lubricant
• Change mud type
• Along casing High Low
• [Switch to rotary
Unable to reach TD
steerable drilling]

Schlumberger Private
16 GD
5/31/2005

There are two aspects for “lubrication”:

. Cooling and lubrification of the bit, to prevent premature failure: cutters for PDC bits,
bearings for roller cones.
. Lubrication of the drill string or casing, to decrease total drag and enable enough weight
on bit or running casing to total depth (TD)

There are various ways of acting on the lubricating properties of a DF: switch from WBM to
OBM, add a liquid lubricant, add a solids lubricant (e.g. glass beads)

The way the well is drilled has a strong influence on the drag: hole spiraling due to
directional drilling induces large friction while rotary steerable drilling produces much
smoother holes, hence lower friction.

16
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Well cleaning

Hole Information Hole control

Lubrication
Hole Information

Potential problem Severity Probability Actions Main Fluid (API)

Properties
• Cuttings properties altered Low Low • Remove cuttings as • Inhibition,

Schlumberger Private
• Gas shows -> HSE quickly as possible Encapsulation
• Decrease viscosity • Rheology
• Bad communication with BHA Medium Low “Anti foam” Compressibility
Data lost

• Modify near wellbore reservoir Low High • Efficient filtration • Fluid loss
information control volume
Saturation and resistivity

Schlumberger Private
17 GD
5/31/2005

This is an important function for SLB, as it directly influences the quality of the data we
measure and transmit to the client.

The geologist looks for intact cuttings

Hole information also resides in the formation fluids that are mixed with the mud: oil cannot
be detected, formation brines may alter the mud properties, gas is systematically detected
at the gas separator (degaser).

Communication problems may appear with foams or foamy muds like aphrons: the
pressure pulses are strongly attenuated.

The problem of formation invasion is detailed in Part 3.

17
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Negative Functions
Potential problem Severity Probability Actions

• HSE, toxicity for personnel High Medium • HSE compliant additives

and environment • “PLONOR” list

Schlumberger Private
• Corrosion of drill pipes or BHA High Low • “Corrosion rings”
• Additives, O 2 content
• Difficult to displace Medium Low • Do not “over-treat”
Compatibility with other fluids • Special mud systems
Cost
• Fluid cost Proactive fluid management

Schlumberger Private
18 GD
5/31/2005

This is a list of additional concerns for the mud engineer, not apparent to the other persons
on the rig except when the potential problem materializes

HSE is a constrain that must be considered well before drilling, in the design phase.
For the North Sea, there is a list of chemicals that “Pause Little Or No Risk” = PLONOR
list. Ideally, all chemicals used should appear there. No risk means both non-toxic and
biodegradable.
Corrosion is monitored on a daily basis by weighting “corrosion rings”
Atmospheric oxygen increases corrosion as in any fluid pumped downhole: oxygen
scavenger can be used.
One potential problem is the negative interaction of the DF with BHA, such as chemical
compatibility with rubbers (mud motors and silicate muds).
Over treating an OBM is classically done, to ensure fluid stability in case of contamination.
However, the excess amount of surfactant can create a lot of direct or indirect damage:
change wettability of reservoir, make water-wet hole surfaces difficult to clean hence bad
cement quality.

18
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Other Functions
Hydraulic power is the most efficient way to carry
energy downhole

• Maximize hydraulic drilling efficiency

Schlumberger Private
= Pressure drop through the nozzles / pump
pressure

Pump pressure =
friction in the pipe (turbulent flow)
+ ∆P in the mud motor-BHA
+ ∆P at nozzles
+ friction in the annulus (laminar flow)

Schlumberger Private
• Power MWD / LWD tools with minimum erosion
19 GD

Traditionally, a key effectiveness criterion for a DF is its hydraulic efficiency: for best
ROP, most of the pressure drop should take place in the nozzles. Friction pressure drop
in the pipe and annulus are nuisances.

The drilling fluid should not contain and material which is likely to damage/plug down hole
equipment. This usually involves keeping the sand content below 0.5 % and keeping the
size and concentration of lost circulation material below the suppliers limits.
The photograph at bottom shows a part from the ADN8 D&M tool, badly eroded.

Pressure pulse attenuation may be of interest in deep holes, this may make OBM less
suitable for transferring information upwards.

19
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Summary of DF Properties and Composition

Density 2 Liquid phases
Rheology: n Aqueous
yield stress n Non-aqueous
viscosity
API RP 13 2+ Solid phases

Schlumberger Private
gel strength(s)
Fluid loss: n Weighting agents
filtrate volume n Cuttings
filter cake thickness & nature n Other: bentonite, salt, LCM, glass beads, etc.
Inhibition: Dissolved compounds
cuttings integrity
water activity n Salts
Fluid stability vs. temperature, shear, n Polymers
contamination, etc.; no settling n Dispersants, surfactants, polyols, etc.
Lubricity

Schlumberger Private
Corrosiveness
20 GD
5/31/2005

On the left side: a recap of the properties previously mentioned

On the right side, the various components of a DF grouped according to the phase they
reside in.
All DF have at least 2 liquid phases, aqueous and oil.
• If the aqueous phase is external, this is a WBM. The oil phase content might be very low
but it exists: at least pipe dope. Enough to make surfaces dirty and more difficult to clean.
• If the oil phase is external, this an OBM or SBM
This description into phases is the actual distribution; for practical reasons, it is often
necessary to alter this distribution into a theoretical distribution, creating “pseudo-phases”:
see below slide 27.

20
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Functions
Properties
Density Composition
CALIBRATE
KEEP HOLE FREE BY ADDING/
By convention the density is called the mud TO EXPEL MUD
REMOVING
weight LEAD SHOT

n MW (or SG): Measured at surface SIGHT GLASS

Schlumberger Private
n EMW: P&T effects vs. depth
n ECD: includes annulus friction pressure SCALE BAR
drop

Measured using a “mud balance”

SLIDING WEIGHT
Adjusted by adding weighting agents: barite,
calcium carbonate
or light materials: “glass bubbles”, air bubbes

Schlumberger Private
21 GD

D Vanbeck
The mud density is commonly measured using a mud balance. This can have 4 different
scales on it to accommodate various operator’s requirements. What are they?
Pounds per gallon, pounds per square inch per 1000 feet, specific gravity and pounds per
cubic foot.
Mud balances can only work if they are calibrated correctly. This is done using Distilled water.
Although the balance can be re-calibrated with lead shot this is not recommended as accuracy
may not be possible. It is far better to have a new balance available. The cost is insignificant
when the operation may depend on it (blow out etc).
Note that the lid and balance are calibrated together. Don’t use a different lid????
Pressure balances work the same way except they can remove entrapped air. All the
components are numbered as a set. So again don’t mix and match.
------------------------------------------------------------------------------------------------------------------
An accuracy of 0.05 ppg can be reached with a well calibrated and maintained pressurized
mud balanced. More often the accuracy is closer to 0.2 ppg, which is the minimum required for
safe drilling.
Often, mud engineer only have atmospheric mud balance: mud density is thus systematically
underestimated.
• MW (Mud weight) is measured at surface, from the active pit
• EMW (Equivalent Mud Weight) is the density of the DF averaged all along the well
trajectory, accounting for temperature and pressure effects (thermal expansion and
compressibility)
• ECD (Equivalent Circulating Density) is the EMW + friction pressure drops

21
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Rheology
DF’s are viscoplastic, thixotropic fluids Funnel viscosity
3 parameters minimum required:
– Viscosity
– Yield stress

Schlumberger Private
– Gel strength (measured after different rest periods)
12
Measured with
Gel strength
10 increasing shear rate
Shear Stress (Pa)

6 Measured with
decreasing shear rate
4 Yield stress Bingham yield stress
2 (or shear strength)

Schlumberger Private
0 200 400 600 800 100 120
Shear rate (s -1 )
22 GD
5/31/2005

DF rheology includes a minimum of 4 API properties.

It is important to understand the difference between the various “yield strengths”, that originate
from the non-ideal behavior of muds:
. Bingham yield stress: extrapolation at zero shear rate, based on a limited
number of readings (often at 600 and 300 or 100 and 300 RPM)
. True yield stress: shear stress extrapolated from continuous measurements
down to very low shear rates.
. Gel strength: shear stress required to initiate flow after a rest period of given
duration. Because DF are thixotropic, the gel strength increases with the duration of the rest
period. The API requires the GS to be measured after 10 s and 10 mn rest. These are called
the “gel values”.

Nevertheless, even after 10 mn, the gel strength continues to increase. It is more common to
reach a pseudo steady-state gel strength value after 1 hour than after 10 min; for practical
reasons, the rest period is limited to 10 mn in API specs.

For most muds, the Bingham model provides a good enough fit, I.e. the data are well fitted
even at low shear rate. For polymer muds, a 3-parameters model is necessary since the data
show a more pronounced curvature at low shear rates.

22
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Rheology

Factors affecting rheology

n DF composition
– Bentonite / clay content and aggregation yield stress

Schlumberger Private
– Solids content, especially small size cuttings viscosity
– Polymers non-Newtonian behavior
n Pressure & Temperature
n Solids dispersion & polymer hydration, shear history, additives
n Ageing, thermal degradation, contamination by influxes or cement, etc.

Thus maintaining drilling fluid properties constant over time is a full job, done by trial and error

Schlumberger Private
23 GD
5/31/2005

Rheology is probably the DF property that is the most sensitive to its composition.
Maintaining DF rheology at specified values is an art, key skill for the DF engineer.

The primary way to decrease a high rheology is to clean the mud

Increasing its viscosity is done by adding polymers
Increasing the yield strength is done by adding bentonite.

Often, it takes a full round trip for the mud additives to show their full effect on the
rheology: dispersion and hydration of these additives takes time. Thus, it is a common
practice to disperse and hydrate these additives in a separate tank and then add this pre-
mix to the active system.

23
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Schlumberger Private

Schlumberger Private
24 GD
5/31/2005

Example of rheological data for an HEC (hydroxyethyl cellulose, I.e. polymer used in
completion operations) solution.
The operator uses the PV/TY data which provide an acceptable fit at high shear rates.
However, the solids carrying properties of this fluid are very poor, looking at the LSR
values (low shear rate). In fact, this fluid is used to carry solid particle and have them
settled in the hole to form a protective plug.
There is no doubt that either a power law or Herschel Bulkley model will provide a much
better fit.

24
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

(Static) Filtration

Characterized by two parameters:

n Filtrate volume (after 30 mn) depth of invasion, shale stability
n Filter cake thickness & hardness differential sticking

Schlumberger Private
Mainly dependent on Wellbore Formation
n WBM: bentonite flocculation, starch
n OBM: O/B ratio

Typical values API values:

n WBM: 5 – 10 mL Drilling
fluid Formation
n OBM: 2 – 5 mL fluids

Schlumberger Private
Static mud Mud solids Mud
Dynamic filtrate
cake
25 GD mud cake
5/31/2005

Filtration is due to the flow of the DF past low pressure permeable formations. If the
formation permeability is high enough, a filter cake is formed on the wellbore.

The API specs use 2 parameters to describe this filtration process, fluid loss volume and
cake thickness.
At least two more parameters are required to describe the effectiveness of the DF vs.
drilling operations, static vs. dynamic cake and filtrate invasion.

DF filter cakes are usually strongly compressible, namely their permeability decreases
when the pressure differential increases (non-reversible). This compressibility depends on
the relative amount of bentonite vs. other solids.

FOR OBM’s, the cake properties is primarily dependent on the brine droplets.

DF filter cakes are extremely effective in limiting formation invasion, with fluid loss volume
as low as a few mL in 30 mn, I.e. an invasion velocity of ~1 mm/hour (porosity ~15%)! If
steady state filtration can be maintained.

25
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Inhibition - Accretion, Bit Balling, Gumbos, Wet Discharge

Objective: Prevent water from entering between clay platelets and swell the minerals
Method: monitor cuttings integrity
For WBM’s:
– KCl + polyols + encapsulating polymers
– Silicate muds

Schlumberger Private
For OBM’s: water activity adjusted to formation
water activity
– CaCl2 content in the aqueous phase

Schlumberger Private
26 GD
5/31/2005

Inhibition covers a wide variety of related phenomena. The visible consequence of

insufficient or incorrect inhibition include:
. Swelling of wellbore: need to backream
. Creation of washouts, if the swelling is too large
. Cuttings are stuck on various parts of the drill string, increasing drag and pull force,
decreasing ROP
. Cuttings agglomerate together, creating “gumbo attacks”
• Inhibition is a property of the DF with respect to a given type of rock
• Accretion is the phenomenon of cuttings sticking together
• Bit balling appears when cuttings stick on the drill bit or other parts of the BHA:
the ROP is greatly decreased (top-right photograph)
• Gumbos are large pieces of rock, with dimension typically large with respect to
hole size (bottom-left photograph)
These are major drilling problems.
In additions, cuttings may be altered making the job of the geologist more difficult.

On surface, bad inhibition also means ineffective shale shaker operation with wet cuttings,
I.e. high maintenance cost (bottom-center photographs: before and after using the correct
drillingfluid).

Inhibition is the main selection criterion for the mud system, from bentonite mud, KCl-
PHPA (partially hydrolyzed polyacrylamide), glycol muds to OBM/SBM’s

26
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Mechanisms of Shale Inhibition

Poor inhibition
– Water enters the rock,
– The rock swells, becoming more permeable and weaker,

Schlumberger Private
– More water can enter until the rock fails

Methods to prevent water from entering the rock

– Osmotic barrier
– “Impermeable” barrier
– Strengthen rock
– No water in the drilling Fluid

Schlumberger Private
27 GD
5/31/2005

Shales – or water sensitive formations – are rocks whose properties significantly change with water content.
These changes are most of times detrimental, including:
• Shales: weakening of the rock mechanical strength, which can ultimately lead to hole collapse.
• Sandstones: decrease of permeability, ultimately the rock becomes impermeable to oil flow.
Since shales represent about 2/3 of the formations drilled, shale swelling and destabilization is a serious
drilling problem when drilling intermediate sections.
Many methods are available to limit or prevent shale destabilization, from the simplest to the most efficient:
• Increase the salt content of the aqueous phase: NaCl
• Use stabilizing cations, like potassium or calcium: KCl muds
• Limit the infiltration of aqueous phase, by creating an impermeable cake (acting on filtration
properties) and removing filtration of aqueous phase (oil-based muds)
• Strengthen the formation, to help it resist swelling: silicate muds
Usually, more than one mechanism act together:
• The aqueous water activity is decreased, by adding salts: -> thermodynamic effect
• Bridging cations are used: K+, Ca ++ -> colloidal forces
• Organic bridging molecules are used: polyols.
• Polymers coat the shale surface (PHPA, encapsulating polymers).
• Silicates react with chemical groups on rock surface, creating covalent bonds(? Actual
mechanisms not well understood.)
References:
• L Bailey, B Craster, C Sawdon, M Brady, S Cliffe, New Insight into the Mechanisms of Shale Inhibition
Using Water Based Silicate Drilling Fluids, SPE 39401.
• Reid, P. I., Dolan, B., and Cliffe, S.: “Mechanism of Shale Inhibition by Polyols in Water Based Drilling
Fluids,” SPE 28960, presented at the International Symposium on Oilfield Chemistry, San Antonio (February,
1995).
• Curtis Boney, Clay stabilization, 8 Jul. 2002, http://eurekabb.slb.com/stimknow-bb/msg00005.html

27
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Condenser

Oil-Water Ratio, Solids Content Connection

(filled with
steel wool)

Mud Sample

The mud composition is determined

by distillation,
+ ions titration (Cl-, Ca++)
Heating Jacket

Schlumberger Private
Oil
Graduated

+ mass balance cylinder Water

+ a few assumptions
Retort
• Liquid phases: O/W or O/B ratio
• HGS: “High Gravity Solids” = barite Pseudo
• LGS: “Low Gravity Solids” phases

Schlumberger Private
28 GD
5/31/2005

The oil-brine ratio is the primary design criterion for OBM/SBM. This is determined using
the retort and knowing the salt content, monitored using titration methods.

API titration methods allow to determine the actual mud composition in terms of two solid
pseudo phases:
• High Gravity Solids
• Low gravity solids, include all solids other than barite. I.e. cuttings + bentonite + excess
salt + polymers + surfactants, etc.

For practical purposes, the DF engineer must maintain the DF LGS contents below a
threshold value: this a key indicator of mud cleanliness.

Oil-based muds and synthetic-based muds have a particular feature vs. water-based
muds, namely the wide “particle-size” range that strongly impacts sound and ultrasound
propagation. In addition to solids, they contain brine droplets. This large heterogeneity
induces a large acoustic attenuation, which directly impact Schlumberger acoustic tools
like the USI.

28
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Functions

Phases in Drilling Fluids Properties

Composition
Drilling fluids are complex mixtures of soluble and solid components
Components Actual distribution API Retort MudCADE 2.0
interpretation
Pure water
Brine phase

Schlumberger Private
Soluble salts
Water soluble organics: Aqueous phase Aqueous phase
Belong to LGS phase
dispersants, polymers, surfactants

Polyols Polyol phase

Base oil, pipe dope, etc. Oil phase
Oil phase Oil phase
Oil soluble polymers and surfactants Belong to LGS phase
Excess salt Ignored
Cuttings Three solid phases:
Four solid phases • Solid salt phase
Un-removable solids Three solid phases
(bentonite, dispersed clays) • LGS phase
• HGS phase
HGS (barite + its impurities)

Schlumberger Private
2+ liquid phases 3 liquid phases 2 liquid phases
29 GD 4 solid phases 3 solid phases 3 solid phases
5/31/2005

Summary table of the components of a DF and the phases – and pseudo phases - in
which they are distributed.

Note: polyols may be only partially soluble in the aqueous phase; in this situation, there is
a third liquid phase.

The column on the right side corresponds what was considered in the MudCADE software,
developed in SRPC in the late 90’s.

29
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Well Profile and Selection of Mud Type

AAwell
wellisiscomposed
composedofofa atelescopic
telescopicseries
seriesofof“sections”
“sections”
AAwell
wellisiscomposed
composedofofaatelescopic
telescopicseries
seriesofof“sections”
“sections”
– –Conductor
Conductorcasing
casing
– Surface casing
– Conductor casing
– – Intermediate
Conductor casing

Schlumberger Private
casing(s) or liner(s)
– Surface casing
– Surface casing
– Intermediate casing(s) or liner(s)
– Production casing, or liner

Each section has different objectives and

drilling problems
Global objective: optimize drilling process and cost

Schlumberger Private
Different DF systems are used in different sections
30 GD
5/31/2005

This slide summarizes the basics of an oil well. This slide and subsequent ones have been
extracted from an introductory presentation on cementing.

An oil well is composed of a series of tubulars, of decreasing size, arranged telescopically.

Traditionally, each casing size is designated with a specific name (conductor, surface,
intermediate, etc.) and has typical dimensions and drilling problems, hence different mud
system are used.
This traditional view has been partly obsoleted by the introduction of solid expandable
casings (SEC) which aim at reducing this telescopic effect.

30
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Conductor Pipe

Standard conditions …
n Prevent top unconsolidated soil layers from falling into the hole
30’’ casing in n Cemented to surface
36’’ hole

Schlumberger Private
n The casing carries no load
and
“Spud mud”, low cost, water-based
20’’ casing in
26’’ hole
30 m - 300 m … to challenging problems
Offshore:
n Possible occurrence of shallow water flows
n Low temperatures
n Drilling through gas hydrates under deep water conditions
Onshore:

Schlumberger Private
n Shallow gas flows
31 GD
5/31/2005

The first section of a well is the top-hole, in which a conductor casing is set. There is
usually no specific problem here except in some situations in which shallow flows are
expected.

The top hole is quickly drilled with water + some bentonite as drilling fluid. As drilling
continues, more additives are added to the active system to improve the DF properties for
subsequent sections: mainly polymers.

For offshore wells, the DF is returned to sea floor, so it is not recycled.

31
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Surface Casing

n Used to provide a competent mechanical base

for subsequent operations (BOP, Well Head, etc.)

Schlumberger Private
n Must withstand eventual kicks: stronger than formation at shoe
n Isolates surface fresh water aquifers
n Has to be cemented up to surface,
Bentonite water-based mud
16’’ casing
in 20’’ hole
Challenges Offshore:
n possible occurrence of swallow water flows
1000 m
n low temperatures
n protect gas hydrates bearing zones

Schlumberger Private
32 GD
5/31/2005

The surface casing has a significant role since it will bear the blow-out preventer (BOP).
Thus, in the event of a kick, and after closing the BOPs, quite high pressures may occur in
this large pipe. To withstand these potentially severe conditions, the casing must be
cemented up to surface.

Also, the formations that are crossed contain aquifers and it wo uld be a serious problem if
these fresh water reservoirs were polluted due to cross flow with other formations!

More requirements come in when drilling in deep water environments since the formations
are still quite cool - thus preventing fast setting of the cement. It is not uncommon to drill
through gas hydrates bearing formation, which represents a serious drilling hazard.

Accurate prediction of the temperature in the formation during these operations is not
mature yet. We are at the limits of our technological know-how.

32
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Intermediate Casing(s)

n Long section, down to top of reservoir

n Cased to drill the reservoir without problems

Schlumberger Private
n Cemented up to shoe of previous casing
n Potential problems: over-pressured or loss zones, shales

n Narrow pressure window, between pore @ bottom & frac @ top

13’’3/8 casing
in 17’’1/2 hole OBM or SBM
Long sections: High cost
9’’5/8 casing
in 12’’1/4 hole
n Large variety of lithologies crossed
2000 to 5000 m long,
n Large volume of cuttings generated
deviated

Schlumberger Private
33 GD
5/31/2005

Intermediate casings are set between the surface casing and the top of the reservoir.
Theses sections might be long, with deviated portions. In mature fields, the pressure
window between the pore pressure and the fracture pressure may be very narrow. This
causes serious placement problems and exotic solutions are sometimes required:
• 2 stages jobs
• foamed cement
• Modern solution = LiteCRETE systems

When zonal isolation problems are expected, very costly cement slurries are used that can
push the cost of the cement job to several thousand US dollars.

Offshore, drilling is sometimes limited by the need to lift cuttings through the riser, I.e. low
velocity area: DF rheology may be dictated by this need.

33
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Reservoir Casing(s) or Liner(s)

n Minimum damage to the reservoir

Schlumberger Private
n Potential problems: torque & drag

Reservoir Drilling Fluid

Then
Completion Fluid
7’’ liner
in 8’’1/2 hole
3000 m to 6000 m
deviated to horizontal

Schlumberger Private
34 GD
5/31/2005

The reservoir casing or liner has objectives similar to those cited above. A liner is a casing
that only covers the new open hole and stops just above the shoe of the previous casing
hence saving costs of steel.

Zonal isolation is now a critical issue especially when there are several reservoirs or when
the oil company wants to produce a specific layer:

• For vertical or deviated wells, good zonal isolation is mandatory to avoid

producing too much water or gas
• In horizontal wells, the production liner is often not cemented … so no problems in
the short term (problems will appear later, when remedial work has to be done)

34
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Determination of Casing Design from Pressure Control

kg/m3
m
1200 1400 1600 1800
Vertical well in homogeneous formation
0

Hydrostatic
Min. Dynamic
Frac
Pore

Equivalent Density = Pressure / g TVD

Schlumberger Private
Shoe of
1000

previous
Measured Depth

casing Static conditions:

ED = mud density
Dynamic conditions:
2000

ECD = mud density + annulus frictions / g TVD

Danger
Warning

Warning
Danger

TVD = True Vertical Depth

ECD = Equiv. Circulating Dens.
3000

Pressure window

Schlumberger Private
Well Dynamic Well Security

35 GD
5/31/2005

Three slides to explain the telescoping casing design from the pressure control point view.

Present slide: definition of vocabulary and standard representation ED vs. TVD. A variation
is to present ED vs. measured depth, for deviated wells.

35
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Determination of Casing Design from Pressure Control

Vertical well in homogeneous formation

Equivalent Density = Pressure / g TVD

Schlumberger Private
Static conditions:
ED = mud density
Dynamic conditions:
ECD = mud density + frictions / g TVD

TVD = True Vertical Depth

Pressure window ECD = Equiv. Circulating Dens.

Schlumberger Private
36 GD
5/31/2005

Practical results, for an offshore well: many casing sizes are mandatory.

This view is based on 3 facts:

•There is a single fluid in the annulus
•The pressure on surface is the atmospheric pressure
•There is no pressure discontinuity in the annulus

If any of these 3 facts is not kept, this is called “managed pressure drilling”

36
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Conventional Riserless

Managed
Pressure Single
Heavier Mud w/
Seawater Above

Drilling
Mudline
Mud
Weight

Same Bottom
Hole Pressure

Schlumberger Private
Pressure

Depth

Schlumberger Private
37 GD
5/31/2005

One way to go beyond the pressure window limitations is commonly called “managed
pressure drilling”.
•A radical solution for offshore well is the so-called dual-gradient method. This is
being developed, not fully tested yet.
•Less radical solutions include choking the mud flow on surface: this has been
commonly done for underbalanced drilling.
•Choking the mud flow at sea bed level
•Gas injection in the riser

Reference: D. M. Hannegan, “Managed Pressure Drilling in Marine Environments –

Case studies”, SPE 92600

37
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Drilling Fluid Properties Guidelines

Property Top Hole* 17 1/2” - 16” 12 1/4” 8 1/2” 6”
Flow rate (gpm) A.F.A.P. 900+ 500-700 300-400 200-300
YP (lbf/100 ft 2) 30+ 25-30 15-25 12-15 12-15

Schlumberger Private
3 RPM Fann 25 15 10 5 5
Fluid Loss (mL)** n/c 10-15 5-10 3-5 3-5
10 mn gels (lbf/100 ft2) 35 max 35 max 35 max 35 max 35 max
Key driver for the DF cost cost ROP, inhibition reservoir

Mud Weight : as required

LGS : Preferably below 6% for a water based mud * 36” or 26” hole
PV : as low as possible ** Fluid loss for water based muds
AV : should be above 80 ft/mn

Schlumberger Private
38 GD
5/31/2005

This is a summary slide providing orders of magnitude of properties requirements vs.

section drilled.

Overall, as the well goes deeper:

. DF density increases,
. Rheology decreases (to limit friction pressure drops)
. Fluid loss control is tighter
. Inhibition becomes more important.
. Mud volumes are smaller

38
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord Mud Types and M-I Swaco Systems
Cheap to moderately expensive
WBM’s
Expensive to very expensive
OBM’s, SBM’s

(except formate muds: very expensive)

Average to good HSE footpring Bad to average HSE footprint
Limited compatibility with water sensitive formations (shale Good shale inhibition
Good tolerance to added solids (cuttings) Limited tolerance to added solids
Moderate to low rate of penetration High rate of penetration
Easy to clean before cementing or well completion Specific cleaning systems required
Medium to high formation damage Low formation damage, possible interference with RFT tools
RDF: low formation damage

Schlumberger Private
Drilling Systems
Bentonite muds M-I Gel Diesel-based muds Versadrill
Polymer muds PolyPlus Mineral oil-based muds Versaclean
Inhibitive muds K-MAG Low-toxicity mineral oil (LTMO) Versavert
Encapsulating muds Ultradril Synthetic oil-based muds
Glycol mud Glydril Linear alpha-olefins, internal olefins Novaplus, Novatec

Inhibition
Other water based muds WARP Paraffin Paratherm
Silicate muds Sildril Paradril, Ultidrill
Conductive muds SigmaDril Paraland

HSE
MMH, Aphrons, Formate Aphrons ICS Rheliant
DRILPLEX Ester muds Petrofree, Finagreen
DURATHERM, Ecogreen
ENVIROTHERM Exotic systems: Acetal, ether, etc
Old systems: Gypsum muds, Lime muds
Reservoir Drilling Systems

Slide before last of part 1, giving an overview of DF systems, This is organized in Water-based Stardril
DiPro
FLOPRO
Oil-based FAZEPRO
TRUCORE
VERSAPRO, VERSAPRO LS

drilling fluids vs. reservoir DF and WBM vs. OBM/SBM. 39 GD

Synthetic based NOVAPRO, NOVATEC
PARAPRO

5/31/2005 Baker Hughes Drilling Fluids systems: http://www.bakerhughes.com/drillingfluids/about/popup_fluidsyste ms.htm

M-I Reservoir Drilling systems Halliburton Baroid: http://www.halliburton.com/esg /sd1315.jsp

DIPRO Water-Base. DIPRO is a highly engineered drilling fluid system with a wide range of flexibility and compatibility with a full gamut of well
conditions and completion methods.
FAZEPRO Oil-Base. The FAZEPRO system is the industry's only reversible reservoir drill-in fluid system that delivers the drilling performance of an
invert emulsion fluid with the filtercake-removal efficiency and overall completion simplicity of a water-base mud.
FLOPRO NT Water-Base. M-I SWACO has worked to develop technology and a fluid system to answer the production needs of the reservoir
engineer, while addressing the performance requirements of the drilling operations personnel.
NOVAPRO Synthetic-Base. The synthetic NOVAPRO olefin-base drilling fluid system, designed for reservoir drilling applications, is especially
suited for high-temperature, low-permeability, open-hole-completed reservoirs.
NOVATEC Synthetic-Base. NOVATEC, an ultra-low-viscosity, LAO-base synthetic fluid system suited for use in deepwater operations, drilling in
environmentally sensitive and high-differential pressure environments, is especially suited for cold water and ERD applications.
PARAPRO Synthetic-Base. The PARAPRO paraffin-base drilling fluid system is designed as an alternative to conventional or mineral-oil reservoir
drill-in fluid systems.
TRUCORE Oil-Base. All-oil oil-base system designed for coring operations
VERSAPRO Oil-Base. The oil-base VERSAPRO reservoir drill-in fluid is designed for drilling high-temperature, low-permeability, open-hole-
completed reservoirs.

Schlumberger Private
VERSAPRO LS Oil-Base. The VERSAPRO LS system is a low-solids invert emulsion version of the VERSAPRO system. It employs CaCl2,
CaBr2, NaBr, KCOOH, CeCOOH, etc. as the internal phase for density.
M-I Drilling systems
APHRON ICS Water-Base. An engineered, high-performance drilling fluid that reduces the risk of formation invasion and lost circulation by the use
of energized micro bubbles.
DRILPLEX Water-Base. The DRILPLEX system delivers exceptional performance in a multitude of applications and does so in one, easily
engineered, cost-effective and environmentally sound package.
DURATHERM Water-Base. The DURATHERM system is a low-colloid, contaminant-resistant water-base fluid designed for high-temperature
drilling.
ECOGREEN Synthetic-Base. ECOGREEN, our ester-base synthetic fluid system, is one more example of M-I's uncompromising pledge to balance
superb downhole performance with environmental stewardship.
ENVIROTHERM Water-Base. The ENVIROTHERM system is a chrome-free, environmentally advanced fluid designed for high-temperature
drilling.
ENVIROVERT Oil-Base. With ENVIROVERT, operators now have all the performance advantages of a conventional invert-emulsion drilling fluid,
with the added benefit of reduced disposal costs.
GLYDRIL Water-Base. The GLYDRIL systems, a family of glycol-enhanced fluid systems, deliver performance beyond that of conve ntional polymer
and other water-base fluids.
K-MAG Water-Base. The K-MAG system, used for drilling troublesome shales, provides good shale inhibition and wellbore stability as it minimizes
clay migration, swelling and dispersion.
NOVAPLUS Synthetic-Base. The low-viscosity, internal-olefin-base NOVAPLUS synthetic drilling fluid is ideally suited for drilling in deepwater
and environmentally sensitive areas.
NOVATEC Synthetic-Base. NOVATEC, an ultra-low-viscosity, LAO-base synthetic fluid system suited for use in deepwater operations, drilling in
environmentally sensitive and high-differential pressure environments, is especially suited for cold water and ERD applications.
PARADRIL Synthetic-Base. The paraffin-base PARADRIL system provides good hole cleaning, superior retur n permeability, minimal formation
damage and excellent wellbore stability that help maximize production and lower costs.
PARALAND Synthetic-Base. The paraffin-base PARALAND drilling fluid system is designed to allow the optimized land-based disposal of drill
cuttings.
POLY-PLUS Water-Base. The polymer-base, POLY-PLUS PHPA system is designed for improved cuttings encapsulation and shale stabilization.
RHELIANT Synthetic-Base. The RHELIANT 'Flat' rheology system is designed to manage ECD without sacrificing hole cleaning ability or
promoting barite sag.
SILDRIL Water-Base. The SILDRIL system capitalizes on the very latest in silicate technology to give performance approaching that of oil mud, but
with the environmental acceptability of a water-base fluid.
TRUCORE Oil-Base. All-oil oil-base system designed for coring operations
TRUDRIL Oil-Base. Its inherent lubricity, borehole stability, enhanced hole cleaning and low ECDs help make the TRUDRIL system an easily
engineered system that is an ideal alternative to an invert-emulsion fluid.
ULTRADRIL Water-Base. With ULTRADRIL, M-I SWACO has given the industry a field-proven, water-base drilling fluid that provides outstanding
shale inhibition and drilling performance characteristics previously associated only with invert emulsion systems.
VERSACLEAN Oil-Base. The VERSACLEAN mineral oil-base drilling fluids system is designed for use in areas where diesel oil is prohibited.
VERSADRIL Oil-Base. The VERSADRIL diesel oil-base drilling fluids system, designed for wellbore stability is contaminant resistant and solids
tolerant.
VERSAVERT Oil-Base. The VERSAVERT system is an ultra-low toxicity mineral oil-base drilling fluid.
39
Introduction to Drilling Fluids – Part 1 5/31/2005
G Daccord

Drilling Fluid Performance

Shale Inhibition Oil Based Mud
Formation Ester Based Mud
Protection Lubricity ULTIDRIL System
KCl-PHPA

Schlumberger Private
Glydril System

Thermal Tolerance to
Stability Contaminants

Corrosion Environmental
Inhibition Footprint

Drilling Performance

Schlumberger Private
40 GD

This slide illustrates very effectively the relative performance of drilling fluids in meeting all
requirements but cost.

Note that oil base muds meet all the parameters except the environmental footprint. This is still
an area of major concern even with the development of synthetic muds.

What are the advantages from using oil base mud?????

Low cost and good inhibition, suitable for most difficult sections when cuttings disposal is
solved by means other than dumping. These have been the systems of choice in the North Sea
until environmental regulations banned them (hopefully!!).

40
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Introduction
Part 1 – Function, properties
Part 2 – DF management on surface
Part 3 – DF chemistry

Part 2 Part 4 – A few downhole problems

Schlumberger Private
Drilling Fluid Management & Maintenance

Schlumberger Private
Part 2 of the introductory presentation on Drilling Fluids.

G Daccord, January 2005.

Part 1 was about functions and properties of DF. This part will focus on DF maintenance at rig
site.

Several slides were taken from a presentation from D Vanbeck, used as teaching support for
new field engineers.

1
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Drilling Fluid Management

Objectives: maintain DF properties at required target values, subject

to minimum cost and to HSE constrains (regulations)
This means managing the whole fluid system

Schlumberger Private
Topics covered:
1. DF management Drilling Fluid cost =
n Properties maintenance, Fluid cost +
n Daily Mud Report Short version Maintenance chemicals cost +
n Detailed description of solids circuit Extended version SCE cost +
n Cost optimization Disposal cost +
(Engineering cost)
2. Waste management
n What to do with separated solids
n What to do with the mud at the end of a section, end of well

Schlumberger Private
3. IFE: Integrated Fluids Engineering
2 GD
5/31/2005

The role of the DF company / mud engineer is to ensure the DF maintains its desired
properties while the well is being drilled at optimum overall cost.
The issues we will review in this part include:
. How to maintain DF properties
. Detailed description of the mud circuit on surface
. How to optimize the cost, what are the various options
. What to do with separated solids, I.e. waste management

The DF properties vary for a variety of reasons (contamination with cuttings or formation fluids,
degradation of some components, adsorption of some components on wellbore or cuttings);
also, the target DF properties evolve with depth and according to eventual drilling problems.

In this part we do not consider how the optimum DF properties are defined – this will be
summarized in Part 3.

SCE = Solids Control Equipments

2
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

DF management
Adjustment of DF Properties, DMR Waste management
Integrated Fluids Engineering

Actions
Measurements Target
Properties
• Density
1. Remove undesirable solids

Schlumberger Private
• Rheology or dump some whole mud
• Fluid loss 2. Add fresh components or
• Titrations whole mud

• Retort
All these data and actions are summarized in the Daily Mud Reports
Examples of DMR
• Surface casing (WBM)

Schlumberger Private
• Intermediate section (SBM)
3 GD
5/31/2005

Maintenance of DF properties is performed by making measurements on the active pit mud,

comparing results with target values and adjusting mud composition either by removing
components or adding some. The adjustment is mainly based on trial-and-error methods.
The DMR is the main tool used to record all parameters; it is worth detailing an example.
Important sections:
• Top: general info on the status of the well, which section is being drilled
• Left: mud properties
• Center: drill string and SCE description
• Right: cost, financial details
• Bottom: summary of daily mud engineer activity, explanations

Note how some data are visibly erroneous! Exercise: find them out!

3
 PERTAMINA DAILY MUD REPORT REPORT No.: 09 P.T.
NEW VENTURE DATE :MAY. 27, 2004 MATRA
IPM SCHLUMBERGER COMPANY REP. IPM SCHLUMBERGER : Mr. ANTE BOBIC.& Mr.SAMSON CONTRACTOR REP. : Mr. JATUN UNIKATAMA
PRESENT ACTIVITY : NIPPLE UP SPUD IN : MAY, 25,2004 Jl.Kertanegara No.62
JAKARTA 12180
Well KTB-B Bit Size 26" Survey / Logging hrs 30 CSG @ 23 m Depth 30 m Ph : (021) - 7233191
Contractor SCHLUMBERGER Make Drilling Time hrs CSG @ m Angle Fax : (021) - 7233290

o
Rig PDSI MSH-2000 Type Bottom-up #DIV/0! mnt Open Hole 36 m Flow rate gpm E mail : matraunika
Phase 26" Jets Circulating Time #DIV/0! mnt Daily Progress 30 m Pump press psi @' hotmail.com
FLUID TYPE FRESH WATER GEL
SAMPLE TIME 12:00 24:00 STRING ASSY. UNIT DAILY
No PRODUCT USED RECV STOCK
Depth m OD Length PRICE COST Last stock
FLOWLINE SAMPLE DP1 5.00 30.00 1 UNIBAR 100 LB 5640 8.35 5640
Mud Weight Out SG DP2 2 UNIGEL 100 LB 30 340 11.25 337.50 370
Mud Temp Out C HWDP 5.00 3 UNICARB FINE 50 KG 6.45
Funnel Vis Ou sec DC1 6.25 4 UNICARB MEDIUM 50KG 6.45
Sand Out % DC2 8 3/8 WATER - BASED MUD CHEMICALS
PIT SAMPLE TUBING 1 BIOCIDE/ UNICIDE 5 GA 50.91
Mud Weight SG 1.02 1.04 PUMP DATA 10P130 & 9P 10 2 CAUSTIC SODA 50 KG 1 24 57.20 57.20 25
Mud Temp C LINER/BPS 6.00 0.082 3 CMC - HV 25 KG 90 67.50 90
Funnel Vis sec 40 42 SPM/ BPM 4 CMC - LV 25 KG 80 62.80 80
Sand % HYDRAULICS 5 UNIDETERGENT 55 GA 2 212.00 2
Retort Water % 3 3 AV. DPXOH m/mnt 6 UNIDEFOAM 55 GA 413.80
Retort oil % AV. DCXOH #DIV/0! m/mnt 7 DEFOAMER ( Cn ) 5 GA 20 37.2. 20
Uncorrected s % 97 97 VC. DPXOH -7 m/mnt 8 KCL 50 KG 30 150 120 17.80 534.00
Oil / water Ratio VC. DCXOH #DIV/0! m/mnt 9 KOH ( POTASH ) 25 KG 40 35.80 40
Fann 600 rpm 33 31 . SHALE SHAKERS 10 UNIPAC LV 25 KG 92.50
Fann 300 rpm 23 23 Make : Swaco 11 UNIPAC R 25 KG 116 97.50 116
Fann 200 rpm Screen # 1 50/50/84/84 Msh 12 UNIPHPA L 5 GA 20 20 88.00
Fann 100 rpm Screen # 2 50/50/84/84 Msh 13 UNIPHPA - P 25 KG 98.00
Fann 6 rpm Screen # 3 50/50/84/84 Msh 14 UNI SPA 5 GA 71.80
Fann 3 rpm Run Hrs Hrs 15 UNICARB COARSE 50 KG 6.45
Gel 10 sec lbs/100 ft2 4 4 DESANDER 16 SOLTEX 50 LB 81.70
Gel 10 min lbs/100 ft2 12 12 Make : RIG 17 SODA ASH 50 KG 30 31.30 30
Apparent Visc cps 16.5 15.5 Run Hrs Hrs 18 SOD. BICARB 50 KG 40 30.40 40
Plastic Viscos cps 10 8 DESILTER / M.CLEANER 19 UNICARB COARSE 25 KG 3.40
Yield Point lbs/100 ft2 13 15 Make : RIG 20 UNICARB MEDIUM 25 KG 3.40
n 0.52 0.43 Screen 200 X 5 Msh 21 UNILUBE 55 GA 357.95
k 0.62 1.17 Run Hrs Hrs 22 ZINK CARBONAT 25 KG 32.80
LSR YP lbs/ft 100 ft CENTRIFUGE (S) 23 FRACSEAL 30 LB 15.55
WATER - BASED MUD Make : SWACO 24 XANTHAN GUM 25 KG 225.70
FiltrateAPI(30m mls 10.0 10.0 Speed Rpm 25 SOD. BICARB 50 KG 30.40
Ph 9.0 9.0 MW out SG OIL - BASED MUD CHEMICALS
Pf / Mf 0.2/0.45 0.2/0.4 MW Under Flow SG 1 CACL2 25 KG 16.00
Chlorides mg/l 4,800 Run Hrs Hrs 2 DEMULSIFIER 55 GA 981.24
Total Hardnes mg/l 3 UNIMUL - P 55 GA 8 511.00 8
MBT ppb 10.0 START VOL 100 M3 4 UNIMUL - S 55 GA 8 537.95 8
NaCl mg/l MUD BUILT ON RIG 5 UNILOW RM 55 GA 952.00
KCl ppb PRODS. VOL. 1 M3 6 UNITONE / UNITROL 50 LB 90 47.50 90
Solids (Correc % 97.0 M3 7 UNITHIN 55 GA 961.00
ASG SG 1.0 WATER VOL. M3 8 UNIGEL-OM / UNIVIS 50 LB 360 90.70 360
LGS % 191.5 TRANS. SOBM IN M3 9 UNIWET 55 GA 4 547.00 4
HGS % INCREASE VOL. 1 M3 10 HYDRATED LIME 25 KG 200 6.55 200
CAKE 1/32" 1 1 TOTAL HANDLED 101 M3 11 UNICLEAN-OM 55 GA 457.00
HPHT 12 UNIFREE 55 GA 4 4 385.00
SARALIN - OBM SURF. LOSS M3 13 UNIPlug F 25 KG 9.70
Filtrate 500psi mls DUMPED M3 14 SARALIN M3 655.35
AgNO3 (0.282 mls FORM. LOSS M3 15 SOBM FROM LMP M3
H2SO4 / Alkalinity DEAD VOL. M3 16 UNIQSEAL C 40 LB 22.30
Excess Lime kg/m3 TOTAL LOSSES M3 17 UNIQSEAL F 40 LB 22.30
CaCl2 (brine p kg/m3 LOST - CIRCULATION MATERIALS
Solids (Correc % TRANS. OUT M3 1 UNI PLUG - F 25 KG 9.70
Brine % 2 UNI PLUG - M 25 KG 9.70
Oil / Brine ratio ( O/ W HOLE VOL. 0 M3 3 UNI PLUG - C 25 KG 9.70
ASG SG ACTIVE VOL. 80 M3 4 UNIQSEAL M 40 LB 22.30
LGS % ACT. SYSTEM 81 M3 DAILY ENGINEERS SERVICES ( 1 Engr ) US $ 225.00
HGS % M3 CUMMULATIVE ENGINEERS SERVICES US $ 2,250.00
Electrical Stab volts RESERVE 25 M3 DAILY MUD COST US $ 928.70
Geltone ppb M3 CUMMULATIVE MUD COST US $ 4,529.70 WBM CALC
W P Salinity ppm #DIV/0! FINAL VOL. 106 M3 TOTAL MUD COST + ENGINEER SERVICES US $ 6,779.70 100
`Chloride ppm #DIV/0!
REMARKS: MUD PIT DETAILS
CHANGED SCREEN TO 50/50/84 ( X 3). M3 SG M3 SG OBM CALC
MIXED 25 M3 PREHIDRATED MUD IN PITS # 6 RES-1 25.00 NIL 1.03 Sandtrap 1.00
RUN SUFACE CIRCULATION AND ADDED 1 % KCL IN TO ACTICE SYSTEM AS A SHALE IN HIBITOR. RES-2 NIL 1.00 Settling 1 1.00
TAG TOP OF CEMENT @ 20 MT.CONT NIPPLE UP RES- 3 NIL 1.00 Active 2 18 1.00 1.00
RES 4 NIL 1.00 Active 3 18 1.00
SLUG NIL Active 4 18 1.00 3.00
MUD PLANT Active 5 26 1.02 97.00
SOBM NIL 1.02
RES- SOBM NIL -84.41
181.42
MUD ENGINEERS : SIMON NAPITUPULU & GIDION N MUD ENG SUPV : I. N. SABAR
Introduction to Drilling Fluids – Part 2 5/30/2005
G. Daccord
Notes page for the DMR

The DMR is probably one of the most important source of information for anybody who has to work
on a rig while drilling: it should be available from the driller or company man.
A DMR is traditionally organized as follows:
Header: Well status
Three columns of detailed information between a
header and a footer.
• The header contains information about Column Column Column
the well and the section being drilled 1: Mud 2: Rig 3:
properties and SCE Additions
• Column 1 contains all mud properties status and cost
• Column 2 contains drill string information
and SCE + mud tanks arrangement
• Column 3 contains inventory and cost
information.
• The footer includes a description of key
actions that occurred on the rig + tanks

Schlumberger Private
status
DMR’s are done twice a day, noon and midnight. Footer: remarks, key actions done

Some specific comments on the DMR for the surface section:

• Header: vertical surface section being drilled, with minimum amount of info provided
• Column 1: this is a bentonite mud, just water + bentonite + some KCl. Viscosity is
monitored at 2 RPM’s only. Only a few chemical properties are measured: pH and
carbonate content.
Solids concentration is wrong (97% is the water content), which gives absurd LGS
content 191%!
• Column 2: only shakers are used, with coarse mesh. Volumes are not consistent: actual
hole volume is about 15 m3 and surface active tanks 74 m3, i.e. total active = 90 m3, not
80.
• Column 3: only 300 lbs of bentonite + 50 kg NaOH + 300 kg KCl (0.3 %) have been
used

Vocabulary :
MBT: methylene Blue test, used to determine the amount of exchangeable clay, often expressed in
terms of “equivalent bentonite content”.
Cake: thickness of filter cake, expressed in 1/32nd of inches
ASG: average solids gravity

Remark: DMR’s frequently contain erroneous data. On this one, the retort water% and the solids
content data are inverted (circled in red), which results in the LGS% data being absurd.
 PERTAMINA DAILY MUD REPORT REPORT No.: 23 P.T.
NEW VENTURE DATE :JUNE. 16, 2004 MATRA
IPM SCHLUMBERGER COMPANY REP. IPM SCHLUMBERGER : Mr.KEN EICHER & Mr.NOVY.Y CONTRACTOR REP :Mr. JATUN UNIKATAMA
PRESENT ACTIVITY : DRILLING SPUD IN : MAY, 26,2004 Jl.Kertanegara No.62
1
Well KTB-B Bit Size 12 1/4" Survey / Logging hrs 13" CSG @ 1201 m Depth 1426.0 mt Ph : (021) - 7233191
Contractor SCHLUMBERGER Make HYCALOG Drilling Time hrs CSG @ m Angle Fax : (021) - 7233290

o
Rig PDSI MSH-2000 Type PDC Bottom-up 38 mnt Open Hole 225 m Flow rate 632 gpm E mail : matraunika
Phase 12.25 Jets 3X20 2X16 Circulating Time 92 mnt Daily Progress m Pump press 1640 psi @' hotmail.com
FLUID TYPE OIL BASE MUD
SAMPLE TIME 12:00 23:00 STRING ASSY. UNIT DAILY
No PRODUCT USED RECV STOCK
Depth m 1300.0 1426.0 OD Length PRICE COST
FLOWLINE SAMPLE DP1 5.00 1306.00 1 UNIBAR 100 LB 360 8714 8.35 3,006.00
Mud Weight Out SG 1.50 1.52 DP2 5.00 2 UNIGEL 100 LB 267 11.25
Mud Temp Out C 62 64 HWDP 5.00 3 UNICARB FINE 50 KG 6.45
Funnel Vis Out sec 86 84 DC1 6.25 40.00 4 UNICARB MEDIUM 50KG 6.45
Sand Out % 0.30 0.30 DC2 8.00 80.00 WATER - BASED MUD CHEMICALS
PIT SAMPLE TUBING 1 BIOCIDE/ UNICIDE 5 GA 50.91
Mud Weight IN SG 1.50 1.52 PUMP DATA 10P130/9P100 9.5 2 CAUSTIC SODA 50 KG 20 57.20
Mud Temp IN C 62 64 LINER/BPS 6.25 0.085 3 CMC - HV 25 KG 90 67.50
Funnel Vis IN sec 86 88 SPM/ BPM 177 15.047 4 CMC - LV 25 KG 62.80
Sand IN % 0.30 0.30 HYDRAULICS 5 UNIDETERGENT 55 GA 2 212.00
Retort water % 18 17 AV. DPXOH 189 6 UNIDEFOAM 55 GA 413.80
Retort oil % 69 70 AV. DCXOH 74 m/mnt 7 DEFOAMER ( Cn ) 5 GA 20 37.2.
Uncorrected solids % 13 13 VC. DPXOH 19 m/mnt 8 KCL 50 KG 17.80
Oil / water Ratio 79/21 80/20 VC. DCXOH 64 m/mnt 9 KOH ( POTASH ) 25 KG 40 35.80
Fann 600 rpm 88 84 . SHALE SHAKERS 10 UNIPAC LV 25 KG 92.50
Fann 300 rpm 56 54 Make : Swaco 11 UNIPAC R 25 KG 30 92.50
Fann 200 rpm 36 34 Screen # 1 50/50/84/84 Msh 12 UNIPHPA L 5 GA 10 88.00
Fann 100 rpm 27 25 Screen # 2 50/50/84/84 Msh 13 UNIPHPA - P 25 KG 98.00
Fann 6 rpm 16 14 Screen # 3 50/50/84/84 Msh 14 UNI SPA 5 GA 71.80
Fann 3 rpm 12 12 Run Hrs 20 Hrs 15 UNICARB COARSE 50 KG 6.45
Gel 10 sec lbs/100 ft2 14 13 DESANDER 16 SOLTEX 50 LB 81.70
Gel 10 min lbs/100 ft2 26 24 Make : RIG 17 SODA ASH 50 KG 30 31.30
Apparent Viscositycps 44.0 42.0 Run Hrs Hrs 18 SOD. BICARB 25KG 34 15.20
Plastic Viscosity cps 32 30 DESILTER / M.CLEANER 19 UNICARB COARSE 25 KG 3.40
Yield Point lbs/100 ft2 24 24 Make : RIG 20 UNICARB MEDIUM 25 KG 3.40
n 0.65 0.64 Screen 200 X 5 Msh 21 UNILUBE 55 GA 357.95
k 0.61 0.65 Run Hrs 18 Hrs 22 ZINK CARBONAT 25 KG 32.80
LSR YP lbs/ft 100 ft2 8 10 CENTRIFUGE (S) BRANDT 23 FRACSEAL 30 LB 200 15.55
WATER - BASED MUD Make : SWACO STD518 24 XANTHAN GUM 25 KG 225.70
FiltrateAPI(30min)
mls Speed Rpm 25 SOD. BICARB 50 KG 30.40
Ph MW out SG OIL - BASED MUD CHEMICALS
Pf / Mf MW Under Flow SG 1 CACL2 25 KG 10 470 16.00 160.00
Chlorides mg/l Run Hrs Hrs 2 DEMULSIFIER 55 GA 981.24
Total Hardness mg/l 3 UNIMUL - P 55 GA 3 2 511.00 1,533.00
MBT ppb START VOL 351 M3 4 UNIMUL - S 55 GA 1 5 537.95 537.95
NaCl mg/l MUD BUILT ON RIG 5 UNILOW RM 55 GA 952.00
KCl ppb PRODS. VOL. 6 M3 6 UNITONE / UNITROL 50 LB 8 62 47.50 380.00
Solids (Corrected)% M3 7 UNITHIN 55 GA 1 3 961.00 961.00
ASG SG WATER VOL. M3 8 UNIGEL-OM / UNIVIS OM
50 LB 413 90.70
LGS % RECEIVED SOBM M3 9 UNIWET 55 GA 2 2 547.00 1,094.00
HGS % INCREASE VOL. 6 M3 10 HYDRATED LIME 25 KG 15 83 6.55 98.25
CAKE 1/32" TOTAL HANDLED 357 M3 11 UNICLEAN-OM 55 GA 457.00
HPHT 12 UNIFREE 55 GA 3 385.00
SARALIN - OBM SURF. LOSS 8 M3 13 UNIPlug F 25 KG 9.70
Filtrate 500psi/300 mls
F 4.4 4.2 DUMPED M3 14 SARALIN BBL 50.0 13 104.20 5,210.00
AgNO3 (0.282 N) mls 4.6 4.8 FORM. LOSS M3 15 SOBM FROM LMP M3 370 ?
H2SO4 / Alkalinity 1.6 1.8 DEAD VOL/OOC. 6 M3 16 UNIQSEAL C 40 LB 22.30
Excess Lime kg/m3 5.9 6.7 TOTAL LOSSES 14 M3 17 UNIQSEAL F 40 LB 22.30
CaCl2 (brine phase)
kg/m3 224 246 LOST - CIRCULATION MATERIALS
Solids (Corrected)% 11.92 11.86 TRANS. OUT M3 1 UNI PLUG - F 25 KG 9.70
Brine % 19.08 18.14 2 UNI PLUG - M 25 KG 9.70
Oil / Brine ratio ( O/ W) 78/22 79/21 HOLE VOL. 104 M3 3 UNI PLUG - C 25 KG 9.70
ASG SG 5.98 6.18 ACTIVE VOL. 111 M3 4 UNIQSEAL M 40 LB 22.30
LGS % 12.50 13.83 ACT. SYSTEM 221 M3 DAILY ENGINEERS SERVICES ( 2 Engr ) US $ 440.00
HGS % 24.42 25.69 M3 CUMMULATIVE ENGINEERS SERVICES US $ 10,405.00
Electrical Stability
volts 760 780 RESERVE 136 M3 DAILY MUD COST US $ 12,980.20
Geltone ppb 4.5 5.0 M3 CUMMULATIVE MUD COST US $ 108,524.85
W P Salinity ppm 285779 #DIV/0! 306559 FINAL VOL. 343 M3 TOTAL MUD COST + ENGINEER SERVICES US $ 118,929.85
`Chloride ppm 182613 #DIV/0! 195891
REMARKS: MUD PIT DETAILS
CONT'D RIH AND T.O.C AT 1178 M. DRILL OUT CEMENT AND NEW FORMATION TO 1207 M. M3 SG M3 SG
R/U DOWELL TO PERFORM FLOT WITH EQ.SG = 2.09, PRESSURE 1050 PSI. RES-1 24 1.48 Sandtrap 28 NC
INCREASE MW TO 1.53 SG . ADD UNITHIN AND EMULSIFIER IN THE ACTIVE PIT. RUN D/SILTER TO MINIMIZE OF RES-2 24 1.48 Settling 1 12 1.48
SOLID. DRILL A HEAD TO 1426 M AT REPORT TIME. RES- 3 4 Active 2 15 1.48
RES 4 22 1.48 Active 3 18 1.48
NOTE: SLUG 4 1.65 Active 4 18 1.48
SURFACE LOSSES WERE : ELECTRICAL POWER OFF SUDDENLY=8 M3 (460 GPM FOR 5 MINUTE),OIL ON CUTTING SARRALINE 10 Active 55 20 1.48
WHILE 12 1/4" DRILLED= 6 M3 MATRA PITS 48 1.35
REC- SOBM
111
MUD ENGINEERS : YUSUF.K - AGUS M - DEWA MUD ENG SUPV : TURKANDI .
Introduction to Drilling Fluids – Part 2 5/30/2005
G. Daccord
DMR for intermediate section
• Header: 12 ¼ in section being drilled, current depth at 1426 m, normal flow rate 632
gpm.
• Col 1: weighted OBM used. Full Fann readings and viscosity data given. All chemical
measurements are available. The ASG is too high, not realistic value (problem of retort
method). Also the uncorrected oil % is quite different from HGS+LGS%: 13 vs. 13+24.
• Col 2: shakers and mud cleaner (with very fine mesh) used. Note the 6 bbl of surface
losses, which is a serious HSE incident.
• Col 3: compare the daily mud cost for this mud system vs. the previous one, $12980 vs.
$928.
The material used to build the 6 bbl of new mud are clearly visible: barite, surfactants, oil
and lime
• Footer: detailed description of all tanks + explanation of the cause of surface losses

Vocabulary:
LSR YP: low shear rate yield point, between Bingham YP and gel values

Schlumberger Private
N and K values are irrelevant
ASG: calculated average solids specific gravity (HGS+LGS). The obviously wrong value (it cannot
be higher than the HGS density = 4.2) leads to inconsistent LGS and HGS values: 12.5% + 24.4%,
compared with 13% measured.
AgNO3: titration of chloride ions
WP Salinity: water phase salinity, from which a water activity coefficient can be determined.
OOC: oil on cuttings
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Solids Management

Why are solids so important to the DF engineer?

n Solids and drilled solids in particular are the single most important contaminant in the
mud system

Schlumberger Private
The nature and content of suspended solids directly affects key properties – and functions - of
the drilling fluid
n Density, rheology, filter cake properties, lubricity, ...

These modified properties impact drilling performance and the environment

n Drilling efficiency: ROP, Hole cleaning
n Drilling risks: Differential sticking, Surge & swab
n Mud costs: Dilution volume, maintenance, polymers & additives

Schlumberger Private
4 GD

Why is it so necessary to keep strict control over the solids in a drilling fluid?

4
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Solids Management – (Contd)

n We usually have both desirable solids (bentonite + weighting agents)
and undesirable solids (cuttings) in the fluid

Schlumberger Private
n Removing the undesirable solids is the first priority but this can sometimes result in
desirable solids being lost from the system

n If undesirable solids are not removed, they will be ground to finer size and become more
difficult to remove later on

Solids control must be proactive

Schlumberger Private
5 GD

Reminder:
Bentonite: provides most rheological properties, especially yield stress
Weighting agent: gives fluid density
Most undesirable: fine cuttings in colloidal form, large specific surface area, impossible to
remove using SCE

Tradeoff between removing desirable and undesirable solids: this is a cost optimization
decision

5
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

DF’s on Surface
Removal of Undesirable Solids
Solids Control

Schlumberger Private

Schlumberger Private
6 GD
5/31/2005

Back to the general view of a land rig.

On an offshore rig, the SCE’s are located underneath the main deck, not visible on surface.
We now look more in details at the tanks, colored in brown, where SCE’s are located.
What are the main functions of the surface mud system??
• storage capacity
• removal of undesirable solids
• addition and mixing of chemicals
• agitation to maintain homogeneity of the mud.
A good solids removal package will repay itself many times in terms of cheaper well costs and
less wear and tear on equipment.
SCE room in an offshore rig (shale shakers clearly visible), quite clean!

6
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord
Mud Tanks and Solids Control Equipment (SCE)
Active pit

Mud pumps

Mud
Samples

Schlumberger Private
Mud Lab
Samples
Hopper
Paddle mixers

Sand trap

7 GD
5/31/2005

Schlumberger Private
This is an overview of the mud tanks arrangement, with an indication of the use of each tank in the
process of mud maintenance.
This series of tanks is called the active system since the DF continually flows through all of them.
The circuit starts at the top-right corner, the active pit. This is where the DF is sampled for monitoring its
properties, just before being “sucked” by centrifugal pumps that feed the mud pumps. Eventually, samples
from the other tanks are taken for limited lab analysis (mainly density and solids contents)
The solids loaded drilling fluid returns from the well through the flowline, and it is treated through various
pieces of solids control equipment placed in series:
. Shale shakers
. Sand trap
. Degasser
. Desanders
. Desilter
. Centrifuges
Each piece of SCE is connected to a tank at its inlet and another at its outlet. These tanks communicate
one to the next one either by a “high weir” or a “low equalizer” as shown by the arrows.
Once cleaned from undesirable solids, fresh additives are added either directly with a hopper (e.g. barite)
or through an intermediate premix tank (polymers or bentonite).
This complex setup can be simply summarized as follows:
. An inlet stream (flowline),
. Discard streams, from each piece of SCE
. Addition streams, hopper
. An outlet at the active pit.

The mud lab is shown for reference only: obviously it is located in a safe place. Most samples are taken
from the active tank although sometimes samples from SCE equipments are analyzed to assess their
performance.

7
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Solids Removal Techniques Available

Solids can be removed by:

n Dumping and Diluting Expensive but common

Schlumberger Private
n Free sedimentation, Settlement Sand Traps and Settling Pits
n Mechanical means - Normally the cheapest option
Sieving, forced sedimentation (hydrocyclones,
centrifuges)

n Chemical means Flocculation units

Some techniques use a combination of the above

Schlumberger Private
8 GD

Classification of solids removal methods, all used on drilling rigs

Chemical means are not reviewed below: basically this is similar to what is done in water
treatment plants, in civil engineering, I.e. addition of a flocculant then separation of solids. A
common name for units doing this job is “clarification unit”.
Sometimes, it is the underflow of SCE that is treated by clarification, for instance the liquid
stream of barite recovery centrifuges.
These chemical means are not detailed below.

8
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Solids Removal By Settlement

Stokes settling times for small particles of silica of S.G. 2.65 in water

Schlumberger Private
Type Size Specific Surface Area Settling Time
microns m2/g 1 m fall
Gravel 10000 0.0003 1s
Course sand 1000 0.003 10 s
Fine Sand 100 0.0314 125 s
Silt 10 0.314 108 mn
Bacteria 1 3.14 180 hr
Colloidal 0.1 31.4 755 days

Clearly settling times for small particles are unacceptable

Residence time in a tank: volume ~ 20 bbl, pump rate ~ 600 gpm/14 bpm, time ~ 1 mn 20 s

Schlumberger Private
9 GD

Self explanatory.

Note that it is the viscosity of pure water that is considered, while the low shear viscosity of
DF’s can be one or two orders of magnitude higher than that of water.

9
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Particle Size Distribution of Mud Fed to Solids Control Equipment

Number
of High Speed Centrifuges
Particles Low Speed Centrifuges
Mud Cleaners & Desilters
Linear Motion Shakers

Schlumberger Private
Desanders
Conventional
Shakers

BARITE
3% > 74 microns
5% > 44 microns

Drill Solids

3 12 Particle Size (microns) 44 74 150 300 1000

Schlumberger Private
333 83 Specific Surface Area 23 13 6.7 3.3 1
10 GD Colloidal Ultra-Fine Fine Medium Intermediate
Silt Sand

Mesh number: number of openings in a 1 inch2 surface area

Specific surface area in m2/g of solid
Sand > 200 mesh (74 microns), silt: < 200 mesh

Various definitions for colloidal particles are possible:

• Size below 1 micron
• Brownian motion becomes relevant
• Main inter-particles forces are of “colloidal” nature rather than steric

PSD of drill solids is primarily dependent on bit type, formation properties and drilling
parameters. Various empirical correlations have been proposed.
One method is to base the cuttings PSD on formation lithology, assuming for instance that:
. The shale fraction will form cutting about 10-20 microns;
. Sandstone will form cuttings about 30 microns;
. Carbonate cuttings will be around 50-70 microns;
. Etc.
Note that a means of back-calculating the actual cuttings PSD was devised and patented. It is
based on the interpretation of dilution volumes using the model described later (NMPS).
Ref.: M. Allouche, G. Daccord, E. Touboul, "Simulation du controle des solides dans des
fluides de forage et application a la determination des tailles des deblais de forage", patent FR
97/09082

10
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

The Shale Shaker (vibrating sieve)

Basic Components:
Header-tank
Drive Motor/vibrator
Basket (containing one or

Schlumberger Private
more decks)
Sieves, screens (negative slope)

Main operating parameters

n Screen opening size and form:
down to 150 mesh (100 microns)
n Vibration direction and amplitude (G’s)
n Screen angle: positive or negative

Optimum operation: small openings -> “high solids efficiency”, dry cuttings discarded

Schlumberger Private
11 GD

D Vanbeck
The first shakers were based on those used in the mining industry.
These were usually single decks with coarse screens: RUMBA
These can still be found on some rigs today.
Development led to the introduction of the Brandt double deck which for many years was the
industry standard. however, the more widespread use of oil base muds in the 80’s led to further
work on shakers to minimize losses and the elliptical motion shaker: VSM 120 was introduced.
This in time led to the introduction of the linear motion shaker: VSM 100

11
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Hydrocyclone Theory
Pressurized slurry
enters tangentially

Schlumberger Private
Slurry rotation creates high
centrifugal forces throughout

Liquid moves inwards and upwards

as a spiraling vortex

Suspended solids driven towards

wall and then downwards
As the cone diameter decreases, the
acceleration increases

Schlumberger Private
12 GD

D Vanbeck

• The cone types currently in use are known as ‘balanced design’ types.

• The fluid enters through the side aperture.

• As it enters the top of the cone it strikes the far wall and is forced to flow tangentially.
Because of the confines of the cone the only way for the fluid to move is down the cone. So
there is development of both tangential and axial forces. These axial forces are manifested in
the development of uplift forces at the centre of the fluid

• The resultant force is proportional to the tangential velocity / radius of the spiral, so as the
diameter decreases the tangential force increases .

• This means that the denser material is forced towards the wall of the cone as the fluid moves
down the cone, and the uplift forces are increasing.

• The tangential velocity close to the wall is relatively low due to retardation from friction so
when a particle enters this area its velocity drops and the resultant uplift force is not so
pronounced and the particle will remain close to the wall of the cone rather than being forced
to the centre of the column of liquid.

• The solids will gradually move down the wall of the cone and out the apex at the bottom.
Some fluid is also exited due to the design of the cone.

• The increasing uplift force will retard the axial force until a balance point is reached and the
axial force is zero. At this point the fluid can no longer spiral and will rise up the centre of the
cone again as a spiral motion until it leaves the cone by the discharge.

12
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Hydrocyclones: Desanders and Desilters

Desilter
Desander
(many small size
hydrocyclones) (a few large

Schlumberger Private
hydrocyclones)

Outlet

Inlet Inlet Outlet

Operating variables Advantages Drawbacks

• Inlet feed rate (hydraulic head) • Cheap • Wet underflow

Schlumberger Private
• Underflow size • Large capacity
13 GD

• View of desilter and desander on a yard. Not the best picture, to be eventually replaced.

13
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Mudcleaner
Note that a Mudcleaner is basically a
combination of a hydrocyclone and a
shale shaker.

Schlumberger Private
Used to dry the underflow from
hydrocyclones,, i.e. recover
hydrocyclones
expensive liquid

Hydrocyclone use has diminished

rapidly with the introduction of better
shakers and centrifuges.

Schlumberger Private
14 GD

14
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Decanting Centrifuges
Bowl
Skid

Schlumberger Private

Schlumberger Private
15 GD

This slide shows a basic decanting centrifuge layout.

Note the power assembly

The bowl and scroll assembly
The various discharges

There are various other centrifuge designs, for instance disc-stack centrifuges or cuttings
drying centrifuges with vertical rotation axis. The disc-stack centrifuges are preferably used to
separate emulsions like sludges. Also used to dry fuel in boats.
Picture of a cuttings drying centrifuge:

15
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Decanting Centrifuges Bowl Screw

Weir plate

Schlumberger Private
Pool, pond
Beach
Cylinder Cone
Low speed centrifuges: 60 cm diameter bowl
High speed centrifuge: 35 cm diameter bowl
Operating parameters (high speed): Advantages Drawbacks
• Feed rate (100 gpm) • Only way to separate • Can treat only part of the full
• RPM (3000 RPM) small size solids mud stream
• Differential velocity (50 RPM) • Produces dry solids if well • Costly
• Pond depth (4 cm) operated
• Dilution (10%)

Schlumberger Private
16 GD

All centrifuges consist of a feed pump, control panel and rotating bowl assembly.
The feed pump is usually a positive displacement pump to give a more accurate feed rate and
to minimize break up of the solids.
The bowl rotates throwing the particles to the wall where they form a cake. This cake is
scraped out of the bowl to the discharge point. As the solids climb up the beach they are dried.
The liquid leaves via a weir overflow, this can be adjusted to vary the pool depth.

A well operated centrifuge produces very dry solids

It is an interesting exercise to model the hydrodynamics inside the bowl to calculate the
separation efficiency! This was attempted in SRPC, about 10 years ago. Refer to report:
M. Vidémont, “Model of a decanter centrifuge”, RD 95004, 30-Jun-95.

Compare the feed rate, around 100 gpm with the pump rate: 200-300 gpm for the reservoir
section. Only part of the mud stream can be treated.

16
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Simple Solids Control Equipment Setup

Centrifuge processing active system
Median
Equipment Comments
Separation
Shale Shakers < 147 µm Capable of running 100 mesh (d50 = 147 microns) at maximum circulation rate.
Shakers + hydrocyclones
Degasser na If required.
Processing Rate = 110% of maximum circulating rate.
Desander 70 µm
Discard Underflow.
Use as a desilter if required to achieve 110% of circulation rate.
Mud Cleaner 25 µm
Run in parallel with other desilter manifolds.

Schlumberger Private
Total Processing Rate (including mud cleaner cones) = 110% of maximum
Desilter 25 µm circulating rate.
Discard Underflow.
Process at least 25% of maximum circulating rate. High G, high capacity
Centrifuge 4 µm machine.
Discard Cake (Solids).

No barite recovery
Significant loss of liquid

Schlumberger Private
17 GD
5/31/2005

The various pieces of solid control equipment just detailed can be used in various ways: there
are a few typical arrangements.
The selection of the best arrangement is nothing else than a cost optimization exercise.

This slide shows a basic arrangement that would be used for an unweighted inhibitive WBM,
with low tolerance to extra solids.

17
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Complete SCE Setup

Two stage centrifuging
Median
Equipment Comments
Separation
Screen with finest mesh possible, down to 200 mesh (d50 = 74 microns) at
Shale Shakers >74 µm maximum circulation rate.
Monitor solids discharge for barite content.
Degasser na If required.
Run only if insufficient shaker capacity. 150 mesh screens recommended. Monitor
Mud Cleaner 74 - 100 µm
solids discharge for barite content.

Schlumberger Private
Barite recovery mode, high capacity machine.
Centrifuge #1 Return barite to well-agitated compartment upstream of addition section.
Dilute feed. Run at highest G-force conditions will allow. Centrate to centrifuge #2.
Run at maximum rpm, high-G machine. Discard solids. Return centrate to active
Centrifuge #2 4 µm
system.

Reduced capacity
Cost, close monitoring needed

Schlumberger Private
18 GD
5/31/2005
Low speed High speed
centrifuge centrifuge

More efficient – and expensive – arrangement. By comparison with the previous one:
. Discarded solids are drier,
. Barite is recovered.

Typical best arrangement when using OBM or SBM

18
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Barite Recovery and Fines Discard Using Two Decanting Centrifuges

Number
of High Speed Centrifuges
Particles Low Speed Centrifuges
Mud Cleaners & Desilters
Linear Motion Shakers

Schlumberger Private
Desanders
Conventional
Shakers

BARITE
3% > 74 microns
5% > 44 microns

Discarded Recovered Discarded

3 12 Particle Size (microns) 44 74 150 300 1000

Schlumberger Private
333 83 Specific Surface Area 23 13 6.7 3.3 1
19 GD

This shows how barite recovery works

19
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Among these various options, how to select the most cost-effective one?

Tools needed for modeling solids removal & mud maintenance at the different
stages of:

Schlumberger Private
– Well planning
– On-site execution and optimization
– End of well evaluation

There are 3 methods of increasing complexity

Schlumberger Private
20 GD
5/31/2005

20
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Volumes & Costs Estimates

Global Mass Balance over a section
Cuttings New Mud
(replacement + dilution)

Schlumberger Private
SCE

Removal
efficiency Mud dumped
Initial situation
Solids: cuttings + HGS
Liquids attached to solids
Final situation

Schlumberger Private
Analysis usually performed in a planning phase and at the end of a section
21 GD

Volumes & Costs Estimates - Global Approach

Simple diagram indicating that the SCE considers

• initial mud as the volume of the casing,
• Cuttings are added as drilling commences,
• then the SCE parameters are taken into account - solids, cuttings, HGS & liquids
attached to solids are all removed,
• replacement and dilution mud are added,
• any mud dumped is removed and
• the final mud is the casing and the hole volume just drilled.

This is a useful representation to determine the global performance of the SCE system. It
allows determining indices like:
. Volume of mud spent per ft of well drilled or per volume of cuttings drilled
. Mud cost / ft drilled
. Average Solids Removal Efficiency

This removal efficiency is reused for other wells plans for rough designs.

21
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Unit Operations and Flowsheet

New material
Weighting agent

Shale-shakers Sand Trap Hydrocyclones Active Pit Spec

MW

Schlumberger Private
Dump % LGS
Discard (Whole mud) Discard
BIT

Cuttings
Input
Active pit Specification: Mud weight - max % LGS
Bit unit ROP - Bit size - Pump rate
Separation units Characterized by their discharge volume rate and composition (%LGS; %HGS)
or HGS and LGS removal efficiencies + liquid to solid ratio
Prediction
Volume of mud to dump (from sand trap)
Volume of new material to add (into active pit) Similar to standard chemical
Volume of weighting agent to add (into active pit) engineering problems except

Schlumberger Private
→ Total cost non-steady-state!
22 GD

This diagram shows the concept of the Mud Process Simulator, used to optimize solids control
management.
This is not too far from what is used in other industry, e.g. chemical plants or mining industry
except the non-steady-state condition: the well is being drilled, so the volume of the circuit
increases with time.

Commercially available software’s cannot be used but Excel is sufficient to solve the problem!

22
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Solids Control Economics

Simulate different
SCE configurations …

Schlumberger Private

Schlumberger Private
23 GD
5/31/2005

A simulator was developed and included in MudCADE software, aimed at comparing the costs
of various SCE arrangements.
This screen shows the summary of a shaker+mud cleaner arrangement,

23
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

SCE Economics

… to optimize the

Schlumberger Private
global mud treatment
cost

Schlumberger Private
24 GD
5/31/2005

… and this screen dump shows the final cost comparison between four arrangements.

Although this type of tool was developed about 10 years ago, is still rarely used on actual
operations.

24
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Numerical Mud Process Simulator

Instead of using “separation

efficiencies”, we may use the full
particle size distributions:

Schlumberger Private
Shale shaker - Particle size
0.05

0.04 Mud in
Mud out
Frequency

0.03 Partition function /50

0.02

0.01
Discarded
0
0 50 100 150 200
Size (microns)

Schlumberger Private
25 GD
5/31/2005

Another generation of simulator was specified and a prototype developed, in which the physics
of solids separation is better accounted for. It was able to simulate the behavior of the whole
active system while drilling a section.

The Smith-SLB JV was created as this tool was being developed: we just had the time to
validate its concept using a couple of field cases.
It was transferred to M-I Swaco

Note that in this approach we need the PSD (particle size distribution) of cuttings: this is
usually not available but it can be estimated by calibrating the model using rig-site data,
almost in real-time.

25
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

DF management
Waste management
Integrated Fluids Engineering

Waste Management

Schlumberger Private
Drilled Solids and Used Mud

Schlumberger Private
Now that we know how to separate solids from the active mud, what do we do with these
solids?

26
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

What to do with Separated Cuttings and Used Mud?

?
Used

Schlumberger Private
Clean mud
mud
1 to 0.1 m3/m drilled 1000’s bbl

Initial situation Final situation

Constrains: regulations & cost

Schlumberger Private
27 GD
5/31/2005

Typical number, mud used: 1 m3/m drilled for WBM, 0.1 for SBM

Mud used = mud that cannot be recycled at the rig site. It must be either discharged or
offloaded for treatment in a specialized mud plant (MI SWACO EnviroCenter’s)

Theoretical solids discharged = well volume X bulking factor + liquid on cuttings

Reference: Canadian Association of Petroleum Producers, “Offshore Drilling Waste

Management Review”, February 2001, technical report 2001-0007, http//:www.capp.ca

Over last years, waste management has grown to becoming a big market by itself mostly
because of environmental regulations.
Reference: OSPAR organization for the North Sea, www.ospar.org
OSPAR objective: Protection of the Marine Environment of the North-East Atlantic

27
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Cuttings Discharge on the

Seabed
Cuttings piles survive tens of years
Deposition strongly dependent on currents & storms:
Settling velocity ~ a few mm/s

Schlumberger Private
Current ~1 m/s spreading
Depth 100 m over 10 km

Schlumberger Private
28 GD
5/31/2005

Most common method to get rid of waste = discharge into the environment.

Routinely done with WBM’s, closely regulated for OBM’s, some precautions with SBM’s:
permit mandatory

Discharged materials can be spread over large distances owing to the low settling speed of
fine particles.

28
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Present Approaches
Move towards an holistic view, i.e. consider all environmental aspects:
– Environment preservation
– Energy consumption / CO2 release for transport and treatment
– Risk analysis

Schlumberger Private
Select the Best Available Technique (BAT) …
… to prevent shifting pollution from one site to another, replacing chemical pollution by
CO2 emission, etc.
MI SWACO IFE Wells Worldwide

Schlumberger Private
29 GD
5/31/2005
Responsible Disposal

Today's approach is based on an holistic view, encouraging proactive actions

IFE = Integrated Fluids Engineering, I.e. reduction of waste at the source by optimizing SCE,
recycling of wastes in EnviroCenters, etc.
Remark the business growth: more than 10 folds increase in 4 years!
However, this number represents only a few % of the total number of wells drilled worldwide:
there is plenty of room for growth!

This is clearly driven by environmental regulations.

29
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Drilling Waste Disposal Techniques

n Dump to sea bed, directly or after treatment

n Cuttings re-injection (CRI), after grinding and slurrying
Offload, treat onshore: often combination of different techniques (cost up to ~ 100 $/bbl)

Schlumberger Private
n
– Landfill
– Immobilize: bricks, road structure
– Thermal treatments
– Distillate
– Burn (cement kilns)
– Solvent extraction
– Bioremediation, land farming
– Re-use as fertilizer Make $ from cuttings rather than paying for their disposal !

Schlumberger Private
30 GD
5/31/2005

This is a list of current techniques used to dispose of wastes, from the cheapest to the most
advanced.

Dump: for WBM and top hole when no riser is installed

CRI: relatively common for development wells, offshore
Offload: exploration wells. Becoming the only option in many areas. E.g. BP policy is “zero
discharge”

Example: large and clean cuttings (sand) may be reused for roads and fine and dirty cuttings
(silts) treated in kilns or reinjected.
Reference: SPE 86732

30
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Schlumberger Private

Schlumberger Private
Restricted to development wells,
31 GD
5/31/2005 impossible for exploration wells

These are slides directly taken from a MI Swaco presentation

CRI is also part of SLB-Well services activities, because it uses Fracturing techniques.
Basically, the technique consists in injecting wastes into hydraulic fractures created in non-
productive zones, far enough from aquifers.

31
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Schlumberger Private

Schlumberger Private
32 GD
5/31/2005

When wastes cannot be discharged or re-injected, they are treated onshore.

These installation used to be called “mud plants”, now renamed “EnviroCenters”
Both solids and used mud can be treated

32
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Schlumberger Private

Schlumberger Private
33 GD
5/31/2005

The solid matrix is simply a cheap cement like slag cement.

33
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Schlumberger Private

Schlumberger Private
34 GD
5/31/2005

Besides thermal methods, solvent methods are also used. Supercritical fluid extraction is one
method of choice: CO2, propane, etc.

TPH = total petroleum hydrocarbons, must be below 1% for solids to be allowed to be

discharged to the sea bed.

34
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Schlumberger Private

Schlumberger Private
35 GD
5/31/2005

Bioremediation is probably the most active R&D area simply because most components of the
wastes are potentially good sources of nutriments or direct fertilizers.
E.g., chloride is sometimes replaced by nitrate in OBM’s: can be directly used as fertilizers
(done for many years in Canada).
Lime is commonly spread in acidic fields to improve the water-retention capabilities of soils.
Oil can be a nutriment for bacteria
The last fluid developed by M-I Swaco is PARALAND, specially designed for being directly
spread on soils: very fast biodegradation, good fertilizing properties. Cost > SBM

Taken from SPE 74474:

35
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Selection of Cuttings Disposal Technique

Top sections
n Drilled with cheap WBM, no riser → dumped to sea bed

Schlumberger Private
Intermediate sections
n SBM: Dumped to sea bed, subject to regulations
n OBM: treated onshore

Reservoir
n WB-RDF’s: dumped

Schlumberger Private
Company policies, e.g. zero discharge for BP
36 GD
5/31/2005

Typical means of treating drilling wastes

36
Introduction to Drilling Fluids – Part 2 5/31/2005
G. Daccord

Schlumberger Private
End of Part 2

Schlumberger Private
37 GD
5/31/2005

37
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Introduction
Part 1 – Function, properties
Part 2 – DF management on surface
Part 3 – Drilling Fluids Chemistry
Part 4 – A few downhole problems

Part 3

Schlumberger Private
Drilling Fluid Chemistry
Clays structure & properties

Schlumberger Private
Part 3 of the Introduction to Drilling Fluids by G Daccord. 20 March 2005

This part is centered on chemistry and physico chemistry. Most of this part is dedicated
to clays: this is because bentonite is a clay and it is the main component of most drilling
fluids. Clays are also at the origin of many drilling and production problems: these are
reactive or swelling clays or shales.

1
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Topics Covered

Clay physico-chemistry
– What is a clay
– Charges, cation exchange
Clays

Schlumberger Private
– Swelling clays Polymers
– Dispersion, flocculation and aggregation OBM’s – SBM’s
– Bentonite in drilling fluids Filtrate
Polymer chemistry
– Polymer types, structure and configuration
– Effect of ions
– Polymers in DF’s, pH-sensitive polymers
Oil-based muds (and SBM) chemistry
DF filtrate, chemical logging

Schlumberger Private
2 GD
5/31/2005

After a description of clays, polymers used in DF’s are briefly reviewed.

The chemistry of OBM’s is much simpler than that of WBM: it will be described in just a
couple of slides.
DF filtrate is the subject of a special slide.

2
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Clays
Silicates, Alumino-Silicates and Clays Polymers
OBM’s – SBM’s
Filtrate

Basic building block

O H
Si

Schlumberger Private
Si O Si O Si
O Negative charge + cation

3D structures
Small ions
1D structures 2D structures “tectosilicates”
“nesosilicates”
Chains and ribbons Planes or sheets • Quartz
• Sodium silicate, Na 4SiO4 “inosilicates” “phyllosilicates”
• Feldspars
• Pyroxene • Clays: micas, chlorite,

Schlumberger Private
montmorillonite, etc.
3 GD
5/31/2005

The building block of silicates is the SiO4 unit. Its structure is tetrahedric, with the Si atom in the
middle.
Each oxygen has to make two bonds: the missing bond in the tetrahedron can be either with an
hydrogen (hydroxyl group), another silicon or the oxygen can carry a negative charge that
needs to be balanced by a nearby cation. This leads to 4 groups of silicate compounds:
• All oxygen's are linked to H or have a negative charge: this is the free silicate ions that can
dimerize or polymerize in small size soluble species (“silicate muds”).
• Two oxygen's are linked to silicon atoms: this creates a silicate chain, I.e. a 1D structure
• Three oxygen's are linked to silicon atoms: we obtain a 2D layer (in Greek, phyllo = sheet,
layer)
• All four oxygen's are linked to silicon's: this is quartz.

Pictures of a 6-co-ordinated atom (Al)

and corresponding “octahedral cage”

Pictures of a 4-co-ordinated atom (Si)

and corresponding “tetrahedral cage”

3
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Clays (Montmorillonite) Structure

“Tetrahedric Si layer”
1D chain

Schlumberger Private
2D sheet

Aluminum
“Octahedric Al layer”
Hydroxide

Montmorillonite Cations and water

structure
A few Al exchanged with Mg

Schlumberger Private
A few Si exchanged with Al

4 GD
5/31/2005

Construction of montmorillonite platelets:

1. Build a 2D layer of “silicate tetrahedra: 3 out of the 4 oxygens are now correctly bound.
2. Pile up two such tetrahedric layers, with un-bound oxygens pointing one to the other.
3. Place aluminum ions in between, in the “octahedric cages” with 2 hydroxyl groups per Al. Each Al is
linked to four oxygens.
4. Replace a few Si by Al and a few octahedric Al by Mg: you obtain a “montmorillonite platelet”.
5. Compensate the remaining excess negative charges of the sandwich by interlayer hydrated cations
+ free water.
6. You obtain the cation-montmorillonite mineral.

A few other common

types of clays:

Raw formula of Na-mont.

Si8Al4-xMgxO2(OH)2 Nax

4
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

This Structure Does Exist

Schlumberger Private
Specific surface area: 800 m2/g

Face charges: pH independent

Edge charges: pH sensitive

Transmission electron micrograph of a calcium-montmorillonite mud, illustrating the formation of dense and relatively well-
ordered stacks ( quasi-crystals ) of clay lamellae. Thanks to its large lateral extension and deformability, a given lamella may

Schlumberger Private
be part of different quasi-crystals at different places. (H. Gaboriau and C. Clinard, 1991)

5 GD
5/31/2005

This TEM micrograph is taken from a Ca-montmorillonite sample, with a very small
amount of water content.

The typical size of the platelets is 1 nanometer in thickness and 1 micrometer in

extension: the specific surface area is then huge.

Besides surface charges, there are a few edge charges because the platelets are not
infinite. The sign of these charges can be reversed depending on pH and adsorbed
species: Si-OH at low pH, Si-O- at high pH.
To keep platelets dispersed, it is better to have them entirely negatively charged, so have
high pH: the pH of drilling fluids is always basic.
At the difference from edge charges, surface charges originate from atoms substitution in
the network and are pH-insensitive.

5
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Montmorillonite Sheets in Water

Key parameters:
– Binding energy of the cations with the sheets: Na + < K+ < Ca++
– Number of exchange sites / mass of clay: CEC, in meq / 100 grams

Schlumberger Private
Pure
Ca-montmorillonite

Schlumberger Private
Pure Na-montmorillonite
6 GD
5/31/2005
Mixed Na-Ca-montmorillonite

The behavior of montmorillonite minerals in water depends first of all on the binding energy
between the platelets, thus on the type of cation and the platelet charge.
It is experimentally found that sodium ions have a weak interaction energy: when dispersed
in water, a Na-montmorillonite mineral will progressively absorb quite a large amount of
water.
For cations with higher binding energy, the amount of absorbed water is much less.

The charge of platelets is measured by adsorbing methylene blue dye, this is called the
MBT “methylene blue test”, expressed in milliequivalents per 100 grams of dry matter or
in the equivalent lb/bbl of pure Na-bentonite (API).
The MB displaces weakly bound cations: this is a measurement of the cation-exchange-
capacity of the clay (CEC). Good bentonites have a CEC of at least about 80 meq/100 g
(80 millimoles). This is very variable property, depending on the amount of substituted Si
and Al in the platelet and inter-platelets cation.

Remarks:
1. The binding energy varies like the valency of the cations. Transition metals like uranium
will be strongly linked: clays act as barriers to the movement of heavy metals. This
explain why gamma ray logs correlate with the presence of shales (strong affinity with
U, and K for other reasons).
2. The possibility of cations to be replaced is at the basis of the spontaneous potential,
key log used for the detection of formation boundaries (shales act as semi permeable
barriers: cations can move between platelets but not anions). Refer to part 4.

6
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Montmorillonite Swelling

The swelling-compaction behavior is strongly dependent on the cations

Schlumberger Private
Tessier, 1991

Schlumberger Private
7 GD
5/31/2005

Sodium-montmorillonite
When dispersed in fresh water, the mineral will swell and absorb a lot of water. Upon
compaction, water is expelled almost reversibly, I.e. upon re-dispersion in water the clay
re-absorb almost all water.
Calcium-montmorillonite
After dispersion in water, the mineral absorb much less water than Na-mont. In addition, if
the suspension is compressed some water is expelled irreversibly. The higher the
compaction pressure the more irreversible the compaction.

Note that the scale on the Y-axis is not the same on both graphs.

Two important consequences:

• For DF’s: Ca-contamination is irreversible. Make sure there is no Ca (or Mg) ions in the
mix water before dispersing bentonite.
• For shale formations: load the DF filtrate with Ca to limit formation swelling and
loosening. Commonly done for OBM/SBM’s: the aqueous phase is a CaCl2 brine.

Vocabulary:
Adsorption: process by which molecules area (more or less) weakly bound to a surface.
Absorption: process by which a solvent enters the structure of another compound. The
energy gained during this process is lower than for adsorption, thus reversibility is easier.
Example: a sponge absorbs a lot a water and can free it upon drying. The same sponge
adsorbs ink (or dye) and hardly release it. The dye is more strongly bound to the solid
structure than water.

7
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Preventing Shale Swelling with Organic Molecules

Research area in SCR for years

Schlumberger Private
A. Patel, E. Stamatakis, S. Young and S. Cliffe, M-I
L.L.C., “Designing for the Future – A Review of the
Design, Development and Testing of a Novel,
Inhibitive Water-Based Drilling Fluid”, AADE-02-
DFWM-HO-33

Schlumberger Private
8 GD
5/31/2005

The regularity of montmorillonite sheets and their large aspect ratio make them ideal
structures for molecular modeling.

SCR have been working on “shale inhibitors” for years. One tool of choice for these
studies is molecular modeling: this has been applied to optimize the structure of possible
organic additives.

New DF systems are being commercialized that are based on new and more effective
shale stabilizing additives.

The molecules shown here are oligomers of propylene oxide with amine end groups

8
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Dispersion, Flocculation, Aggregation: DLVO Theory

DLVO theory combines London & electrostatic repulsion with Van der Waals attraction:
Interaction Potential

Schlumberger Private
Repulsive
Total

Attractive

Distance
Low salt content High salt content (nm)
Although too simple, it provides a first order understanding of Na-montmorillonite behavior vs. salt
content
Flocculated : weak edge-to-face links, reversible

Schlumberger Private
Dispersed: no contact between platelets
Aggregated : strong face-to-face links, irreversible
9 GD
5/31/2005

DLVO = Derjaguin, Landau, Verwey and Over. On the plots, small range Born repulsion is not
indicated.
The 3 keywords that describe bentonite-water structure are dispersion, flocculation and
aggregation; the DLVO theory provides a better explanation of the difference between flocs and
aggregates than this card-house view. They correspond to different potential wells, with a small
energy barrier for flocs and large one for aggregates.
There are 3 main means to act on the dispersion-flocculation state:
• Modify the pH, as said before to neutralize edge charges
• Modify the salt loading (NaCl): increasing the ionic strength decreases the Debye layer
thickness
• Use organic dispersants (steric effect): small size polymers with good affinity with clay
surface.
Adding divalent cations will induce irreversible aggregation, and thus a sharp decrease of viscosity
(cuttings transport): this is what occurs when the mud is contaminated with Ca brine or cement
(after drilling the shoe of previous casing). This aggregation can be prevented by pretreatment of
the WBM with excess sodium bicarbonate to precipitate any Ca and Mg free ion as calcite or
dolomite.
20 VISCOSITY (cP)

15

10 A Dry bentonite in salt solution

B Dry bentonite in calcium solution
5 A
B
0
SALT 50,000 100,000 150,000 200,000
CALCIUM 1500 3000 4500 6000
PPM 9
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Old vs. Modern Conceptual Views

Dispersed and deflocculated Aggregated and deflocculated

Schlumberger Private
Dispersed-flocculated

Edge-to-face flocculated but Hydrated-aggregated

Edge-to-edge flocculated but
dispersed dispersed

Schlumberger Private
Edge-to-face Edge-to-edge Edge-to-edge and edge-to-
flocculated and flocculated and face flocculated and
10 GD
aggregated aggregated aggregated
5/31/2005
H. van Olphen, 1963

Until about a decade ago, montmorillonite clays were believed to organize themselves in
“card-house” - like structures. This structure is primarily based on edges to faces
electrostatic interactions between platelets.

This mental picture is now abandoned, since evidences have shown that most
interactions between clay platelets are face-to face. The 3D structure is thus mainly due
to the flexibility of the individual platelets.

10
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Bentonite in Oilfield Application

Bentonite: natural industrial ore
– Based on Na-Ca-montmorillonite + impurities
– Various grades, based on its viscosification ability
• Wyoming bentonite: almost pure Na-montmorillonite

Schlumberger Private
• OCMA clay: Ca-montmorillonite
• API bentonite: minimum viscosity values, max. fluid loss volume

Basic preparation procedure (~ 60 g/L):

– Precipitate any Ca++ and Mg++ ions from water with NaHCO3
– Mechanically disperse bentonite and leave it hydrate for a few hours
– Raise the pH to 9-10 with NaOH
– Eventually, add a slight amount of Ca++

Schlumberger Private
Bentonite – water mixture is commonly called “gel”
11 GD
5/31/2005

Bentonite is not a mineral, this is an ore composed of montmorillonite and other minerals
acting as impurities.
The API has edited specs to classify the various grades of bentonites according to various
engineering properties:
. Particle size
. Viscosity and filtration properties of water-bentonite suspensions
. CEC and type of cation
Based on previous slides, one can understand the principles applied to prepare a
bentonite suspension:
1. Remove all divalent ions from the based water, by
precipitating them into carbonates
2. Mechanically disperse the dry bentonite to speed-up its
hydration
3. Wait enough time to allow water molecules to swell the
platelets piles
4. Neutralize edge positive charges by raising the pH
5. Eventually, a slight amount of calcium ions can be added
to raise the yield point
In the oilfield slang, a bentonite-water suspension is called “gel”; drilling fluid systems
based on that are “gel muds”. By extension, dry bentonite itself is sometimes called
gel: this is reflected in the various trade names.

11
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Organo-Clays, Polymer Adsorption

12 to 18 C
Exchange the Na+ ion with an aliphatic amine R-NH3+
– The montmorillonite particles become hydrophobic
– They can be used to viscosify oil-based fluids

Schlumberger Private
Commonly used in water treatment
plants to remove oily compounds

The adsorbed species can also be

polymers, of varying chain length

Schlumberger Private
12 GD
5/31/2005

Transition to the “Polymers in DF’s” sub-part.

We saw that atomic cations can adsorb on montmorillonite faces (sodium, potassium,
calcium, etc.) Organic molecules when they have charges (or can create weak hydrogen
bonds) can also adsorb; these are either surfactants or polymers.

To cover the whole surface, the surfactant must be cationic (positively charged): the clay
platelet become hydrophobic. These materials are called organoclays; they are used in
oil-based drilling fluids.

Negatively charged polymers can neutralize edge positive charges and act either as
dispersants – when they are linked to a single sheet – or as flocculants when they bridge
many sheets together.

Positively charged polymers are very efficient shale stabilizers, but their HSE
performance is generally poor: they are thus seldom used in oilfield applications.

References on clay structures and bentonite-water suspensions:

• M-I engineering manual, chapter 4
• H. van Olphen, An introduction to Clay Colloid Chemistry, John Wiley & Sons
Ed., 1977

12
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Clays
Polymers in Drilling Fluids Polymers
OBM’s – SBM’s
Filtrate

A polymer is made of many similar unit blocks (monomers) linked together

A polymer is described by:

Schlumberger Private
– The number of different monomers: 1 = homopolymer, 2+ = random or segmented arrangements
– The chemistry of each monomer: polarity, charge and effect of pH, reactivity
– The total number of monomer per chain (degree of polymerization, molecular weight)
– Linear, ramified, cross-linked chains
– The conformation of polymer chains in the liquid phase: coil to extended chain
– Its interactions with other components, in particular solid surfaces

This gives the polymer solution its properties that are strongly dependent on
– Liquid physico-chemistry: polarity, presence and valence of ions
– Physical parameters: temperature, shear, elongational flow

Schlumberger Private
To obtain key fluid functions: rheology, fluid loss, shale stability & dispersion, lubricity
13 GD
5/31/2005

Quick summary of what polymers are:

• Definition
• Characterization
• Sensitivity to chemical and physical environment

The three pictures show a coil, an extended flexible chain (e.g. PHPA in low salt water)
and a rigid polymer (xanthan)

13
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Polymers in DF’s: Classification

- CH2 - CH - CH2 - CH - CH2 - CH- CH2 – CH -
I I I I

n Origin C =O
I
C =O
I I
C=O C =O
I

– Synthetic: based on acrylamide-acrylic acid -> PHPA

NH2 O- NH2 NH2

– Natural: polysaccharides -> xanthan, starch CH2 OH

– Modified natural polymers: CMC, HEC, lignosulfonates, etc.

Schlumberger Private
O
O H

n Anionic, neutral, cationic HO

I
I
I
I

n By function
I I
H OH

– Thickeners long chain, good solubility in the liquid

– Dispersants short chains, reactivity with solid particles - CH2 - CH - O -

– Fluid loss control agents block permeability of filter cakes

– Shale encapsulation long chains, reactivity with shales - CH - CH2 – O -
|
CH3

Schlumberger Private
14 GD
5/31/2005

Because of cost reasons, most polymers used in DF’s are either natural or derived from
natural polymers:
• From the wood industry, cellulose: hydroxyethyl-cellulose (HEC), carboxymethyl
cellulose (CMC); lignosulfonates are by-products from the paper industry.
• Xanthan is produced by bacteria.
• Starch is produced from various vegetables (e.g. potatoes).
Synthetic polymers are (relatively) expensive, with two origins:
• Based on acrylic backbone: numerous products are available, mainly used as
shale stabilizers. They vary by the chain length and percentage of carboxylic
groups.
• Based on so-called “glycols”: these are small mass polymers used for shale
stability.
Only neutral or anionic polymer are used in DF’s. Cationic polymers are almost never
used (except in very limited cases).
Their functions are numerous, covering all major properties of DF’s except density.

The four pictures show the structure of a PHPA, glucose as the elementary unit of
polysaccharides, polyethylene glycol (PEG or PEO) and polypropylene glycol.

14
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Polymers in DF’s: Charges, Effect of Ions and pH

- -
Low ionic content, strong electrostatic repulsion
Fresh water

Schlumberger Private
- - - -

High ionic content, screened electrostatic repulsion Salt water

Low pH Divalent cations

- -
Ca++ Ca++
OH OH - -
Sea water

Schlumberger Private
or cement contamination
15 GD
5/31/2005

A charged polymer in an aqueous solution. Its behavior is similar to what happens with
montmorillonite clays:
• In deionized water or fresh water, electrostatic repulsions are maximum, chains
are elongated, fluid viscosity is high.
• In salt water (high NaCl content), coulombic interactions are screened, chains
are shrunk and fluid viscosity is reduced.
• In presence of divalent ions, calcium or magnesium, internal or inter-chains
crosslinks are formed, which reduce both the fluid viscosity and polymer solubility.
• At low pH, reactive groups are protonated, with a strong decrease of polymer
solubility.

15
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

WBM’s Types and Composition - Summary

Bentonite-based and milling Shale Stability, polymer Other types

fluids based – Silicates
– Fresh water – KCl + PHPA (synergetic – Aphrons

Schlumberger Private
– Bentonite effect) – Reservoir DF
– Organic dispersant – “Glycol”: wide variety, (Drill-In Fluids)
– Barite proprietary structure
– Polymeric fluid loss agent Old systems
– Polymeric viscosifier: – UltraDrill – Gypsum muds
xanthan

– Mixed Metal Hydroxide

(MMH)

Schlumberger Private
16 GD
5/31/2005

Quick summary look at the main types of water-based muds and their main components

• Bentonite WBM’s.
MMH muds are special fluids very yield point and almost zero PV. Sometimes designated
as “flat rheology”. Used for window milling because they have very good solids carrying
properties. The MMH additive is a kind or sub-microscopic clay-like synthetic compound
that strongly interacts with bentonite platelets. On a concept point of view, not very
different from flocculants used in water treatment plants.

• Polymer WBM: there is no bentonite otherwise it would adsorb all encapsulating

polymers. PHPA is used in conjunction with KCl, since they have a synergetic effect on
shale stability, not well understood. A “glycol” is the usual third shale inhibitor used in
these fluids.

• Silicates muds are used for their shale stability properties, but they are fundamentally
different from polymer muds.

• Aphrons are low-density DF’s, with good filtration properties. The reason behind the
observed benefit of the presence of the micro gas bubbles is not well understood.

• RDF is used by M-I Swaco, other companies used the term “drill-in fluids”.

16
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Clays
Oil / Synthetic-Based DFs Chemistry Polymers
OBM’s – SBM’s
Filtrate

Bentonite WBM
n Why using OBM-SBM? Inhibitive WBM
Shale Inhibition

Schlumberger Private
OBM
Specific properties
Cost Formation Protection
SBM

Lubricity Thermal Stability

n Composition
Types of OBM’s
Tolerance to
n Contaminants
Corrosion Inhibition

Overall Drilling
Environmental Footprint
Performance

Schlumberger Private
17 GD
5/31/2005

The main reason for using OBM’s is drilling efficiency in difficult formations i.e. mainly
reactive clays.
This objective is primarily reached by not allowing water to contact the formation.

The other positive properties of OBM’s should be considered as additional advantages

rather than critical ones. In other words, without shale inhibition properties, OBM’s would
not exist. A good proof of that is the continuous effort to develop new WBM’s as inhibitive
as OBM’s: the UltraDrill system is as expensive as low cost OBM’s

17
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

OBM-SBM Composition
– Oil phase
• Synthetic compounds: paraffins, olefins, esters
Cost • Low-Toxicity mineral oil (LTMO): many grades available, depending on the amount of aromatics

Schlumberger Private
• Diesel: cheap, bad environmental properties
– Aqueous phase
• CaCl 2 brine: provides shale stability & filtration control, decreases cost, improves HSE
– Organoclay or oil-soluble polymer for viscosity control
– Surfactant package
• Emulsifier + wetting agent for fluid stability (+ lime)
– Weighting agent
• Barite

Schlumberger Private
– Cuttings and other contaminants
18 GD
5/31/2005

Summary of OBM/SBM components:

• The oil phase dictates the cost of the fluid: the higher the oil cost, the more
environmentally compatible.
• Diesel is the worse oil: toxic, low biodegradability (it contains a lot of aromatics).
• Refined oils are more costly; the degree of refining, i.e. the residual amount of
aromatic compounds sets the product cost.
• The alternative way of producing oils is first to crack petroleum into monomers
(e.g. ethylene) followed by controlled polymerization: very pure compounds are
manufactured.
• The aqueous phase has two main purposes, (1) gives filtration properties without (2)
destroying shale stability. This is provided by the surfactant package that actually prevents
direct contact of aqueous droplets with the formation. In addition, because water has a
finite solubility in oil, the chemical potential of the water phase in the OBM is adjusted to
that of the water phase in the shale.
• Viscosity may be increased by the use of organoclays.
• The surfactant package has two major functions (1) ensure water-in-oil emulsion stability
(emulsifying properties) + (2) ensure proper dispersion of solids (wetting properties).
It commonly comprises a minimum of 2 compounds, often 3, and requires the presence of
lime (calcium hydroxide) for optimum performance.
• Weighting agent.
• Without forgetting the usual contaminants!
Note that an excess of surfactant is required to immediately coat cuttings as soon as they are
drilled: these chemicals are lost on surface, when these solids are separated.

18
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

pH Sensitive OBM’s – Reservoir

Drilling OBM’s
One of the main drawback of OBM’s is the difficulty of cleaning them
once drilling is completed

Schlumberger Private
M-I Swaco developed the FazePro system in which the emulsifier is
pH-sensitive: it stabilizes water-in-oil emulsions at high pH and oil-in-
water emulsions at low pH

Oi
l Oi
l

Schlumberger Private
Water Water
19 GD
5/31/2005

What makes an emulsifier to stabilize an W/O emulsion or an O/W emulsion?

It is just the relative size of its polar head vs. its hydrophobic tail:
• Large head, small tail: the interface curvature favors oil-in water.
• Large tail, small head: the interface curvature favors water in oil.

The pH sensitivity is achieved by using an ammonium head. The pH change is performed

once the casing or completion string is in place, using an acid wash (HCl).

Reference: Ravitz et al., “Active filter cake technology eliminating the need for post
completion cleanup, SPE 94726.

19
Introduction to Drilling Fluids – Part 3 5/31/2005
G Daccord

Clays
Drilling Fluid Filtrate Polymers
OBM’s – SBM’s
LWD by Chemical Logging Filtrate

One signature of the formation being drilled lies in the mud filtrate:
– Ions in the formation brine
– Soluble formations

Schlumberger Private
– Reactive clays

1992: mud out vs. mud in

2005: lab on a chip?

Schlumberger Private
C. Hall et al., “Mud Analysis and Control for Drilling”, 1992
20 GD
5/31/2005

The idea of analyzing the formation being drilled by its chemical interactions with the drilling fluid was
studied at the beginning of the 90’s in SCR, as part of an EU funded project.
At the time, only surface measurements were feasible: however, clear signatures of the formation being
drilled were visible despite the spreading of the peaks due to dispersion and diffusion in the flow up the
annulus until surface.
Three types of interactions are possible:
• The brine that saturates the rock is diluted in the mud as soon as it is cut at the bit.
• Soluble formations – like anhydride – directly affect the aqueous phase ionic composition.
• Clays with exchangeable cations interact with the drilling fluid: they preferentially adsorb
potassium and release sodium.
In addition, it was experimentally observed that the relative abundance of cations is correlated with the
drilling of sandstone of carbonates.
Practically, these interactions are detected by making the difference in the chemical composition of the
mud pumped in and mud exiting the hole. The same type of measurement could be done in the BHA
using microfluidic systems: its only the difference in composition that matters!
References:
1. T. G. J. Jones, T. L. Hughes and P. Tomkins, “The ion content and mineralogy of a North Sea
Cretaceous shale formation”, Clay Minerals, 24, 393-410 (1989).
2. T. L. Hughes, T. G. J. Jones and T. Geehan, “The chemical logging of drilling fluids”, paper
SPE 23076 (1991).
3. C. Hall, P. Fletcher, T. L. Hughes, T. G. J. Jones, G. C. Maitland and T. Geehan, “Mud analysis
and control for drilling”, paper presented at the 4th EC Symposium “Oil and Gas in a Wider
Europe” meeting, Berlin, 1992.
4. C. Hall and T. L. Hughes, “Ion chromatography tracer experiments during drilling”, paper SPE
25178 (1993).
5. T. L. Hughes, T. G. L. Jones, T. Geehan and P. G. Tomkins, “Rigsite ions monitoring system
for drilling fluids”, paper SPE 25703 (1993).

20
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Introduction
Part 1 – Function, properties
Part 2 – DF management on surface
Part 3 – DF chemistry
Part 4 – A few downhole problems

Part 4

Schlumberger Private
Drilling Fluid in the Hole – A Few Problems
“Drilling Engineering”, D&M and M-I Swaco
Well bore stability
Fluid-fluid displacement Impact of mud filtration on
Hole cleaning formation logging
Differential sticking

Schlumberger Private
Filtration

Part 4 of the Introduction to Drilling Fluids by G Daccord. 20 January 2005

This 4 th part aims at bridging the gap between mud company activities and SLB activities. We
will review the behavior of drilling fluids downhole.

• In part 1, we introduced the various functions of drilling fluids, that are translated into
requirements for the fluid properties

• In Part 2, we saw how to adjust the DF properties to the target values.

• Part 3 was focused on the chemistry of DF’s, with a large importance given to clays.

• In the present part, we will go over a few of the methods used to specify the target
values for the DF properties, I.e. the quantitative relationship between function and
properties

This is the boundary domain between DF engineering and drilling engineering, I.e. between
D&M and M-I Swaco.
The part ends with a review of the impact of drilling fluids on formation evaluation tools and
logs.

1
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

DF Calculations Usually done by the Mud Engineer

Mud properties, especially rheology

and density, vary with depth
• Pressure

Schlumberger Private
• Temperature

This impacts all functions of the DF

More complex models:

n SideKick
n Hole stability

Schlumberger Private
2 GD
5/31/2005

Besides his key task of maintaining mud properties as per specs, the DF engineer is also capable of making a
number of basic or advanced calculations, thanks to dedicated models and software.
Several of these calculations are also done by the driller or D&M engineer. Potential compatibility issues: in
SLB, the PowerPlan module of Drilling Office was developed with the need of being compatibility with M-I
series of software. They are listed here.
The M-I software modules all use a central database of DF properties, the “Virtual Hydraulics” database. This
database is built using either default mud system properties or data generated at the rig site using a Fann 70
rheometer (HPHT model).
. TPVOL: trip tank volume. Variation of mud volume when the DF comes out of the hole (RIH) or is pumped
into the hole (POOH). This is useful to interpret pit gains as early signal of a kick or just fluid expansion.
. HYPLAN: planning of drilling hydraulics for optimization.

VIRTUAL HYDRAULICS® is a proprietary integrated suite of programs to evaluate and design critical-well drilling hydraulics under
simulated downhole conditions. It is most often used in the following applications.
• ECD, ESD, temperature, hole-cleaning and tripping profiles in critical wells
• Hydraulics and rheological behavior of synthetic-, oil- and water-base drilling fluids in extreme temperatures and/or pressure
environments such as deepwater and HTHP drilling
VIRTUAL HYDRAULICS is a powerful tool for maximizing drilling fluid performance, minimizing overall costs, and improving confidence
levels while using high-performance fluids in challenging deepwater and HTHP environments. The integrated software suite uses state-
of-the-art models for hydraulics, mud rheology, temperature profiles, hole-cleaning performance, and surge/swab pressures that
consider the dramatic effects of pressure and temperature on downhole fluid properties.
• VIRTUAL RHEOLOGY ® uses an innovative “data-cube” concept to predict mud rheological properties under downhole conditions.
• VIRTUAL RDH™ considers the effects of downhole density and mud rheological profiles, pipe rotation, eccentricity and cuttings
behavior to accurately calculate pump pressure, ECD, ESD and hole-cleaning profiles during drilling.
• TPRO™ uses a fully transient temperature simulator to determine the downhole temperature profile under circulating and static
conditions.
• DPRO™ accurately determines equivalent static density profiles based on temperature, pressure and specific mud characteristics.
• TRIPPRO™ executes transient surge and swab analyses with effects of down hole density, rheology and time to determine optimum
tripping schedules while running pipe or casing.
• CLEANPRO™ determines hole-cleaning profiles using fuzzy logic principles that consider the effects of rotation, eccentricity and
downhole fluid properties.

All major Drilling Fluid companies have similar calculations capabilities.

2
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Schlumberger Private

Schlumberger Private
3 GD
5/31/2005
D&M PowerPlan (part of Drilling Office) software has several identical capabilities

Marketing view of a few screen displays.

The objective here is for the driller to have all important information on the DF on a
single screen, in a visual representation to better prevent drilling problems.

Again, this is possible only thanks to a detailed characterization of the P&T dependence
of DF rheology.

M-I also have a real-time pressure interpretation program, PRESSPRO-RT. It is

somehow redundant with Drilling Office and BHA measurements, with the difference that
it does not stop showing data when the mud pumps are stopped!
The fluid rheology may be periodically fitted to measured data.

All these hydraulic calculations are more or less standard, what differs is the interface
and its ergonomics.

Three important fluid mechanics problems are further described on next slides: hole
cleaning, fluid displacement and filtration + two other non-fluids mechanics problems.
One common limitation of these models is to properly account for the complexity of the
situation – e.g. eccentered and rotating pipe - and very few quantifying measurements.

3
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Wellbore Stability

Schlumberger Private

Schlumberger Private
4 GD
5/31/2005

Wellbore Stability commonly covers two topics, wellbore stability while drilling and during
production (sanding). Here, we only consider the first topic.

The basic mechanism of wellbore instability is when the stresses are higher than the rock
strength. The stresses around a wellbore come from the interaction from “far field
stresses”, i.e. stresses that exist before the well is drilled and stresses added by the
wellbore itself and the fluid filling it.

Thus, the primary parameters that influence the stress state include:
• The far field stress: in “relaxed” areas, the vertical stress is higher than both horizontal
principal stresses. In tectonically stressed places, horizontal stresses may overpass the
vertical stress.
• The inclination of the well.
• The hydrostatic pressure exerted by the wellbore fluid.

The two broad categories of failures are either shear failures or tensile failures. The rock
may fail in one or both categories depending on the stress state.

4
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Failure Modes

Large mounts “Mud losses”

of “cavings”

Schlumberger Private
DANGER RISKY SAFE
TOO LOW TOO HIGH

MUD WEIGHT
Pp Sh
Note: “sanding” is not considered here, this is a production problem Stable
References:
• T. Bratton, T. Bornemann, Q. Li, R. Plumb, J. Rasmus and H. Krabbe, “Logging- Unstable
while-drilling images for geomechanical, geological and petrophysical
interpretations”, SPWLA (1999).
• “Mechanical wellbore stability”, presentation by R. Plumb, 1996. IPM Drilling

Schlumberger Private
Engineering web pages: http://www.hub.slb.com/index.cfm?id=id18271

5 GD
5/31/2005

For a vertical well drilled in a stress-relaxed area, the three stresses – axial,
radial and tangential – vary with the mud density as shown on the top-right plot.
Comparison of these stresses with the rock strength allows plotting a stability
diagram (Bottom-right): if the delta stability parameter is negative, the rock
may fail. This plot allows predicting the safe mud density range.

In general, too low mud density leads to shear failure, whose symptoms are
as follows:
• Hole elongation in direction of S2;
• Heavy Reaming, high torque and drag;
• High volume of solids/cavings;
The easier control means is to increase the mud density. Stable
The image on the right side is a Resistivity-at-the-bit log, showing breakouts
on the top and bottom side of the hole. Unstable

A too high mud density create tensile fractures, similar to hydraulic fractures. Symptoms include:
• Sudden mud losses;
• Mud wt vs. loss similar across field;
• Induced fractures aligned with S1;
Curative means include:
• Reducing the mud density;
• Minimizing all dynamic pressure: P surges while running-in-hole, frictions in the annulus.

Finally, whenever possible, it is better to design the well trajectory to minimize these risks.

5
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

The addition of real-time fast

formation shear from
sonicVISION data enables
decisions affecting wellbore
stability or completion design
to be made as the well is
drilled, not after they become
problems.

Schlumberger Private
Optimal mud weight

Schlumberger Private
window is computed
from real-time
sonicVISION log
6 GD
5/31/2005 information.

Two pictures extracted from the sonicVISION brochure, to highlight the importance of
mud weight management for the driller.
These real-time predictions are based on the interpretation of sonic + neutron logs made
while drilling

Ref.: Brehm and Ward, “Pre-drill planning saves money”, E&P May 2005, pp. 81-83.

Remark: the drilling process may improve the rock mechanical properties as in casing
drilling. This is called a “plastering effect”. Practically, it has been observed that the safe
mud density window is widened by as much as 1 to 2 lbm/gal. No good explanation for
this effect is available yet.

6
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Fluid-Fluid Displacement

Mud-to-mud Physics
– While drilling a section – Mixing & displacement in a
Mud-to-cement cylindrical pipe

Schlumberger Private
– After running casing – Mixing & displacement in an
inclined non-uniform annulus
Mud-to-completion fluid – Unstable flows
– Before completing a well – Non-Newtonian rheologies
– Wetting effects
Objectives
– Minimize mixing zones Common solution
– Does not leave mud films – Turbulent flow to try achieving
on walls 1-D flow

Schlumberger Private
7 GD
5/31/2005

Fluid-fluid displacement is a fluid mechanics domain in which practices are based more
on experience than on validated model predictions.

The most advanced understanding is for well cementing, simply because the flow
geometry can be assumed to be 2-D (refer to the ICD* Schlumberger service). This is not
possible for the other applications.

M-I have developed a module, X-Clean, based on lab experiments and fuzzy logics to
help predict cleaning efficiency during mud-to-completion fluid displacement.

Whenever possible, the best solution is to achieve turbulent flow: the mixing zone is much
wider than for an ideal piston-like displacement but much smaller than under unfavorable
laminar conditions for which viscous fingering occurs.
Many phenomena are still research areas, e.g. the tangential erosion or turbulent cleaning
mechanisms.

ICD = Integrated Cement Design

7
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Hole Cleaning Predictions and Prevention

Complex set of phenomena, no satisfactory full model

available yet.
Combination of:

Schlumberger Private
– Solids transport
– Solids pickup, from solids bed
– Multiphase flow
– Moving boundaries
– Non-Newtonian fluid rheologies
– Laminar and turbulent flow regimes

Sedco-Forex Driller’s Stuck Pipe Handbook:

https://www.cambridge.scr.slb.com/~barrow/stuck_pipe/spade/version_4_4/handbook/handbook.html#Contents

Schlumberger Private
8 GD
5/31/2005

A few additional precisions on an important problem, hole cleaning or cuttings transport.

Although this sounds like a fluids dynamics problems, no satisfactory model is still
available despite numerous attempts.
Practically, the driller uses his experience: pipe rotation, fluid velocity and viscous
sweeps.

A key feature of cuttings transport and barite sag is their partial irreversibility: if solids start
to settle at given conditions, much more energy is required to put them back in
suspension. Prevention is far better than cure.

Note that the use of steerable rotary drilling techniques has been very helpful: it is agreed
that one of the most useful means of keeping the hole clean is to prevent cutting from
settling, which is nicely achieved if the drill string does not stop rotating. This used to be
impossible with traditional directional drilling based on alternatively sliding-rotating.

Special drill pipe are available that help clean the hole.
Weatherford propose Hydroclean DP’s: “The patented Hydroclean profile is a combination
of specially designed angles that work in harmony to lift cuttings off the wall and propel
them up the hole, providing a significant improvement in overall hydraulic performance”
(SPE 59143)

8
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Hole Cleaning / Stuck Pipe Prevention – Current Approaches

Combination of surface measurements of cuttings flux + downhole while-
drilling measurements + models
Thonhauser et al., “Rigsite Measurement of Cuttings
S. Jardine, D. McCann and D. White, “Method of Weight Equipment: Method to Analyze the Data and
warning of pipe sticking during drilling Extended-Reach Field Test”, SPE 56561 (1999)

Schlumberger Private
operations”, US 5,454,436 (1995)

SPP = stand pipe pressure

TOR = torque

Schlumberger Private
9 GD
5/31/2005

As a consequence of facts shown on previous slides, current approaches are based on the
integration of rig-site measurements and real-time interpretation. The practical objective is
to automatically determine risky situations before problems become issues.
• Within D&M, the method patented by Jardine et al. is being implemented.
• Application of Thonhauser thesis was tested in a couple of wells: cuttings separation rate
on the shakers is monitored and compared with model data.
• Leising and Walton suggested to use Velocity / Sqrt(diameter) rather than annular velocity
to compare cutting transport in turbulent flow.

A few recent references:

L.J. Leising, I.C. Walton, “Cuttings-Transport Problems and Solutions in Coiled-Tubing Drilling”,
SPE Drilling & Completion, 17 (1) March 2002 (SPE 77261)
M. Zamora, S. Roy, “The Top 10 Reasons to Rethink Hydraulics and Rheology, SPE 62731
G. Thonhauser, K.h K. Millheim, A. L. Martins, “Cuttings Flux Measurement and Analysis for
Extended-Reach Wells”, SPE/IADC 52793
G. Thonhauser, E. Maidla, P. O'Leary, K. Millheim, “Rigsite Measurement of Cuttings Weight
Equipment: Method to Analyze the Data and Extended-Reach Field Test”, SPE 56561
S. Jardine, D. McCann and D. White, “Method of warning of pipe sticking during drilling
operations”, US 5,454,436, 3 Oct. 1995.
I. Rezmer-Cooper, “Method for detecting stuck pipe or poor hole cleaning”, US 6,401,838, 11 Jun.
2002.

9
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

The hole is not filled with an homogeneous nice fluid …

Filtration & Mud Cake
Gelled Mud, and Solids Beds

Layer of gelled mud

immobile on
impermeable surfaces

Schlumberger Private
Mud channel
on narrow sides
Gelled mud pocket in
washouts Mud cake
Barite layer or cuttings
deposited on
bed on low side permeable layers

Schlumberger Private
Mud Gelled Mud Mud Cake
10 GD
5/31/2005
0 10 100 1000 Shear strength (Pa)

A third FM problem, which we detail some more because of its large impact on SLB
business, is mud filtration and formation invasion.
Put in a broader picture, the well is filled with circulating mud, immobile mud (gelled),
solids deposits (settled barite or cuttings) and partially dehydrated mud (filter cake).
These immobile phases are located in different places in the well, and have different
potential consequences on the drilling process:
. Gelled mud: bad cement jobs and hydraulic isolation
. Settled solids: high drag forces
. Mud cake: risk of differential sticking and high ECD

Going from circulating mud to gelled mud and mud cake, one of the main difference
is the shear strength of the medium: one order of magnitude between each of them.

10
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Differential Sticking

Schlumberger Private
SLB Oilfield Glossary
Differential sticking. These cross-sectional views show a drill collar
embedded in mudcake and pinned to the borehole wall by the
pressure differential between the drilling mud and the formation.
As time passes, if the drillstring remains stationary, the area of
contact can increase (right) making it more difficult to free the

Schlumberger Private
drillstring.

11 GD
5/31/2005

Directly linked to these static beds is the problem of differential sticking.

It may happen in front of permeable formation, when a static mud cake grows around a
static object.
A differential pressure builds up between the side of the object that remains in contact
with the fluid and the side that is embedded in the cake. This differential pressure pushes
the object deeper into the cake.

11
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Force Required to Un-stick a Piece of Drill Pipe

Basic model:
Assume the only force needed is that required to break the static

Schlumberger Private
mud cake
Axial force / unit length = πD × Yield strength

Drilling fluid 5 in drill pipe half embedded in static cake

10 m thick formation
cake yield strength = 1000 Pa
Axial force = 4000 N
Static mud cake
Can happen for drill string, logging tool, logging cable, casing

Schlumberger Private
12 GD
5/31/2005

The simplest means to get a feeling of the force required to un-stick a stuck object is to
consider that we have to overcome the yield strength of the cake.

The axial force is thus equal to the yield strength X surface area. In this example, we
obtain 400 daN, I.e. the same order of magnitude as the pipe weight.

More sophisticated models can be derived, but key input parameters are the cake yield
strength or equivalent property (friction, etc.) and the embedded surface area.
A comparison between OBM’s and WBM’s tells that:
• The yield strength of WBM cake is about 1 order of magnitude higher than that of
OBM’s.
• The cake thickness of WBM’s is much higher than that of OBM’s.
• The friction coefficient (or adhesion force) between steel and WBM cake is
higher than between steel and OBM cake.
These three facts highlight the fact that differential sticking is a bigger problem when
drilling with WBM’s than with OBM’s.

Finally, differential sticking may occur whenever there is a static object in a reservoir
zone, for instance an MDT tool in operation. This is a clear advantage of the XPT if the
only measurement is reservoir pressure!

A chemical method to release a stuck pipe is to place a chemical in front of the stuck
zone, which will shrink the mud cake and decrease the cake-pipe adhesion.

12
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Drilling Fluid Filtration and Formation Invasion

After successful cementing

Casing Formation
While drilling

Wellbore Formation

Schlumberger Private
Invasion
depth

Permeable Cement Dynamic

layer Sheath mud cake
Drilling
fluid Formation
fluids
Static Dynamic Mud Mud

Schlumberger Private
mud solids filtrate
mud
13 GD
5/31/2005
cake cake

This slide shows a simple explanation of the various zones from the wellbore to the
formation, when filtration occurs:
. Circulating mud
. Fluffy static cake, that is eroded when circulation resumes
. Dynamic cake, strong enough to withstand the erosion of the flowing mud. It can only be
removed by mechanical means, e.g. scratching.
. A zone invaded by solids, often very narrow if any.
. The filtrate-invaded zone
. Finally the intact formation

After a successful cement job, only the static cake has disappeared. The materials
between the casing and the native formation are the cement sheath, dynamic mud cake,
filtrate-invaded zone.

When logging cased formations, these are the various zones that you have to account for
in the data treatment.
In a few open-hole tools, the pad that makes measurements is designed to scrap the mud
cake: FMI for instance. The mud cake immediately re-forms itself once the mud is in
contact with the formation.

13
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Filtration and Mud Cakes

External cake Internal cake and filtrate

– Limits filtration – Shallow penetration of fine solids,
but
cannot be scratched
– Generates drilling problems: stuck pipe

Schlumberger Private
– Cannot by removed by hydrodynamics alone – Time dependent penetration of liquid
phase: ~ 1 µm/s
– Acts as a “check valve”,
low FIP*
– The filtrate carries with it soluble
compounds:
– Re-forms quickly
when scratched salt, polymers, surfactants →
“formation damage”
* Flow Initiation Pressure

Schlumberger Private
14 GD
5/31/2005

Most of the knowledge about mud cakes has been acquired in SCR: the information in the
following slides is taken from the studies run there in the last 20 years.

Types of possible formation damage:

• Change of water saturation -> “water block”
• Change of rock wettability -> lower production
• Hydration of water sensitive clay minerals that swell -> mechanical blockage of
pores
• Invasion by solid particle -> mechanical blockage
• Incompatibility with oil in place: sludges
• Etc.

14
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

External Filter Cakes are not Inert

n Depend primarily on mud type
– Bentonite muds
– Polymer muds or Reservoir drilling fluid
– Invert emulsion muds

Schlumberger Private
External filter cake deposited by a properly formulated reservoir
n Dynamic deposition – drilling fluid (RDF) (extracted from Ali et al. 2001).

erosion mechanisms not fully understood: “irreversible particle attachment”

n Filter cakes can shrink or swell depending on changes of P or fluid chemistry
n Filter cakes are
strongly non-uniform
“Fluffy” cake

Influenced by

Schlumberger Private
adhesion on rock
15 GD Cerasi, 2000
5/31/2005

Mud cakes have very low permeabilities. The filtrate velocity in the formation is of the
order of a few mm/hour!
Mud cakes are not inert: they react to changes in the chemistry of the surrounding. This is
a relatively slow process but time scales are of the order of hours.

15
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Internal Mud Cake – Reservoir Drilling Fluids

Schlumberger Private
Invasion of mud solids on Ketton limestone cores. RDF’s designed so that:
– Left: extra fine CaCO3; – No internal cake is formed
– Right: coarse CaCO3. – The external cake can be easily

Schlumberger Private
Limestone grain size ~ 0.5 mm (extracted from destroyed or lifted off when needed.
Bailey et al., 1999).
16 GD
5/31/2005

These are two self-explaining pictures showing how solids can invade the porous medium
if the ratio between pore size and solid size is high enough.

Note that the internal mud cake cannot be removed while the external cake can eventuall
be “pealed away”

16
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Internal Mud Cake – OBM and Bentonite Mud

Schlumberger Private
Conceptual picture of filtration of emulsions containing bridging Internal cake obtained with an unweighted HP/HT water based
solids (taken from Al-Riyamy & Sharma, 2002). mud. (taken from Argillier et al., 1999).

Schlumberger Private
17 GD
5/31/2005

OBM’s and SBM’s have a specific filtration control mechanism. The low permeability of
the filter cake is achieved thanks to the brine droplets that block pores between solid
particles: once created, the cake is almost impermeable.

Some filtrate must invade the formation, to form the filter cake: this is called the spurt loss
or spurt volume.
The oil filtrate carries with it a substantial amount of surfactant, that can have a very
detrimental effect on the porous medium: wettability change, emulsions, etc.

17
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Impact of Mud Filtration on

SLB Services & Operations
Well Services - Cementing & Gravel-packing
n Zone isolation, cement-rock adhesion, cement Logs (IBC)
n Skin effect, open-hole GP permeability

Schlumberger Private
n Formation damage, reservoir skin: clay swelling, internal cake, wettability changes, emulsions,
etc.
D&M, IPM : Drilling Efficiency
n Stuck pipe by differential sticking
n Lubricity: WOB, Drag
Formation & Reservoir Evaluation - D&M, Wireline How many measurements are
n LWD not affected by DF filtration?
n Gamma-Ray, Resistivity, NMR logs, nuclear logs (barite, chloride), etc.
n MDT

Schlumberger Private
n Imaging tools
18 GD
5/31/2005

This is a list of SLB operations and services directly impacted by mud filtration and the
associated problems.

The industry does not have solutions for all problems:

• Zone isolation remains number 1 issue in cementing
• Skin and gravel pack (GP) damage is one of the main thread of sand control
operations.
• Formation damage is of major concern for customers

• Stuck pipe is one of the major causes of lost time for D&M

• Only a few formation evaluation measurements are insensitive to the DF and the
filtrate.

18
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Logging of Mud Cakes (External)

No direct method available to know the state and SPE 84560

properties of mud cakes
n Cake thickness = Caliper size – bit size

Schlumberger Private
n Mud cakes are a nuisance UBI log
for most logs
… except for fluid loss rate
(Haberman et al., 1992)

Traces of logging tool

centralizers through
the mud cake

Schlumberger Private
19 GD
5/31/2005

It is only in a few instances that the mud cake can be directly observed, for instance on
caliper logs.
Note that scratching the dynamic cake will lead to an instantaneous increase of filtration
rate until a new cake is created. The invasion depth increases.

19
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Formation Invasion

Wellbore Formation
Invasion
depth

Schlumberger Private
Drilling
Assumed profile
fluid Formation
fluids
Static Dynamic Mud Mud
mud solids filtrate
mud
cake cake

Schlumberger Private
O. & L. Serra
20 GD
5/31/2005

The mud filtrate does not push the formation piston-like: there is a gradual change in
saturations in the radial direction.
In addition, viscous fingering and reservoir heterogeneity induce axial variations.

In most practical applications, the saturation is assumed to show a step change between
the invaded zone and the intact formation except for a limited number of interpretation
algorithms for which more complex profiles can be accounted for (e.g. resistivity/induction
logs).

20
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Filtrate Invasion Does Exist!

Schlumberger Private
Simulation of fluid flow in the formation during MDT operation
• Filtrate must be withdrawn before a representative sample
of formation fluid is taken
• The mud cake prevents influx from wellbore fluid, above
and below the packers
SPE 71569

Schlumberger Private
Change in resistivity log vs. time
21 GD Oilfield Review, Winter 1998
5/31/2005
230 mm

A couple of examples of formation invasion in D&M and W&T operations:

. Variation of invasion depth vs. time, determined by LWD. The invasion depth is about 23
cm, which tends to indicate that the time between recording the two traces was a few
days (true?)

. Simulation of fluid flow during MDT drawdown phase.

Due to both vertical permeability << horizontal perm and very low one-way permeability of
the mud cake, a good sample of formation fluid can be taken once the filtrate has been
swept.

21
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Mud Cake and Filtrate Effects on Formation Evaluation

Measurements

Open-hole acoustic: little effect

Natural γ-ray, spectrometry: especially for KCl muds

Schlumberger Private
Spontaneous / electro kinetic potential: change of salinity between filtrate and connate water
Resistivity / induction: change in saturation + salinity
Neutron - γ-ray
Neutron - neutron Refer to J. Hemingway’s presentation (2 March 2005)
NMR: change in saturation and viscosity
Seismic: no effect

More info: refer to SRPC interpretation specialists or https://elc.melun.eur.slb.com/onlinetraining/wireline/toc-body.htm

Schlumberger Private
22 GD
5/31/2005

Summary slide, effect of mud filtration of formation evaluation logs.

• Sound speed is function of the saturating fluid in the near wellbore area.
• Potassium muds have a large impact on natural gamma ray logs due to natural
radioactivity of 40K isotope (natural concentration ~0.01%, half life 109 years).
• Without filtration, SP logs would be useless.
• Resistivity and induction logs have a deep penetration, beyond filtrate invasion.
• Neutron and gamma logs: subject too broad to be treated here. In short,
detectors designed so that borehole effects can be compensated.
• NMR has a shallow depth of investigation, so strong effect of filtrate.
• Seismic is long wavelength, no effect of the invaded zone.

More details in next few slides or to be asked to interpretation experts.

Also refer to on-line Wireline training course:
https://elc.melun.eur.slb.com/onlinetraining/wireline/toc-body.htm

22
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Acoustic: UBI - USI – IBC – DSI – ASS - iSONIC

Wellbore Rotating sub

• Torque required to rotate the sub

in a drilling fluid:
Diameter2 x Length x “gel strength”

Schlumberger Private
• “Fluid Properties Monitor” to account for
effect of mud properties in the hole

• Filter cake: same impedance as the drilling fluid Flowing mud Immobile mud
but more attenuation

• Formation invasion:
– Sound velocity is function of primary porosity: contacts between grains
– Filtrate affects formation evaluation especially for gas zones

Schlumberger Private
23 GD
5/31/2005

UBI Ultrasonic Borehole Imager

USI UltraSonic Imager
IBC Imaging Behind Casing
DSI Dipole Shear Sonic Imager: both monopole and dipole acoustic sources
ASS Array Sonic: monopole measurement
SonicVISION / iSONIC LWD

The picture shows a numerical calculation done for estimating the torque required to rotate
the IBC sub in a drilling fluid (HV Nguyen).

For acoustic formation evaluation tools, formation invasion directly affects the measurements:
• The acoustic depth of penetration is relatively shallow – a few wavelengths - except
for long spacings.
• The sound velocity varies with primary porosity and the saturating fluid (and pore
pressure).
• The nature of the saturating fluid dictates the sound velocity: increasing velocity =
gas-oil-water-brine, due to both increase in density and decrease in compressibility.
• The larger the difference between the filtrate and the reservoir fluid, the bigger the
effect!
Note that secondary porosity has little impact, but fractures have a large effect (and low
porosity).
For LWD applications, the primary use of acoustic logs is the prediction of mechanical
properties of the rock for deriving the “safe mud weight window”.

23
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Nuclear Magnetic Resonance: CMR, MRX, MRF, etc.

NMR monitors all free Hydrogen nuclei with the depth of investigation (1.5 to 4 in).
n Total number of H → porosity
n Signal decay related to:

Schlumberger Private
– Diffusion of molecules within pores
→ molecule size, fluid viscosity
– Interaction with pore walls
→ pore size distribution
→ permeability
– Interaction with paramagnetic atoms

Schlumberger Private
24 GD
5/31/2005

Because NMR senses hydrogen atoms, it is strongly affected by any fluid invasion
(filtrate). Hopefully, the CMR tool can perform measurement at different depths of
investigation. The comparison of the water saturation vs. depth shows the invasion by the
aqueous filtrate. Information on native fluids is thus extracted from deep measurements.
Note that 4 inches as maximum DOI may not be sufficient to go beyond the invasion
zone.
On the log: the two tracks on the right side are measurements at 2 different Depth Of
Investigation (DOI). The shallow depth shows more water than the deep measurement.
SXO = water saturation in flushed zone, computed from MRX measurements

There are multiple mechanisms of

(transverse relaxation time, T2) signal
decay, each with variable dependency
on whether filtrate is there or not. The
basis of the interpretation is the
analysis of the T2 relaxation spectra,
shown here:
Short T2: irreducible water (top of zone)
Middle T2: water (bottom of zone)
Long T2: oil (middle of zone)

24
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Resistivity-Induction
HRLA, AIT, ARC, FMI, OBMI

Schlumberger Private

Schlumberger Private
25 GD
5/31/2005

Wireline tools: HRLA (High Resolution Laterolog Array tool, resistivity), AIT (Array Induction Tool), HALS
(High resolution Azimuthal Laterolog Sonde)
LWD: ARC or arcVISION, replacement of old CDR. Resistivity-at-the-bit
Imager: FMI, OBMI (Formation MicroImager, Oil-Based Mud Imager)
Pictures taken from HRLA brochure:
Without formation invasion by mud filtrate, life and resistivity tools and inversion would be much simpler!
Because of formation invasion, the resistivity varies with radial depth. The resistivity measurement at various
depth allows calculating the depth of invasion (di) and true formation resistivity (Rt)
In thin bed formations, a 2D model allows better resolution of the fine beds as shown on the log here: Rt from
1D inversion vs. Rt from 2D inversion.
Caption of right figure: Advanced 2D inversion—improving the accuracy of Rt
More accurate representation of the formation and borehole environment means more accurate Rt estimates,
especially in thinly bedded formations. The HRLA tool not only provides a coherent array of measurements,
but the improved quality of these measurements and the additional information about the invaded zone allow
advanced 2D inversion processing. The 2D formation model simultaneously accounts for all 2D effects,
including those from the wellbore (caves) and from vertical (shoulder-bed) and radial (invasion) resistivity
variations. The 2D inversion process begins with the information-rich raw HRLA data. First, layers are defined
through inflection-point segmentation, and a “first guess” is made for the initial formation parameters: Rt, Rxo
and di. The program then computes the tool response in the theoretical formation and compares it to the
actual response. The formation parameters are updated, and after successive iterations an acceptable match
is found. This mathematical inversion technique, used with a 2D formation model, yields a more accurate Rt
and therefore a more accurate saturation estimate.
On the log above, the 2D inverted Rt and Rxo are shown in track 3 with the raw HRLA curves. The red
shading indicates normal invasion (Rxo < Rt ); the green indicates reversed invasion (Rxo > Rt ). In track 4,
the 2D inverted resistivities Rt (red) and Rxo (green) are compared with the 1D inverted formation resistivity
Rt (magenta) and the Rxo (black) from the Platform Express MCFL MicroCylindrically Focused Tool. The 2D
inversion shows a significant increase in Rt obtained in thin beds—such as those between XX30 and XX70
ft—over the 1D inversion results. A good match between the 2D inversion-derived Rxo and the one
independently obtained from the MCFL measurement adds confidence to the inversion results.

25
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Spontaneous Potential
Cations between clay platelets can move:
– A difference in chemical potential between the aqueous
phase of the WBM and the formation water results in an
electrochemical potential

Schlumberger Private
– The flow of mud filtrate in the formation creates an
electrokinetic potential

SP = electrochemical +
electrokinetic potentials

Schlumberger Private
26 GD
5/31/2005

Spontaneous potential
The two components of the SP are due to electrochemical and electrokinetic effects:
• Electrochemical: originates from the difference in chemical potential between the
DF (WBM only) and the reservoir water
• Electrokinetic: due to the flow of conductive filtrate in the reservoir

This is one log that would be of no use without mud filtration and if the mud were
chemically equilibrated with the formation.

Note: the chemical potential of an aqueous solution is a

thermodynamic property that is a function of the content
and nature of the ions present in solution. It is commonly
measured by the “water activity” short for “water activity
coefficient”.

26
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Natural Gamma-Ray: GR, NGS

Th, U and K are measured

For KCl muds, the filtrate modifies the K
measurement

Schlumberger Private
Example of 2 logs in nearby wells with well 2
drilled with a KCl mud (Rider, 1986)

Schlumberger Private
27 GD
5/31/2005

GR: total natural gamma-ray

NGS: natural gamma ray spectroscopy, which differentiates between the 3 atoms. The Th/K
ratio is used to help identify the clay mineral present in the formation (graph below).
The picture shows a somewhat extreme example, even the shale layers have adsorbed some
additional K (picture extracted from O & L Serra, 2000). This effect is easy to predict because
we know which DF was in contact with the formation.
Note that in KCl muds, there is no bentonite – except from cuttings - so the polymer-mud cake
is mainly composed of polymers and will not affect the log. This is different from KCl treated
bentonite muds.

27
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Neutron-Neutron, Neutron- γ, γ-γ: RST

Multiple detectors are used to compensate from borehole effects,

e.g. mud cake (barite)

Schlumberger Private
Filtrate
– C/O ratio from inelastic neutron scattering
– Chloride absorbs thermal neutrons

Schlumberger Private
28 GD
5/31/2005

Too broad a topic to be summarized here, do not show the slide.

The two detectors design allows subtracting wellbore and mud cake effects (RST-A only).
The remaining eventual effect is on the carbon/oxygen ratio in the invaded zone for the
RST tool.

28
Introduction to Drilling Fluids – Part 4 5/31/2005
G Daccord

Conclusion

n Drilling Fluids is an active R&D area: not a mature or declining

business

Schlumberger Private
n Strong competition but good opportunities for improvements and
new markets
n Many physics problems still unsolved

References: refer to “Notes Page”

Schlumberger Private
29 GD
5/31/2005

References, in addition to those present on the slides or note pages:

• Several articles can be found in Oilfield Review:

http://www.oilfield.slb.com/content/resources/oilfieldreview/index.asp?

In particular: Vol. 1 (2), 1989; vol 2 (3), pp. 8-10; April 1994, pp. 34-43;
• MI SWACO web site: http://www.miswaco.co
• Waste management: Canadian Asso. of Pet. Producer, http://www.capp.ca
• API specification 13A for WBM and 13B for OBM/SBM: available from HIS site,
https://login.ihserc.com/login/erc?

• Solids Control Handbook, Dowell-Amoco, 1998. Available from IPM pages:

http://www.hub.slb.com/Docs/slb/Dowell%20Solids%20Control%20Handbook.ZIP

• Sedco Forex, Driller’s Stuck Pipe Handbook,

https://www.cambridge.scr.slb.com/~barrow/stuck_pipe/spade/version_4_4/handbook/handbook.html#Contents

• IPM Drilling Engineering web page : http://www.hub.slb.com/index.cfm?id=id15708

• IPM Well Construction & Intervention: The Hub > IPM > WCI > …

29