CHAPTER 2
LITERATURE REVIEW
2.1
Introduction
This chapter discusses pertinent literature of drilling fluid such as the functions of
drilling fluid and its composition, various categories of base fluids and the additive
currently being used.
2.2
Functions of Drilling Fluids
A drilling fluid, or mud, is any fluid that is used in a drilling operation in which
that fluid is circulated or pumped from the surface, down the drill string, through the bit,
and back to the surface via the annulus ASME (2005) and Gardner (2003) as shown in
Fig. 2.1(HWU, 2009). According to Baker Hughes (1995), Chukwu (2008), Darley and
Gray (1988), drilling fluid must fulfil many functions in order for a well to be drilled
successfully, safely, and economically. The most important functions are:

Remove drilled cuttings from under the bit.

Carry those cuttings out of the hole.

Suspend cuttings in the fluid when circulation is stopped.

Release cuttings when processed by surface equipment.

Allow cuttings to settle out at the surface.

Provide enough hydrostatic pressure to balance formation pore pressures.

Prevent the bore hole from collapsing or caving in.

Protect producing formations from damage which could impair production.

Clean, cool, and lubricate the drill bit etc.
4
Fig.
2.1
Circul
ating
Syste
m
(HWU
, 2009)
2.2.1 Promote Boreh
Wellb
ore
stabilit
y is a
compl
ex
balanc
e
of
mechanical (pressure and stress) and chemical factors . The chemical composition and
mud properties must combine to provide a stable well until the casing can be run and
cemented. Regardless of the chemical composition of the fluid and other factors, the
5
weight of the mud must be within the necessary range to balance the mechanical forces
acting on the wellbore. Wellbore instability is most often identified by a sloughing
formation, which causes tight hole conditions, bridges and fill on trips (API, 1998).
2.2.2 Mechanical Stability
Under drilling conditions, the hydrostatic pressure exerted by the drilling fluid is
normally designed to exceed the existing formation pressures. The desired result is the
control of formation pressures and a mechanically stable borehole. In many cases, these
factors must also be considered:

Behaviour of rocks under stress and their related deformation characteristics.

Steeply dipping formations.

High tectonic activity.

Formations with no cohesive (lack of proper grain cementation) strength.

High fluid velocity.

Pipe tripping speeds and corresponding transient pressures.

Hole angle and azimuth.
Any of these factors may contribute to borehole instability. In these situations, a
protective casing string may be required, or hydrostatic pressure may need to be increased
to values greater than the anticipated formation pressure (Baker Hughes, 2006).
2.2.3 Facilitate Cementing and Completion
The drilling fluid must maintain a wellbore into which casing can be run and
cemented effectively and which does not impede completion operations. Cementing is
critical to effective zone isolation and successful well completion. During casing runs, the
mud must remain fluid and minimize pressure surges so that fracture-induced lost
6
circulation does not occur. Running casing strings in liquid filled boreholes is much easier
in a smooth, in gauge wellbore with no cuttings, caving or bridges. The mud should have a
thin, slick filter cake. To cement casing properly, the mud must be completely displaced by
the spacers, flushes and cement. Effective mud displacement requires that the hole should
be near gauge and the mud must have low viscosity and low, non-progressive gel
strengths. Completion operations such as perforating and gravel packing also require a
near-gauge wellbore and may be affected by mud characteristics (API, 1998).
2.2.4 Chemical Stability
Chemical interactions between the exposed formations of the borehole and the
drilling fluid are a major factor in borehole stability. Borehole formation hydration can be
the primary cause of hole instability, or a contributing factor. Aqueous drilling fluids
normally use a combination of:

A coating mechanism (encapsulation).

A charge satisfaction mechanism.

A mechanical or chemical method of preventing pore pressure transmission.
The present use of low solids/non/dispersed fluids incorporates these principles. They rely
on polymers and soluble salts to inhibit swelling and dispersion. Commonly used
polymers include:

Polysaccharide derivatives for filtration control.

Partially hydrolyzed polyacrylamides for encapsulation.

Xanthan gum for viscosity.
Isolating the fluid from the formation minimizes the potentially detrimental
interaction between the filtrate and the formation. This is accomplished by controlling
mud filtrate invasion of the formation. Filtrate invasion may be controlled by the type and
7
quantity of colloidal material and by filtration control materials and special additives like
cloud point glycols and products containing complexed aluminium. Non-aqueous drilling
fluids minimize wellbore instability problems by having all-oil filtrates and by the osmotic
pressure generated by the dissolved salt (Baker Hughes, 2006).
2.2.5 Remove Drilled Cuttings from Borehole
Drilling fluids transport cuttings from the wellbore as drilling progresses. Many
factors influence the removal of cuttings from the hole. The velocity at which fluid travels
up the annulus is the most important hole cleaning factor. The annular velocity must be
greater than the slip velocity of the cuttings for the cuttings to move up the well bore.
The size, shape, and weight of a cutting determine the velocity necessary to control
its settling rate through a moving fluid. Low shear rate viscosity strongly influences the
carrying capacity of the fluid and reflects the conditions most like those in the wellbore.
The drilling fluid must have sufficient carrying capacity to remove cuttings from the hole.
The density of the suspending fluid has an associated buoyancy effect on the cuttings. An
increase in density increases the capacity of the fluid to carry cuttings. Hole cleaning is
such a complex issue that the best analysis method is to use a simulator (Neff et al., 1987;
Baker Hughes, 2006).
2.2.6 Cool and Lubricate Bit and Drillstring
Considerable heat is generated by rotation of the bit and drillstring. The drilling
fluid acts as a conductor to carry this heat away from the bit and to the surface. Current
trends toward deeper and hotter holes make this a more important function. The drilling
fluid also provides lubrication for the cutting surfaces of the bit thereby extending their
useful life and enhancing bit performance. Filter cake deposited by the drilling fluid
provides lubricity to the drill string, as do various speciality products. Oil and synthetic
8
base fluids are lubricious by nature (Amoco, 1994; Willis, 2000; API, 1998; HSE, 1999).
According to Annis and Smith (1996), cooling and lubricating the bit and drill
string are done automatically by the mud and not because of some special design
characteristic. Muds have sufficient heat capacity and thermal conductivity to allow heat
to be picked up down hole, transported to the surface, and dissipated to the atmosphere.
The process of circulating mud down the drill pipe cools the bottom of the hole. The
heated mud coming up the annulus is hotter than the earth temperature near the surface
and the mud begins to heat the top part of the hole. This causes the temperature profile of
the mud to be different under static than under circulating conditions, as shown in Fig. 2.2
(Annis and Smith, 1996). The maximum mud temperature when circulating, is cooler than
the geothermal bottom-hole temperature. The point of maximum circulating temperature is
not on
botto
m but
about
a third
of the
way
up the
hole.
Fig.
2.2
Circul
9
ating Temperature Profile
( Annis and Smith, 1996)
2.2.7 Control Subsurface Pressure
As drilling progresses, oil, water, or gas may be encountered. Sufficient hydrostatic
pressure must be exerted by the drilling fluid column to prevent influx of these fluids into
the borehole. The amount of hydrostatic pressure depends on the density of the fluid and
the height of the fluid column, i.e., well depth. Typical materials used to maintain drilling
fluid density include barite, haematite, ilmenite and calcium carbonate. The following
formulae can be used to calculate the total hydrostatic pressure at any given depth or fluid
density:
Hydrostatic Pressure (psi) = 0.052 × Depth (ft) × Fluid Density (lbm/gal)
(2.1)
While static pressures are important in controlling an influx of formation fluids,
dynamic fluid conditions must also be considered. Circulation of the drilling fluid and
movement of the drillstring in and out of the hole create positive and negative pressure
differentials. These differentials are directly related to flow properties, circulation rate, and
speed of drill pipe movement . Hydrostatic pressure also controls stresses adjacent to the
wellbore other than those exerted by formation fluids (Baker Hughes,2006; API, 1998;
Amoco,1994).
2.2.8 Suspend Cuttings / Weight Material when Circulation Ceases
When drilling and fluid circulation is stopped, the gel strength of the drilling fluid
must be sufficient to maintain the cuttings in suspension. Several factors affect suspension
ability.

Density of the drilling fluid.
10

Viscosity of the drilling fluid.

Gelation, or thixotropic properties of the drilling fluid.

Size, shape and density of the cuttings and weight material.
Circulation of the suspended material continues when drilling resumes. The drilling fluid
should also exhibit properties which promote efficient removal of solids by surface
equipment (HSE,1999; Baker Hughes, 2006).
2.2.9 Support Partial Weight of Drillstring or Casing
The buoyancy effect of drilling fluids becomes increasingly important as drilling
progresses to greater depths. Surface rig equipment would be overtaxed if it had to support
the entire weight of the drillstring and casing in deeper holes. Since the drilling fluid will
support a weight equal to the weight of the volume of fluid displaced, a greater buoyancy
effect occurs as drilling fluid density increases (HSE, 1999).
2.2.10
Data Logging
A variety of instruments are used down-hole to monitor drilling process. Drilling
fluid properties need to be such that logging instruments used are able to accurately
function and record the relevant well parameters. An increasing range of logging devices
is able to operate within standard muds containing suspended solids. However in some
cases there is still the need to use clean fluids, usually consisting of solids-free heavy
brines such as zinc bromide (HSE, 1999).
2.2.11
Minimize Adverse Effects on Productive Formations
It is extremely important to evaluate how drilling fluids will react when potentially
productive formations are penetrated. Whenever permeable formations are drilled, a filter
cake is deposited on the wall of the borehole. The properties of this cake can be altered to
11
minimize fluid invasion into permeable zones. Also, the chemical characteristics of the
filtrate of the drilling fluid can be controlled to reduce formation damage. Fluid-fluid
interactions can be as important as fluid formation interactions. In many cases, specially
prepared drill-in fluids are used to drill through particularly sensitive horizons (Baker
Hughes, 2006).
2.2.12
Transmit Hydraulic Horse Power to Clean Bit and Bottom of Borehole
Once the bit has created a drill cutting, this cutting must be removed from under
the bit. If the cutting remains, it will be “re-drilled” into smaller particles which adversely
affect penetration rate of the bit and fluid properties. The drilling fluid serves as the
medium to remove these drilled cuttings. One measure of cuttings removal force is
horsepower requirement available at the bit. These are the factors that affect bit hydraulic
horsepower:

Fluid density.

Fluid viscosity.

Jet nozzle size.

Flow rate.
Bit hydraulic horsepower can be improved by decreasing jet nozzle size or increasing the
flow rate. The two most critical factors are flow rate and nozzle size. The total nozzle
cross sectional area is a factor in increasing flow rate and hydraulic horsepower (Baker
Hughes, 2006; HWL 2009).
2.2.13
Release Undesirable Cuttings at the Surface
When drilled cuttings reach the surface, as many of the drilled solids as possible
should be removed to prevent their recirculation. Mechanical equipment such as shale
shakers, desanders, centrifuges, and desilters remove large amounts of cuttings from the
12
drilling fluid. Flow properties of the fluid, however, influence the efficiency of the
removal equipment. Settling pits also function well in removing undesirable cuttings,
especially when fluid viscosity and gel strengths are low (Baker Hughes, 2006).
2.2.14
Ensure Maximum Information from Well
Obtaining maximum information on the formation being penetrated is imperative.
A fluid which promotes cutting integrity is highly desirable for evaluation purposes. The
use of electronic devices incorporated within the drill string has made logging and drilling
simultaneous activities. Consequently, optimum drilling fluid properties should be
maintained at all times during drilling, logging, and completion phases (Baker Hughes,
2006).
2.2.15
Limit Corrosion of Drillstring, Casing, and Tubular Goods
Corrosion in drilling fluids is usually the result of contamination by carbon
dioxide, hydrogen sulphide, and oxygen or, in the case of static fluids, bacterial action.
Low pH, salt-contaminated, and non-dispersed drilling fluids are inherently more
corrosive than organically treated freshwater systems. Oil or synthetic-based fluids are
considered non-corrosive. A proper drilling fluid corrosion control program should
minimize contamination and render the contaminating source non-corrosive (Baker
Hughes, 2006; Amoco,1994).
2.2.16
Minimize Environmental Impact
Drilling creates significant volumes of used fluid, drill cuttings and associated
waste. Increased environmental awareness has resulted in legislation that restricts the use,
handling and disposal of the by-products generated during drilling and after the well is
finished. Careful attention to the composition of the fluid and the handling of the residual
materials reduces the potential environmental impact of the drilling operation (Baker
13
Hughes, 2006; Amoco, 1994; API, 1998).
2.2.17
Improve Penetration Rates
Proper fluid selection and control can improve the rate of penetration (ROP).
Benefits of improved penetration rates are reduced drilling time and fewer hole problems
because of shorter open-hole exposure time. Generally, improved penetration rates result
in reduced costs. Operations such as cementing, completion, and logging must be factored
in to determine true cost effectiveness of improved penetration rates (Amoco, 1994).
2.2.18
Reducing Filtration Rate
The danger of drilling fluid being lost into a formation is particularly important
when drilling through porous and permeable formations where the rate of fluid loss
(filtration rate) may be excessive. Fluid loss control products are designed to reduce the
amount of filtrate lost to permeable formations and to produce a thin filter cake on the hole
walls. Polymers in conjunction with bentonite achieve this in water base muds. Oil based
muds are naturally inhibitive, and generally do not require such additives. Loss circulation
materials are generally different product designed to prevent or reduce the loss of the
whole mud to fractures or vugular porosity, nut plug, mica and large flake material
(cellophane and paper) are common products. A wide range of additives, ranging from
shredded paper to proprietary polymers, are available to reduce filtration rates. Additives
with large individual particles will block and fill cavities and pores (HSE, 1999).
Clearly, these lists of functions indicate the complex nature of the role of drilling
fluids in the drilling operations. It is obvious that compromises will always be necessary
when designing a fluid to carry out these functions, which in some cases require fluids of
opposite properties. The most important functions in a particular drilling operation should
be given the most weight in design of the drilling fluid. Many of these functions are
14
controlled by more than one mud property (Annis and Smith, 1996).
2.3
Composition of Drilling Fluid
Drilling fluids consist of a continuous liquid phase, to which various chemicals and
solids have been added to modify the operational properties of the resulting mix. Key
operational properties of drilling fluid include density, viscosity, fluid loss, ion-exchange
parameters, reactivity and salinity (OGP, 2003).
2.3.1 Key Properties of Drilling Fluid
Density
The density of the fluid will vary according to the formation pressures encountered
in the well bore. It is critical to the stability of the well bore that the formation pressures
are correctly balanced with the drilling fluid to prevent the formation fluids from flowing
into the well bore, and to prevent pressurized formations from causing a well blowout
(OGP and OPIECA, 2009).
Fluid loss control
Some additives may be required to help establish a strong impermeable filter cake
on the well bore to limit the loss of the drilling fluid filtrate to porous formations being
drilled. This improves the stability of the wellbore and a number of drilling and
subsequent production problems (OGP and OPIECA, 2009).
Viscosity
Drilling fluid must be able to suspend drilled cuttings, weighting materials such as
(barium sulphate) and other chemical additives under a wide range of conditions. The
viscosity of the drilling fluid must also be such that the removal of drilled solids at the
surface using solids control equipment is possible (OGP and OPIECA, 2009).
15
Shale Inhibition
When using a Water Base Fluid (WBF), the addition of shale inhibition chemicals
is required to prevent the formation clays from swelling and sticking, which would result
in significant drilling problems. Non-Aqueous Drilling Fluid (NADF) drilling fluids do
not allow the formation clays to be exposed to water. These types of fluids are therefore
innately inhibitive (OGP and OPIECA, 2009).
2.3.2 Types of Drilling Fluids
According OGP, (2003), and Neff et al., (1987), there are two primary types of
drilling fluids:Water Based Fluids (WBFs) and Non-Aqueous Drilling Fluids (NADFs).
Water Based Fluids (WBFs)
WBFs consist of water mixed with bentonite clay and barium sulphate (barite) to
control mud density and thus, hydrostatic head. Other substances are added to gain the
desired drilling properties. These additives include thinners (eg lignosulphonate, or
anionic polymers), filtration control agents (polymers such as carboxymethyl cellulose or
starch) and lubrication agents (eg polyglycols) and numerous other compounds for
specific functions. WBF composition depends on the density of the fluid. As example,
WBF composition (in wt%) for a (9.93 lb/gal) fluid is: 76 wt% water, 15% barite, 7%
bentonite and 2% salts and other additives (Fig. 2.3a) (OGP and OPIECA, 2009).
16
Seaw ater
Barite
7%
Bentonite
Salt and Other
2%
15%
76%
Fig. 2.3a WBF-Chemical Components by Weight (%)
(Modified after OGP and OPIECA, 2009).)
OGP and OPIECA (2009), also reported that the chemical components of Water Based
Mud as shown in Table 2.1. The information has been averaged for global use from
industry sales volumes and fluid types used (Fig. 2.3b; OGP and OPIECA, 2009).).
Table 2.1 Components of Water Based Fluid
Chemical Component
Composition (%)
Seawater
76
Barite
14
Clay/Polymer
6
Other
4
17
Seaw ater
Barite
6%
4%
Bentonite
Other
14%
76%
Fig. 2.3b WBF-Chemical Components by Weight (%)
(Modified after OGP, 2003)
Non-Aqueous Drilling Fluids (NADFs)
NADFs are emulsions where the continuous phase is the non-aqueous base fluid
(NABF) with water and chemicals as the internal phase. The NADFs comprise all nonwater and non-water dispersable base fluids. Similar to WBFs, additives are used to
control the properties of NADFs. A typical NADF composition is shown in Fig. 2.4 (OGP,
2003). Emulsifiers are used in NADFs to stabilise the water-in oil emulsions. As with
WBFs, barite is used to provide sufficient density.
Viscosity is controlled by adjusting the ratio of base fluid to water and by the use
of clay materials. The base fluid provides sufficient lubricity to the fluid, eliminating the
need for lubricating agents. NADF composition depends on fluid density. OGP and
OPIECA (2009), presented an example NADF composition of (in wt%) 47% base fluid,
18
33% barite and 20% water. This example does not reflect a 2-5% content of additives such
as fluid loss agents and emulsifiers that would be used in a NADF.
NAF
Barite
18%
Brine
Emulsifier
Gellants/Others
2%1%
46%
33%
Fig. 2.4 Non-Aqueous Drilling Fluids-Chemical Components by Weight (%)
(Modified after OGP and OPIECA, 2009; OGP, 2003)
NADFs can be split into three groups based on their aromatic hydrocarbon content
(Table 2.2; OGP, 2003).
Table 2.2 Classification of Non-Aqueous Fluids
Non-Aqueous Category
Components
Group I: high-aromatic
Crude oil, diesel oil and
content fluids
conventional mineral oil
Group: medium-aromatic
Low-toxicity mineral oil
content fluids
19
Aromatic Content
5-35%
0.5-5%
Group III: low/negligible
Ester, LAO, PAO, linear
<0.5% and PAH lower than
aromatic content fluid
paraffin and highly
0.001%
processed mineral oil
(Source: OGP and IPIECA 2009)
Group I Non-Aqueous Fluids (High Aromatic Content)
These were the first NABFs used and include diesel and conventional mineral oil
based fluids. They are refined from crude oil and are a non-specific collection of
hydrocarbon compounds including paraffins, olefins and aromatics, and polycyclic
aromatic hydrocarbons (PAHs). Group I NABFs are defined by having PAH levels greater
than 0.35% (OGP, 2003).
Diesel Oil Based Fluids
The PAH content of diesel-oil fluids is typically in the range of 2-4% and the
aromatic content is up to 25%.
Conventional Mineral Oil (CMO) Based Fluids
These were developed as a first step in addressing the concerns over the potential
toxicity of diesel oil-based fluids and to minimise fire and safety issues (Dicks et al.,
1987). CMOs are manufactured by refining crude oil, with the distillation process control
led to the extent that total aromatic hydrocarbons are about half that of diesel. The PAH
contents are 1-2 %. Because of concerns about toxicity, diesel-oil cuttings are not
discharged. However, in situations where transportation of cuttings to shore or injection of
cuttings is possible, such fluids may still be in use (OGP., 2003).
Group II Non-Aqueous Fluids (Medium Aromatic Content)
These fluids, usually referred to as Low Toxicity Mineral Oil Based Fluids
20
(LTMBF) were developed as a second step in addressing the concerns over the potential
toxicity of diesel-based fluids (OGP, 2003). Jacques et al. (1992); and Meinhold (1999)
also referred to this group of NABFs as Enhanced Mineral Oil Based Fluid (EMOBFs).
The fluids in this group are also developed from refining crude oil, but the distillation
process is controlled to the extent that total aromatic hydrocarbon concentrations (between
0.5 and 5%) are less than those of Group I NABFs and PAH content is less than 0.35% but
greater than 0.001% (Jacques et al. 1992; Meinhold 1999).
Group III Non-Aqueous Fluids (Low to Negligible Aromatic Content)
These fluids are characterised by PAH contents less than 0.001% and total aromatic
contents less than 0.5%. Group III includes synthetic based fluids (SBFs) which are
produced by chemical reactions of relatively pure compounds and can include synthetic
hydrocarbons (olefins, paraffins, and esters). Base fluids derived from highly processed
mineral oils using special refining and/or separation processes (paraffins, enhanced
mineral oil based fluid (EMBF), etc) are also included. In some cases, fluids are blended
to attain particular drilling performance conditions (OGP, 2003).
According to Neff et al., (1987), synthetic based fluid can be classified into four categories
as follows:

synthetic hydrocarbons.

ethers.

esters.

acetals.
Synthetic Hydrocarbons
Synthetic hydrocarbons are produced solely from the reaction of specific, purified
chemical feedstock as opposed to being distilled or refined from petroleum. They are
21
generally more stable in troublesome high temperature downhole conditions than the
esters, ethers and acetals, and their rheological properties are more adaptable to deep water
drilling environments. By virtue of the source materials and the manufacturing process,
they have very low total aromatic hydrocarbon and PAH content (<0.001%) (OGP., 2003).
The most common synthetic hydrocarbons are esters, polymerised olefin (linear
alpha olefin (LAO), internal olefin (IO)) and synthetic paraffins. According to Friedheim
and Conn (1996), polymerized olefins are the most frequently used synthetic hydrocarbons
in SBFs today. Polymerized olefins include linear alpha olefins (LAOs), poly alpha olefins
(PAOs), and internal olefins (IOs)
Highly Processed Mineral Oils:
These fluids are produced by refining and/or separation processes and can have
composition and properties similar to those of synthesised paraffins. The composition of
these fluids depends on the feedstock and the refining or separation processes used
Historically, diesel and mineral oils were the base fluids (together referred to as
Group NABFs) used in NADFs. The drilling advantages of Group I NABFs can be
obtained with the use of the Group II and Group III NABFs that have technical
performance properties and uses similar to Group I fluids. Group II and III NABFs have
lower aromatic content and PAH than diesel oil or mineral oil and have lower acute
toxicity. Depending on local regulatory requirements, cuttings from wells drilled with the
NADFs are currently being discharged in many offshore areas such as the Gulf of Mexico,
Azerbaijan,
Angola,
Nigeria,
Equatorial
Guinea,
Congo,
Thailand,
Malaysia,
Newfoundland, Australia and Indonesia instead of being barged to shore for disposal or
injected offshore (OGP, 2003).
2.4
Advantages of NADFs
22
In most cases, WBFs are less expensive than NADFs and are used where
practicable. WBFs are not well suited for certain drilling applications. For example, WBFs
are not suited for use in some demanding drilling operations, including the drilling of
highly deviated and horizontal wells often associated with offshore developments. WBFs
can be problematic where water sensitive clays/shales are present, because interactions of
the formation with water will cause the drill pipe to stick or the walls of the hole to slough
in.
In these situations, NADFs are used in place of WBFs. Often, both WBFs and
NADFs are used in drilling the same well. WBFs may be used to drill some portions
(particularly the shallow portion) of the well, and then NADFs will be substituted for the
deeper portions. Although NADFs are generally more expensive on a per barrel basis than
WBFs, the increased expense is usually offset by improved drilling performance. NADFs
offer the following significant advantages (OGP, 2003).
2.4.1 Wellbore Stability
NADFs do not contain water as a free phase. As a result they typically exhibit low
reactivity with water-sensitive formations (primarily shales) encountered and consequently
avoid damage to the formation. Thus clay swelling and borehole stability problems are
minimised. The resultant improved drilling efficiency leads to lower operational and
environmental risks.
2.4.2 Lubricity
Some of the additives used to formulate NADFs can considerably reduce the
friction factor (over that of WBFs) between the drill string and the sides of the borehole.
Minimising friction and the ability to transfer the weight to the bit are very important
factors in drilling highly deviated extended reach and horizontal wells. Higher lubricity
23
also lowers the incidence of stuck pipe, which can significantly lower drilling efficiency.
Without sufficient lubricity, deviated or horizontal wells may not be able to reach their
drilling target, leading to the need for additional platforms to develop a resource.
Such additional costs may make development of the resource non-economic, and
thereby prevent development. If the resource can be developed using additional platforms
and wells, the environmental footprint would be substantially increased. Therefore,
lubricity is critically important in modern drilling fluid systems (HSE, 1999; OGP 2003).
2.4.3 High Temperature Stability
At high temperature water based fluid may experience problems with viscosity,
fluid loss, control, gel strength and chemical instabilities. These in turn may lead to barite
settling, loss circulation, formation damage, hole erosion, and corrosion or scaling
(Saxena, 1987). NADFs are more stable in high temperature applications, such as those
encountered in deeper wells as compared to water based fluid (HSE,1999; OGP, 2003).
2.4.4 Low Mud Weight
Lower mud weights can be achieved with NADFs than with WBFs due to the
lower specific gravity of NADF base fluids. Low mud weight systems are desirable for
wells drilled in highly fractured formations with low fracture strength, wells with low
productivity, and wells with lost circulation zones (OGP., 2003).
2.4.5 Hydrate Formation Prevention
There is a somewhat greater risk of forming gas hydrates in WBFs than NADFs.
Gas hydrates are (relatively) stable solids that can plug lines and valves when they form.
They form under certain conditions of pressure and temperature in the presence of free gas
and water. These conditions can occur during critical well control operations and may
present a risk to operations, especially in deep water. For this reason, chemicals (salt,
24
methanol, and/or glycol) are often added to WBFs used for deep water wells to prevent
hydrate formation. The water phase of a NADF does not normally contribute to hydrate
problems, because it is present in a relatively low concentration (20% or less by volume)
and it generally has a high salt content (primarily for shale inhibition) (HSE,1999; OGP,
2003).
The following benefits can be derived from the above properties:
Safety
Reduction in drilling time and the need for well-bore maintenance activity reduces
the health and safety risks to personnel for each well drilled. Use of NADFs reduces
drilling time for wells drilled through sensitive shales, and horizontal, or highly deviated
extended reach wells. In addition NADF use results in fewer drilling problems and
consequent remedial work (OGP, 2003).
Improved Rate of Penetration
Drilling with NADFs can often result in more efficient drilling (less time to drill a
well) by reducing well-bore friction-resulting in better stabilisation of the bottom hole
assembly, providing improved lubricity, providing better well-bore stability resulting in
less time for cleaning the hole, and by keeping the bit cutting surfaces cleaner. For the
Chirag Field in the Caspian Sea, the first three wells were drilled with water-based mud
with an average drilling time of 46.3 days. Subsequently three wells were drilled at the
same location with synthetic paraffin to about the same depth as the wells drilled with
WBM. The average drilling time for the latter wells was 23.5 days. This case suggests that
non-aqueous drilling fluids reduce drilling fluids in half compared to water-based drilling
fluids (HSE,1999; OGP, 2003).
Reduced Waste Generation
25
The volume of cuttings produced from drilling with NADFs will be less than that
generated from drilling with WBFs. Hole maintenance is better when drilled with NADF,
resulting in less side wall wash out and a hole that is close to gauge; i.e. nominal bit
diameter. In addition, NADFs are more tolerant to the buildup of fine particulate materials
before the drilling properties degrade. Therefore, they can be reused for a longer period of
time than WBFs prior to their disposal (OGP, 2003).
Suspension of Drilling
In locations where severe weather is an issue, drilling operations may need to be
suspended on occasions and a hole may need to be left exposed to the drilling fluid for
extended periods of time. The well-bore stability characteristic of NADFs allows sensitive
shale formations to be left exposed during such periods without the extensive remedial
work that could be required if WBFs were used (OGP, 2003).
2.5
Disadvantages of NADF
The use of NADFs can also lead to some disadvantages relative to the use of
WBFs. These disadvantages include:
2.5.1 Cost
The wide range of NABF costs depends on the cost of materials for the base fluid
(refined versus synthesised). Synthetic base fluids tend to be 3 to 5 times more expensive
than mineral oils. Cost can be prohibitive, particularly in situations where lost circulation
of the drilling fluid is experienced. In such circumstances, options may include using WBF
or Group I fluids with injection or onshore disposal of cuttings (OGP, 2003).
2.5.2 Physical Properties
Cold temperatures can cause the viscosity of some base fluids, such as the
conventional esters, to rise to an unacceptable level. Therefore, it is important to choose a
26
base fluid that has acceptable drilling properties for the drilling situation envisioned
(OGP., 2003).
2.5.3 Reduced Logging Quality
Due to the insulating properties of the base fluid, use of NABFs may not be
acceptable in applications where electrical log information is critical (OGP, 2003).
2.6
Drilling Fluid Additives
Many substances, both reactive and inert, are added to drilling fluids to perform
specialized functions. The most common functions are:

Alkalinity and pH Control: Designed to control the degree of acidity or alkalinity
of the drilling fluid. Most common are lime, caustic soda and bicarbonate of soda
(HSE, 1999 and Baker Hughes, 1995).

Bactericides: Used to reduce the bacteria count. Paraformaldehyde, caustic soda,
lime and starch preservatives are the most common (HSE, 1999 and Baker Hughes,
1995).

Calcium Reducers: These are used to prevent, reduce and overcome the
contamination effects of calcium sulphates (anhydrite and gypsum). The most
common are caustic soda, soda ash, bicarbonate of soda and certain
polyphosphates (HSE, 1999 and Baker Hughes, 1995).

Corrosion Inhibitors: Used to control the effects of oxygen and hydrogen sulphide
corrosion. Hydrated lime and amine salts are often added to check this type of
corrosion. Oil-based muds have excellent corrosion inhibition properties (HSE,
1999 and Baker Hughes, 1995).

Defoamers: These are used to reduce the foaming action in salt and saturated salt
water mud systems, by reducing the surface tension (HSE, 1999 and Baker
27
Hughes, 1995).

Emulsifiers: Added to a mud system to create a homogeneous mixture of two
liquids (oil and water). The most common are modified lignosulfonates, fatty acids
and amine derivatives (HSE, 1999 and Baker Hughes, 1995).

Filtrate Reducers: These are used to reduce the amount of water lost to the
formations.
The
most
common
are
bentonite
clays,
CMC
(sodium
carboxymethylcellulose) and pre-gelatinized starch (HSE, 1999 and Baker Hughes,
1995).

Flocculants: These are used to cause the colloidal particles in suspension to form
into bunches, causing solids to settle out. The most common are salt, hydrated
lime, gypsum and sodium tetraphosphates (HSE, 1999 and Baker Hughes, 1995).

Foaming Agents: Most commonly used in air drilling operations. They act as
surfactants, to foam in the presence of water (HSE, 1999 and Baker Hughes,
1995).

Lost Circulation Materials: These inert solids are used to plug large openings in the
formations, to prevent the loss of whole drilling fluid. Nut plug (nut shells), and
mica flakes are commonly used (HSE, 1999 and Baker Hughes, 1995).

Lubricants: These are used to reduce torque at the bit by reducing the coefficient of
friction. Certain oils and soaps are commonly used (HSE, 1999 and Baker Hughes,
1995).

Pipe-Freeing Agents: Used as spotting fluids in areas of stuck pipe to reduce
friction, increase lubricity and inhibit formation hydration. Commonly used are
oils, detergents, surfactants and soaps (HSE, 1999 and Baker Hughes, 1995).

Shale-Control Inhibitors: These are used to control the hydration, caving and
28
disintegration of clay/shale formations. Commonly used are gypsum, sodium
silicate and calcium lignosulfonates (HSE, 1999 and Baker Hughes, 1995).

Surfactants: These are used to reduce the interfacial tension between contacting
surfaces (oil/water, water/solids, water/air, etc.) (HSE, 1999 and Baker Hughes,
1995).

Weighting Agents: Used to provide a weighted fluid higher than the fluids specific
gravity. Materials are barite, hematite, calcium carbonate and galena (HSE, 1999
and Baker Hughes, 1995). OSHA (2009b), also reported that weighting materials,
primarily barite (barium sulfate), may be used to increase the density of the mud in
order to equilibrate the pressure between the wellbore and formation when drilling
through particularly pressurized zones. Hematite (Fe2O3) sometimes is used as a
weighting agent in oil-based muds.
29