Drilling Fluids Processing Handbook P2

2.1 DRILLING FLUID SYSTEMS 2.1.1 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 th

This page intentionally left blank

C H A P T E R 2

DRILLING FLUIDS

Fred Growcock

M-I SWACO

Tim Harvey

Oiltools, Inc

2.1 DRILLING FLUID SYSTEMS

2.1.1 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 Drilling fluids satisfy many needs in their capacity to do the following [M-I llc]:

. Suspend cuttings (drilled solids), remove them from the bottom of the hole and the well bore, and release them at the surface

. Control formation pressure and maintain well-bore stability

. Seal permeable formations

. Cool, lubricate, and support the drilling assembly

. Transmit hydraulic energy to tools and bit

. Minimize reservoir damage

. Permit adequate formation evaluation

. Control corrosion

15

. Facilitate cementing and completion

. Minimize impact on the environment

. Inhibit gas hydrate formation

The most critical function that a drilling fluid performs is to minimize the concentration of cuttings around the drill bit and throughout the well bore Of course, in so doing, the fluid itself assumes this cuttings burden, and if the cuttings are not removed from the fluid, it very quickly loses its ability to clean the hole and creates thick filter cakes To enable on-site recycling and reuse of the drilling fluid, cuttings must be continually and efficiently removed

2.1.2 Types of Drilling Fluids

Drilling fluids are classified according to the type of base fluid and other primary ingredients:

. Gaseous: Air, nitrogen

. Aqueous: Gasified—foam, energized (including aphrons)

Clay, polymer, emulsion

. Nonaqueous: Oil or synthetic—all oil, invert emulsion

True foams contain at least 70% gas (usually N2, CO2, or air) at the surface of the hole, while energized fluids, including aphrons, contain lesser amounts of gas Aphrons are specially stabilized bubbles that function as a bridging or lost circulation material (LCM) to reduce mud losses to permeable and microfractured formations Aqueous drilling fluids are generally dubbed water-based muds (WBMs), while non-aqueous drilling fluids (NAFs) are often referred to as oil-based muds (OBMs) or synthetic-based muds (SBMs) OBMs are based on NAFs that are distilled from crude oil; they include diesel, mineral oils, and refined linear paraffins (LPs) SBMs, which are also known as pseudo– oil-based muds, are based on chemical reaction products of common feedstock materials like ethylene; they include olefins, esters, and synthetic LPs

Detailed classification schemes for liquid drilling fluids are employed that describe the composition of the fluids more precisely One such classification scheme is shown in Figures 2.1 and 2.2 An even more precise classification scheme is described in Table 2.1, which includes

the mud systems most commonly used today, along with their principal components and general characteristics [adapted from Darley & Gray]

2.1.3 Drilling Fluid Selection

Drilling-fluid costs can constitute a significant fraction of the overall costs of drilling a well Often the cost is quoted per unit length drilled, which takes into account any problems encountered (and avoided), such

as stuck pipe In many cases, the cost ascribed to the fluid also includes costs associated with solids control/management and waste disposal

Soluble

Additives

Fresh

Water

Sea

Water

Saline Solution Water

Commercial Clays Polymers Chemicals

Low Gravity

Weight Material Insoluble Salts

High Gravity

Mud System Components

Smectite Clays Reactive

Sand Limestone Other minerals Inert

Drilled Solids Solids

Figure 2.1 Types of Water-Based Muds.

Surfactants

Rheology Modifers

Polymers

Thinners

Oil Soluble

Liquid Additives

Diesel Oil

Mineral Oil

Refined LP's

Oil Base

Fluid

Olefins Esters Synthetic LP's

Synthetic Fluid

External

Phase

Ca 2+ and OH − from Lime

Non-Chloride

Activity Reducers:

Glycols, Acetates, Nitrates

Internal Phase

Organophilic Clay Weight Material Salt (CaCO 3 ) FLC Additives

System Components

Clays Sand Limestone

Drilled Solids Solids

CaCl2

to reduce water activity

Figure 2.2 Types of Invert-Emulsion Muds.

FLC ¼ ferroelectric liquid crystals.

Table 2.1 Classification of Drilling Fluid Systems

Mud Type Principal Components General Characteristics

Aqueous

stable formations; need space for solids settling, flocculants may be used

clay, starch, cellulosic polymer

Moderate cost, drilling salt and workovers

gypsum, lignosulfonate

Moderate cost, shale drilling; simple maintenance, high temp, tolerance to salt, anhydrite, cement, drilled solids

Lignite or lignosulfonate

(chrome or chrome free)

Fresh or brackish water; bentonite, caustic, lignite

or lignosulfonate

Moderate cost, shale drilling; simple maintenance, high temp, tolerance to salt, anhydrite, cement

polymer, some bentonite

Moderate cost, hole stability; low tolerance to drilled solids, high pH

Low solids (‘‘nondispersed’’

when weighted up)

solids, cement and divalent salts

soap, water 2–5%

Moderate cost, low-press well completions and workovers, low-press shallow reservoirs; water used to increase density and cuttings-carrying capacity; strong environmental restrictions may apply

environmental restrictions may apply

emulsifiers, organophilic clay, modified resins, and soaps, 5–40% brine

maintenance, environmental restrictions

same as invert emulsion

low maintenance

Thus, it is just as important to minimize costs associated with these twoaspects as it is to ensure that the drilling fluid fulfills its primary functions [Young & Robinson] Muds that require special attention and equipment to control the levels and types of solids frequently incur higher costs Likewise, muds that generate waste fluid and cuttings, which must be hauled off (and perhaps treated) rather than discharged directly into the environment, generally incur higher costs

Until recently, waste WBMs did not require any treatment and could

be discharged directly into the environment However, a number of components in WBMs are becoming increasingly restricted or prohib-ited Chrome-containing materials, such as chrome lignosulfonates, are prohibited in many areas by governmental regulations Tight restrictions are imposed in many areas on chloride, nitrate, and potassium salts, or, more generally, on the total electrical conductivity of the mud In the North Sea, use of polyacrylamide polymers, such as partially hydrolyzed polyacrylamide (PHPA), is also severely restricted OBMs tend to be restricted even more than WBMs, especially offshore, and in many places they can be used only if a zero discharge strategy (sometimes called

a closed loop system) is adopted [Lal & Thurber]

On the other hand, SBMs often can be discharged directly into the sea if they meet certain toxicity/biodegradability criteria and, in the United States, do not create a sheen; as a result, though SBMs generally incur higher initial costs than OBMs, disposal costs for SBMs tend to be considerably less, which can make them more economical

to run

2.1.4 Separation of Drilled Solids from Drilling Fluids

The types and quantities of solids (insoluble components) present in drilling mud systems play major roles in the fluid’s density, viscosity, filter-cake quality/filtration control, and other chemical and mechanical properties The type of solid and its concentration influences mud and well costs, including factors such as drilling rate, hydraulics, dilution rate, torque and drag, surge and swab pressures, differential sticking, lost circulation, hole stability, and balling of the bit and the bottom-hole assembly These, in turn, influence the service life of bits, pumps, and other mechanical equipment Insoluble polymers, clays, and weighting materials are added to drilling mud to achieve various desirable properties

Drilled solids, consisting of rock and low-yielding clays, are incorporated into the mud continuously while drilling To a limited extent, they can be tolerated and may even be beneficial Dispersion of clay-bearing drilled solids creates highly charged colloidal particles (<2 mm) that generate significant viscosity, particularly at low shear rates, which aids in suspension of all solids If the clays are sodium montmorillonite, the solids will also form thin filter cakes and control filtration (loss of liquid phase) into the drilled formation Above a concentration of a few weight percent, dispersed drilled solids can generate excessive low-shear-rate and high-shear-rate viscosities, greatly reduced drilling rates, and excessively thick filter cakes As shown in Figures 2.3 and 2.4, with increasing mud density (increasing concentra-tion of weighting material), the high-shear-rate viscosity (reflected by the plastic viscosity [PV]) rises continuously even as the concentration of drilled solids (low-gravity solids [LGSs]) is reduced The methylene blue test (MBT) is a measure of the surface activity of the solids in the drilling fluid and serves as a relative measure of the amount of active clays in the system It does not correspond directly to the concentration of drilled solids, since composition of drilled solids is quite variable However, it is clear that, in most cases, drilled solids have a much greater effect than barite on viscosity and that the amount of active clays in the drilled

9

50

45

40

35

30

25

20

15

10

5

0

19 18 17 16 15 14 13 Mud Weight (lb/gal)

12 11

Maximum

6% LGS

9% LGS

10

Minimum

Water + Barite Water + LGS

Figure 2.3 Effect of Solids on Mud Weight of Water-Based Muds (Courtesy of M-I SWACO.)

solids is one of the most important factors Thus, as mud density is increased, MBT must be reduced so that PV does not reach such a high level that it exceeds pump capacity or causes well-bore stability problems

As shown in Figure 2.4, increasing the mud density from 10 lb/gal to

18 lb/gal requires that the MBT be reduced by half [M-I llc] Different mud densities require different strategies to maintain the concentration

of drilled solids within an acceptable range Whereas low mud densities may require only mud dilution in combination with a simple mechanical separator, high mud densities may require a more complex strategy: (a) chemical treatment to limit dispersion of the drilled solids (e.g., use of

a shale inhibitor or deflocculant like lignosulfonate), (b) more frequent dilution of the drilling fluid with base fluid, and (c) more complex solids-removal equipment, such as mud cleaners and centrifuges [Svarovsky]

In either case, solids removal is one of the most important aspects of mud system control, since it has a direct bearing on drilling efficiency and represents an opportunity to reduce overall drilling costs A diagram of a typical mud circulating system, including various solids-control devices,

is shown in Figure 2.5 [M-I llc]

While some dilution with fresh treated mud is necessary and even desirable, sole reliance on dilution to control buildup of drilled solids in

50

45

40

35

30

25

20

15

10

5

0

MBT

YP PV

Mud Weight (lb/gal)

2 ) and MBT (lb/bbl)

Figure 2.4 Effect of Mud Weight and MBT on Viscosity of Acceptable WBM (Courtesy of

M-I SWACO.)

the mud is very costly The dilution volume required to compensate for contamination of the mud by 1 bbl of drilled solids is given by the following equation:

Vdilution (bbl drilling fluid/bbl drilled solids) ¼ ð100  VsolidsÞ=Vsolids where Vsolids is the volume of drilled solids expressed in volume per-centage As discussed earlier, drilled solids become less tolerable with increasing mud density For drilling-fluid densities less than 12 lb/gal,

V <5% is desirable, whereas for a density of 18 lb/gal, V <2 or

Bit Drill collar Drill pipe

Kelly

Swivel Standpipe

Kelly hose Mixing hopper Discharge line

Mud pump

Suction line

Mud pits Shale shaker

Flow line

Figure 2.5 Drilling Fluid Circulating System (Courtesy of M-I SWACO.)