American Oil and Gas Reporter - October 2015 - 80

SpecialReport: Drilling Fluids Technology
In today's cost-conscious industry, cost per barrel is obviously a key consideration in selecting the best fluid option. However, a mud system's cost per barrel can be very misleading unless
all cost factors are considered, and deciding on the wrong fluid
can be a very costly mistake. Figure 1 shows the relationship between the cost index and the relative damage of eight fluid types,
with the cheapest mud causing the most damage to the producing zone. While more complex fluid systems cost more, they may
eliminate potential drilling problems that could turn into major
nonproductive time (NPT) events.
FIGURE 1
Relative Mud Cost Index
Versus Relative Damage Index
Synthetic OBM
OBM
Aerated Muds

RCI
RDI

KCL/Polymer/Glycol
PHPA/Polymer
Seawater Polymer
Freshwater Dispersed
Gel
Lignosulfonates

FIGURE 2
Types of Drilling Fluid System
Oil is the continuous phase,
most common: w/o emulsions

Water is the continuous phase

Oil-based
Synthetic
fluid

Diesal
oil

Water-based
Mineral
oil

LAO
PAO
IO
Ester oils

Colloidal
clay

Clay and Polymer
polymers muds

50% worldwide

Pneumatic
Dry
gas

Mist

Foam

Gasified
mud

Niche
applications

FIGURE 3
Maximum Densities for Various Brine Solutions
Cesium Acetate
Cesium Formate
CaBr2/ZnBr2
CaCl2/ZnBr2
CaBr2
K Formate
Base Fluid

K Acetate
NaBr
Na Acetate
CaCl2
Na Formate
NaCl
KCi
Seawater
Freshwater
Oil
0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0 10.0 11.0 12.0 13.0 14.0 15.0 16.0 17.0 18.0 19.0 20.0
lb/gal

80 THE AMERICAN OIL & GAS REPORTER

Base Fluid Systems
The chemistry of any drilling fluid depends on the base fluid used for its construction-pneumatic, water or oil-and sets the
chemistry of all the additives used in the system. Figure 2 shows
the various systems for each base fluid.
Only a small percentage of wells are drilled pneumatically.
The wells always are drilled underbalanced and have the advantage of fast drill rates and minimal damage to the producing zone.
Pure compressed air is circulated through the bit at high volumetric rates and cuttings are ejected as dust. If increasing amounts
of formation water are encountered, the air system is converted
to mist or foam. A number of horizontal wells have been drilled
pneumatically in the Marcellus Shale, and some operators are using hybrid pneumatic systems (inject air into the mud) for managed pressure drilling.
The base fluids for water-based products range from freshwater (chloride content below 5,000 milligrams/liter) to saturated
brines. Brine-based systems typically eliminate the need to use
bentonite for viscosity and fluid loss control, and API mud properties are controlled by various types of water-dispersible polymers.
In offshore drilling, cost and logistics dictate using seawater
as the preferred makeup fluid in top-hole drilling, and perhaps
down to intermediate pipe setting. With seawater salinity and salt
makeup varying throughout the world, the trend has been to use
more brine fluids to formulate the mud. Freshwater "wets" shale
formations and can accelerate wellbore collapse, depending on
the characteristics of the shale formation. Brine-based systems,
along with a variety of shale stabilizing additives, slow the water wetting of shales to delay associated wellbore stability problems.
Another reason for using brine-based systems is to minimize
excessive solids buildup in the mud, which is related to most
drilling fluid problems in water systems. These mud problems
include lower penetration rates, bit balling, and contamination
issues such as high gel strengths and excessive circulating pressure drops. Brine water inhibits the hydration of clays in the shale.
Some brines, depending on the cation present, are better than others for wellbore stability.
While drilled solids are "bad" solids and high densityweight materials such as barite are "good" solids, all solids can
contribute to contamination problems and high pressure drops that
cause high equivalent circulating densities (ECDs). Saturated
brines can be used in place of mineral-weight materials such as
barite in many drilling operations. The majority of wells seldom
require mud weights higher than 14 pounds per gallon. Figure
3 shows the maximum densities at saturation that can be obtained
with a variety of brines versus pure water and oil.
Using brines to control mud weight (up to salt saturation) and/or
clay inhibition (3 percent to saturation) are part of the makeup
of "enhanced" or "high-performance" WBMs, especially for wellbore stabilizing with water-based drilling fluids.
Two types of brines are being used to formulate water-based
fluids: inorganic brines, primarily based on chlorides; and organic brines, primarily based on formates. One of the advantages of
using a formate brine is in waste disposal, such as land farming
cuttings. Formates will degrade into carbon dioxide and water.
Chlorides, on the other hand, cannot be removed chemically, but
must be diluted to acceptable regulatory levels.

American Oil and Gas Reporter - October 2015

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