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Applied Drilling Engineering

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RP 9B, API, Dallas (Dec. 
19. Woodall-Mason, N. and Tilbe, J.R.: "Value of Heave Com-
pensators to Floating Drilling," J. Pet. Tech. (Aug. 1976) 938-
20. Spec. for Drilling and Well Servicing Structures, Std. 4E, 
API, Dallas (March 1974). 
a = constant used in curve-fitting drilling cost 
VS. depth 
a 2 = constant 
A capacity 
A_, displacement of section of pipe 
b constant used in curve-fitting drilling cost 
VS. depth 
C = cost 
Ct = cost per interval drilled 
C; mean cost of n; wells drilled to a mean 
depth, D; 
C r = fixed operating cost of rig per unit time 
d = diameter 
d 1 = inner diameter of annulus 
d 2 = outer diameter of annulus 
d 1 = diameter of liner in pump 
d r = diameter of rod in pump 
D =depth 
D; initial drilled depth of bit run; also mean 
depth of n; wells of mean cost, C; 
!:JJ = depth interval drilled during bit run 
e = base of natural logarithm 
E = efficiency 
F = force 
Ft = force in fast line 
F de maximum equivalent force on derrick 
F P = pump factor 
F,. = force in static line 
H = heating value of fuel 
natural logarithm to base e 
average length of one stand of drillstring 
length of level arm on prony brake 
stroke length on pump 
mechanical advantage 
ideal mechanical advantage of frictionless 
n = number of lines strung between crown 
block and traveling block 
n; = number of wells included in average cost 
N = number of cycles per unit time 
Nb number of bits per I ,000 ft 
N,. number of cylinders used in pump 
1:1p = pressure change 
P =power 
P; = input power 
q = flow rate 
Q; = power (heat) input from fuel consumption 
r = radius 
r d = drum radius 
r; residual error for observation i 
t b rotating time on bit during bit run 
t c nonrotating time on bit during bit run (such 
as connection time) 
t d = total drilling time to depth of interest 
td = drilling time per I ,000 ft 
t b average bit life 
t, = average time required to handle one stand 
of drillstring during tripping operations 
t 1 = time of tripping operations required to 
change bit 
T = torque 
v = velocity 
v b = velocity of block 
v1 = velocity of fast line 
V =volume 
wf = mass rate of fuel consumption 
W = load supported by block-and-tackle system 
p density 
w angular velocity 
a = annulus 
b = bit; block 
c = cylinders 
d = derrick; drum; drilling 
e = equivalent 
f = fast; fuel 
h = hook 
H = hydraulic 
mner; mean; indicated; ideal; 
m= mechanical 
p = pipe; pump 
r = rig 
s = static; stand; stroke 
t = overall 
v = volumetric 
SI Metric Conversion Factors 
bbl X 1.589 873 E-01 
bbl/ft X 5.216 119 E-01 
Btu/Ibm X 2.326* E+03 
ft X 3.048* E-01 
ft/bbl X 1.917 134 E+OO 
ft-lbf X 1.355 818 E+OO 
gal X 3.785 412 E-03 
hp X 7.460 43 E-01 
in. X 2.54* E+OO 
lbf X 4.448 222 E+OO 
lbm/ft X 1.488 164 E+OO 
Ibm/gal X 1.198 264 E+02 
Ibm/min X 7.559 873 E-03 
psi X 6.894 757 E+OO 
·Conversion factor is exact. 
m 3 /m 
m!m 3 
kg/m 3 
Chapter 2 
Drilling Fluids 
The purposes of this chapter are to present (1) the 
primary functions of the drilling fluid, (2) the test 
procedures used to determine whether the drilling fluid 
has suitable propeniesfor performing these functions, 
and (3) the common additives used -to obtain the 
desirable propenies under various well conditions. The 
mathematical modeling of the flow behavior of drilling 
fluids is not discussed in this chapter but is presented 
in detail in Chapter 4. 
Drilling fluid is used in the rotary drilling process to 
( 1) clean the rock fragments from beneath the bit and 
carry them to the surface, (2) exert sufficient 
hydrostatic pressure against subsurface formations 
to prevent formation fluids from flowing into the 
well, (3) keep the newly drilled borehole open until 
steel casing can be cemented in the hole, and (4) cool 
and lubricate the rotating drillstring and bit. In 
addition to serving these functions, the drilling fluid 
should not (1) have properties detrimental to the use 
of planned formation evaluation techniques, (2) 
cause any adverse effects upon the formation pene-
trated, or (3) cause any corrosion of the drilling 
equipment and subsurface tubulars. 
The drilling engineer is concerned with the 
selection and maintenance of the best drilling fluid 
for the job. The drilling fluid is related either directly 
or indirectly to most drilling problems. If the drilling 
fluid does not perform adequately the functions 
listed above, it could become necessary to abandon 
the well. Also, the additives required to maintain the 
drilling fluid in good condition can be quite expensive. 
Drilling fluid cost often exceeds $1 million on a single 
deep well in some areas. A drilling fluid specialist called 
a mud engineer frequently is kept on duty at all times 
to maintain the drilling fluid in good condition at the 
lowest possible cost. 
A broad classification of drilling fluids is shown in 
Fig. 2.1. The main factors governing the selection of 
drilling fluids are (1) the types of formations to be 
drilled, (2) the range of temperature, strength, 
permeability, and pore fluid pressure exhibited by the 
formations, (3) the formation evaluation procedure 
used, (4) the water quality available, and (5) ecological 
and environmental considerations. However, to a large 
extent, the drilling fluid composition that yields the 
lowest drilling cost in an area must be determined by 
trial and error. Waterbase muds are the most commonly 
used drilling fluids. Oil-base muds are generally more 
expensive and require more stringent pollution control 
procedures than water-base muds. Their use usually 
is limited to drilling extremely hot formations or 
formations that are affected adversely by water-base 
muds. The use of gases as drilling fluids is limited to 
areas where the formations are competent and im-
permeable. Gas/liquid mixtures can be used when 
only a few formations capable of producing water at 
significant rates are encountered. 
Fig. 2.2 shows the composition of a typical 11-
lbm/gal water-base mud. Water-base muds consist of 
a mixture of solids, liquids, and chemicals, with 
water being the continuous phase. Some of the solids 
react with the water phase and dissolved chemicals 
and, therefore, are referred to as active solids. Most 
of the active solids present are hydratable clays. The 
chemicals added to the mud restrict the activity of 
such solids, thereby allowing certain drilling fluid 
properties to be maintained between desired limits. 
The other solids in a mud do not react with the water 
and chemicals to a significant degree and are called 
inactive solids. The inactive solids vary in specific 
gravity, which therefore complicates analyses and 
control of the solids in the muds. Any oil added to 
water-base mud is emulsified into the water phase 
and is maintained as small, discontinuous droplets. 
This type of fluid mixture is called an oil-in-water 
Fig. 2.3 shows the composition of a typical 11-
lbm/gal oil-base mud. Oil-base muds are similar in 
composition to water-base muds, except the con-
tinuous phase is oil instead of water and water 
droplets are emulsified into the oil phase. This type 
of fluid is called a water-in-oil emulsion. Another 
Fig. 2.1-Ciassification of drilling fluids. 
major difference is that all solids are considered 
inactive because they do not react with the oil. 
2.1 Diagnostic Tests 
The American Petroleum Inst. 1 (API) has presented 
a recommended practice for testing liquid drilling 
fluids. These tests were devised to help the mud