Chilingarian G.V. et al. Surface Operations in Petroleum Production, II
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TABLE
2.1-1
Coefficient record
form
and recorded sample data of a 4-in. meter
Meter
No.
1000
Remarks: Source
of
gravity
Size
4"
Connections: Flange Clock:
72
hr
W.L.A. Sta.
Source
of
temperature
Meter
No.
1000
Date
h, h/p,
Ext. Line and Gauge range
C
X
(M)(
MI)
C
X
(MI)
X
Gauge press.
C
X
(MI)
X
Sp. gr. Temp.
C'
Comp.
CK
--
effective group orifice
(MI)
(FeZFR)
(Fez
FR
FpV
--
-
psz
beta
S
group
C
Fe2
FR
EPV
FGFT
0.631 65
--
6.0 0.4
I
4X2.500
lOO/SO"
1316.0 40
-~
-
1-30-58 7.40 0.62 (3) 1387.2 0.9487 1.004 1321.3 1.004 1326.6 1.255 1664.9
K
C
56
run); and orifice
/3
=
0.62.
p(
=
d/D,
and termed beta) is the ratio of the diameter of
the orifice to the diameter of the meter run. When
using
flange connected meters,
the best measurement is attained with orifice plates having ratios between 0.15 and
0.70.
(7)
C
=
1387.2. The basic coefficient for a 4
X
2.500-in.
orifice (CNGA, 1956,
table 321).
(8)
Gauge range
=
100
lb/50
in.,
M
=
square root chart factor
=
0.7071 (CNGA,
1956, table 303).
(9) Chart reading method
=
Rockwell integrator 72-h combined
MI
factor.
I
=
J100/500
x
100/500
=
0.4472 integration factor for square root charts.
MI(72
h)
=
0.7071
X
0.4472
X
3
=
0.9487.
(10) F,,-Expansion factor is a function of
h,
=
6.0,
p,,
=
7.40, and
p
=
0.62.
(11) FR-Reynolds number factor is also a function of
h,,
p,,,
and
p.
Combined
(
Fe,
x
FR)
=
1.004 (CNGA, 1956, table 330).
(12) Fpv-Superexpansibility factor is a function of static pressure, specific
gravity and temperature of the gas.
p,,
=
7.40
=
40 lb gauge pressure; sp gr
=
0.631; flow temperature
=
65 OF, and thus
Fpv
=
1.004 (CNGA, 1956, tables 331 and 335).
(13) FG-(Specific gravity
=
0.631). This is one of the most variable of the factors
used. It corrects for the specific gravity variation of the gas.
(14) FT-(Flowing gas temperature
=
65 OF). This factor corrects for the temper-
ature change in the flowing gas.
The combined factors of
FG
and
FT
=
1.255 (CNGA, 1956, table 342).
Product of the factors (see Table 2.1-1, coefficient record form)
C
X
MI
X(F,2XFR)X
Fpv
X(FGXFT)=C’
(1387.2) x(0.9487)
x
(1.004)
X(1.004)
X
(1.255)
=
(1664.9)
Specific gravity and temperature determinations
In the computation of the coefficient, the most variable are the specific gravity
and the flowing temperature values. Following are various typical methods by which
these values are determined.
Specific gravity
record.
(1) Recording gravitometer piped directly to the meter run provides a continuous
(2) Gas sample tanks.
(a) Accumulative proportional sample-gas enters the tank only when there
is
flow through the meter and at a rate proportional to the flow. Usually this is a
weekly gas sample.
(b) Continuous time weighted sample-gas enters the tank continuously at a
uniform rate proportional to time. Usually this is a weekly gas sample.
(c) Spot sample-operator fills the tank manually.
(3)
Portable specific gravity devices.
Using these instruments, spot tests of gas are made in the field.
(4)
Source sample-data from one location used by several meters measuring gas
from the same or representative sources.
In all cases of gas sampling, great care should be taken to ensure a good sample
by adequate purging of the sample tank; or using known initial tank volume and
eliminating it through calculations after determination of collected sample volume.
Temperature
of
flowing gas
(1)
Recording temperature gauges on the meter.
(2)
Temporary recording gauge on the meter.
(3)
Meters with the same temperature characteristic using a base temperature
(4) Ground temperature.
(5) Spot temperature with stem thermometer.
location.
Interpreting the recorded temperature value
(1)
Only
flowing temperature should be used.
(2)
Large volume-usually no atmospheric influence.
(3)
Small volume- influenced by atmospheric conditions.
(4)
After regulators-gas cooled by expansion.
(5)
After compressors-gas heated by compression.
Significant figures
(A) When computing orifice coefficients, all computations should be carried to
five significant figures.
(B)
The number of significant figures given in the tables should be used in all
cases.
(C)
To determine the last significant figure in any computation, all calculations
are carried to one place beyond the number of significant figures desired. When the
next figure beyond the desired significant figure is
5
or more,
1
should be added to
the last significant figure.
Subsequent changes
of
coefficients
On a periodic frequency, provided that the orifice plate has not been changed,
the coefficients will be changed
if
the values of the factors change to the extent as
follows:
(1)
h,-More than two units. Example: 4.0-7.0.
(2)
ps2-More than one unit. Example: 6.0-8.0.
(3)
Specific gravity-More than
0.005.
Example: 0.630-0.636.
(4)
Average temperature-More than 4"
F.
Example: 65-70.
Some coefficients are changed on a regular weekly basis and others on a monthly
58
basis, depending upon the volume of gas measured through the meter. (These
subsequent changes were made by the Southern California Gas Company before
converting to computer calculation. Such procedures may vary in accordance with
the standard practices
of
each company.)
Calculation of
(C)
for nonstandard internal-diameter meter run
When the internal diameter
of
the meter run varies from the standard diameter
used in the
C
tables by the per cent allowable in table
XII,
p. 71,
of
CNGA (1956),
the value of
C
should be calculated by the formula
C
=
d2ZL
using
L
and
Z
values from CNGA (1956, pp. 88-89, tables 803 and
804).
L=
Ko/Ko(4)
and
Z
=
338.2
=
coefficient
of
a
4-in. meter having the same
/3
value.
Example
where
KO
=
coefficient
of
the required meter and
Calculation of
C
for a 6 (5.955 in. internal diameter)
X
3.500 in. orifice.
=
0.588
3.500
5.955
/3=
-
Maximum allowable tolerance for 6.065 standard run with
/3
of 0.59
=
1.3%.
Meter run of 5.955 in. diameter
=
1.8%
variation from standard; therefore, the
Computation of orifice meter gas coefficients. The value
of
C
can be calculated
standard
C
in the tables should not be used.
as follows:
C
=
d2ZL
=
12.25
X
218.1
X
0.9985
=
2667.7
d2
=
12.25;
Z
=
218.1 (table
804,
p.
89);
and
L
=
0.9985 (table
803,
p.
88).
The standard coefficient for 6.065-in. diameter
X
3.500 in. orifice
=
2654.9.
C
value of 5.955 in. dia.
=
2667.7
C
value of 6.065 in. dia.
=
2654.9
Difference
=
12.8
=
+
0.5%
REFERENCES
AGA,
1935.
The Gas Measurement Report No.
2. Natural Gas Department
of
the American Gas
AGA,
1955.
Orifice Metering ofNaturul gas, Report No.
3.
Gas Measurement Committee
of
the American
AGA,
1962.
Manual for the Determination
of
Supercompressibility Factors for Natural Gas.
American Gas
AGA,
1965.
Gas Engineer’s Handbook.
Industrial Press, New York, N.Y.
AGA-ASME,
1935.
History
of
Orifice Meters and the Calibration, Construction, and Operation
of
Orifices
for Metering,
joint report by American Gas Association and American Society
of
Mechanical
Engineers, New York, N.Y.
Association, New York, N.Y.
Gas Association, New York, N.Y.
Association, New York, N.Y.
59
Bean, H.S., 1967. Flow measurement, Part
I:
the expanding field
of
fluid metering.
Mech. Eng.,
April:
Bean,
H.S.
(Editor), 1971.
Fluid Meters.
ASME, New York, N.Y., 6th ed.
Brooks, Instrument Division, 1978.
Brooks
-
Oval Flowmeters.
Statesboro, Geo., 24 pp.
CE Invalco, 1980.
Turbine Flowmeters.
Tulsa, Okla., 16 pp.
CE Invalco, 1982.
Flow Measurement.
Tulsa, Okla., 28 pp.
CNGA, 1935.
Bull. TS
353. California Natural Gasoline Association, Long Beach, Calif.
CNGA, 1941.
Bull.
TS
402.
California Natural Gasoline Association, Long Beach, Calif.
CNGA, 1947.
Tentative Standard Procedure for the Determination of Superexpansibility and Manometer
Factors Used in Measurement of Natural
Gas
by Orifice Meter at Pressures in Excess of 500 pig. Bull.
TS 461.
California Natural Gasoline Association, Long Beach, Calif.
CNGA, 1956.
Tentative Standard Procedures for the Measurement of Natural Gas with Orifice Meters. Bull.
TS 561.
California Natural Gasoline Association, Long Beach, Calif. [This bulletin combines TS 353
(1935) and
TS
402 (1941) with new material added].
CNGA, 1963.
Tentatiue Standard for the Application of
Gas
Measurement Procedures to Computer Usage.
Bull. TS 622.
California Natural Gasoline Association, Long Beach, Calif.
Chilingar, G.V. and Beeson, C.M., 1968.
Surface Operations in Petroleum Production.
Am. Elsevier, New
York, N.Y., 397 pp.
Controlotron, 1984.
Clamp-on Flowmeters.
Controlotron Corp., Hauppage, New York, N.Y., 4 pp.
Cook, N.H. and Rabinowicz, E., 1963.
Physical Measurement and Analysis.
Addison Wesley, Reading,
Daniel Industries, Inc., 1979.
Daniel Orifice Fittings.
Houston, Tex., 8 pp.
Daniel Industries, Inc., 1981.
Flow Products Division.
Houston, Tex., 32 pp.
Daniel Industries, Inc., 1982.
Orifice Plates and Plate Sealing Units
(Catalog
500).
Houston, Tex., 8 pp.
Diehl, J.C., 1955.
Orifice Meter Constants, Handbook E-2.
American Meter Company, Fullerton, Calif.
Fischer and Porter, 1981.
Mini-Mag
(foldout), Warminster, Pa., 16 pp.
Fischer and Porter, 1982.
The New Vortex Flowmeter,
Warminster, Pa.,
3,
12 pp.
Foxboro Co., 1961.
Principles and Practices of Flow Meter Engineering.
Foxboro, Mass., 8th ed.
Gas Processors Suppliers Association (NGPSA), 1972.
Engineering Data Book.,
Tulsa, Okla.
Grove Valve and Regulator Company, 1983.
QF
Orifice Fittings.
Grove, Houston, Tex., 8 pp.
Halliburton Services, 1981.
Special Product Division General Catalog
(8 sections). Duncan, Okla.
Ikoku, Chi U., 1984.
Natural Gas and Production Engineering.
Wiley, New York, N.Y., 517 pp.
I'M Barton, 1980.
Floco Series F Positive Displacement Meters.
International Telephone and Telegraph
Katz, D.L., Cornell, D., Kobayashi, R., Poettmann, F.H., Vary, J.A., Elenbaas,
J.R.
and Weinaug, C.F.,
Kern, R., 1975. How to size flowmeters.
Chem. Eng.,
Mar.: 161-168.
Kerr, T.H. (Chairman), 1935.
The History of Orifice Meters and the Calibration. Construction, and
Operation of Orifices for Metering
(including all data from researchers used in the preparation of the
report). AGA-ASME Orifice Coefficient Committee. Boulder, Co.
36-38.
Mass.
Corp., City of Industry, Calif.
1959.
Handbook of Natural Gas Engineering.
McGraw-Hill, New York, N.Y., 802 pp.
Micromotion, Inc., 1981.
The Micromotion Flow Meter.
Boulder, Co., 8 pp.
Miller, T.E. and Small, H.. 1982. Thermal pulse time-of-flight liquid flow meters.
Anal. Chem.,
54(6):
Petroleum Extension Service, 1972.
Field Handling
of
Natural Gas.
Univ. Texas Press, Austin, Tex.
Powers, J., 1979. Flowmeters selection guide.
Chem. Process.,
Oct.: 79-85.
Richards, E.C., 1947.
Principles and Operation of Differential Meters.
Brown Instrument Company,
Philadelphia, Pa., 177 pp.
Sandford,
J.,
1976. What you should know about flow monitoring devices.
Instrum. Control Syst.,
Sept.:
25-32.
Spink,
L.K.,
1958.
Principles and Practice of Flow Meter Engineering.
The Foxboro Company, Foxboro,
Mass., 8th ed.
Templeton, W.J., 1979.
Practical Concerns in Metering Fluids from Production Operations,
SPE 7802.
Production Operations Symp., SOC. Petrol. Engrs.
of
AIME, Oklahoma City, Okla., Feb. 25-27, pp.
45-50.
907-910.
Terrell, C.E. and Bean, H.S., 1963.
AGA Gas Measurement Manual.
New York, N.Y.
Tokheim Corporation, 1978.
Metering Systems
-
Engineering Data
(10
sections). Fort Wayne, Ind.
This Page Intentionally Left Blank
61
Chapter
3
THE MANUFACTURE, CHEMISTRY AND CLASSIFICATION
OF
OILWELL CEMENTS AND ADDITIVES
JOHN
0.
ROBERTSON Jr., GEORGE
V.
CHILINGARIAN
and SANJAY KUMAR
INTRODUCTION
In 1824, Joseph Aspdin was granted a patent for an artifical cement produced by
burning a blend of limestone (CaCO,) and clay. The manufactured product was
called
“
portland cement” because Aspdin felt it resembled the stone quarried on the
Isle of Portland off the coast
of
England. Portland cement hardens to a set mass
when mixed with water (hydraulic product). Blanks and Kennedy (1955) presented a
detailed information on the manufacture and materials utilized in the preparation of
portland cements (see also Taylor, 1964).
The first case
of
the use of cement slurries in the United States was in 1903, 43
years after the drilling of Drake’s well. Frank
F.
Hill of the Union Oil Company is
credited with mixing and dumping (by means of a bailer) a slurry of
50
sacks of neat
portland cement to shut-off downhole water just above an oil sand in the Lompoc
Field in California, U.S.A. (API, 1948). The cement was drilled out of the wellbore
and the well was placed successfully on production after 28 days. Controlling or
reducing produced water in this manner for oil wells in California quickly spread to
other parts
of
the world.
Dump bailer and tubing placement techniques for cement were improved by the
development of a two-plug cementing method, which was introduced into the
California fields in 1909 by A.A. Perkin (Tough, 1918). Much of todays oilwell
cement technology is based on the Perkin’s technique
of
cement displacement. The
patent issued to Perluns specified the use of two plugs. Later court rulings, however,
extended the patent to include any barrier that prevents the cement from mixing
with contaminants in front or behind the cement.
The Perkins Co. was primarily a California company, whereas Earle
P.
Hallibur-
ton formed a company in Oklahoma to serve the Hewitt Field, Carter County,
Oklahoma. Other companies also were formed to handle the increasing need to
solve water problems in oil wells.
CHEMISTRY AND CHARACTERISTICS
OF
OILWELL CEMENTS
In a broad sense, the word cement denotes any kind of adhesive, whereas in the
building industry it denotes a substance utilized to bind together sand and broken
62
stone (or other forms of aggregates) into a solid mass. Concrete, mortars, and
various kinds of asbestos-cement products are produced in this manner (see Taylor,
1964).
Hydraulic cement was used to construct early Roman marine docks and facilities
found in the Mediterranean area. Such materials were composed of silicate residues
from volcanic eruptions blended with lime and water (see Taylor, 1964).
The cement composition is often referred to as hydraulic because cement
hydrates when mixed with water (into a paste). Then it sets and hardens as a result
of chemical reactions between the water and compounds present in the cement. The
setting and hardening times do not depend on drying out
of
the paste, nor do they
depend on processes such as reaction with atmospheric
CO,.
Setting and hardening
occur not only in the presence of air, but also if cement is placed in water. Inasmuch
as the final product has a low permeability and is nearly insoluble in water, under
normal conditions, water does not destroy the hardened material (see Taylor, 1964).
The thick slurry, called “paste”, is formed by mixing a hydraulic cement, rock
aggregate, and water in such proportions that will insure setting (see Taylor, 1.964).
The term paste is also used to denote the resultant material at all stages
of
setting
and hardening. The initial stiffening stage, which usually occurs within a few hours
after mixing the paste, is called
setting,
whereas
hardening
is the stage
of
develop-
ment of strength, which slowly increases over a period of time after the mixing and
Fig.
3-1.
Four stages in the setting and hardening
of
Portland cement: simplified diagrammatic
representation of the possible sequence
of
changes.
(a)
Dispersion of unreacted clinker grains in water.
(b) After
a
few minutes: hydration products eat into and
grow
out from the surface
of
each grain. (c)
After a few hours: the coatings of different clinker grains have begun to join up, the gel thus becoming
continuous (setting). (d) After
a
few days: further development of the gel has occurred (hardening).
(After Taylor,
1964,
p. 21, fig.
6;
courtesy of Academic Press, Inc.)
63
setting of the paste. At ordinary temperatures, portland cement gains strength
quickly during the first 48 hours. Strength then slowly increases for periods of up to
two years after the mixing. Hydration reactions is a collective term for the reactions
that cause setting and hardening. The term
curing
refers to leaving the paste
undisturbed during setting and hardening stages. It can be carried out under various
conditions, i.e., in air, under water, or in saturated steam. In the absence
of
rock
aggregate, cement mixed with water is called
neat cement
paste.
Taylor (1964, p. 4) pointed out that the manufacture of portland type cements
involves heating to partial fusion of (1) limestone,
(2)
clay,
(3)
iron, and (4)
aluminates (see Fig.
3-1).
The resulting
clinker
is then ground and mixed with a
small amount (a few percent) of gypsum. The clinker contains four main phases:
(1)
tricalcium aluminate,
(2)
P-dicalcium silicate,
(3)
tricalcium aluminate, and (4)
ferrite solid solution (Taylor, 1964, p. 4). The resistance to high temperature and
sulfates and the rate of hardening are determined by the relative proportions of the
constituents of the clinker and the particle size (fineness of grinding).
CLASSIFICATION
OF
OILWELL CEMENTS
In the petroleum industry, the portland cement is manufactured to meet specific
chemical and physical standards set up by the API (American Petroleum Institute).
They are published in the API Standards 10A “Specifications for Oil-well Cements
and Cement Additives” (API, 1960). The following standards were described by
Smith (1976) for various cements:
Class
A:
Class A cement is intended for use from surface to a depth of 6000 ft if
special properties are not required for the mix. This class of cement is similar to an
ASTM C150, Type I cement.
Class
B:
Class
B
cement is intended for use from surface to a depth of 6000 ft,
when the wellbore conditions require a moderate to high sulfate-resistant mix. Many
companies manufacture moderate and high sulfate-resistant mixes. This class of
cement is similar to an ASTM C150, Type I1 cement.
Class
C:
Class C cement is intended for use from surface to a depth of 6000 ft,
when conditions require high early strength. This class is available as a moderate or
high sulfate-resistant mix.
Class
D:
Class
D
cement is intended for use at depths ranging from 6000 to
10,000
ft, where moderately high temperatures and pressures exist in the wellbore.
This class of cement is available as a moderate or high sulfate-resistant mix.
Class
E:
Class
E
cement is intended for use at depths ranging from
10,000
to
14,000
ft, where high temperatures and pressures exist in the wellbore. This class of
cement is available as a moderate or high sulfate-resistant mix.
Class
F:
Class
F
cement is intended for use at depths ranging from
10,000
to
16,000 ft, where extremely high temperatures and pressures exist in the wellbore.
Ths class of cement is available as a high sulfate-resistant mix.
Class
G:
Class
G
cement is intended for use as a basic cement from surface to a
64
depth of
8000
ft as manufactured. On using accelerators and retarders, this cement
can be easily modified to be used at a wide range of depths and temperatures.
Except calcium sulfate, water,
or
both, no other materials can be interground or
blended with the clinker during the manufacture of Class
G
cement. This class of
cement is available as a moderate
or
high sulfate-resistant mix.
Class
H:
Class
H
cement is intended for use as a basic cement from the surface to
a depth of
8000
ft
as manufactured. Accelerators and retarders enable its use at a
wide range of depths and temperatures. Except calcium sulfate, water, or both, no
other materials can be interground
or
blended with the clinker during manufacture
of Class H cement. It is available as a moderate sulfate-resistant mix.
SPECIALTY
OILWELL
CEMENTS
Smith (1976, p. 9) described a variety of cements, modified by the addition of
additives, which do not fall in any specific API
or
ASTM classification. These
materials may or may not be sold under a recognized specification and their quality
and uniformity are generally controlled by the supplier. They include:
(1)
pozzo-
lanic-portland cements, (2) pozzolan-lime cements, (3) resin
or
plastic cements,
(4)
gypsum cements,
(5)
diesel oil cements, (6) expanding cements, (7) refractory
cements,
(8)
latex cements, and (9) cement for permafrost environments (Smith,
1976).
In
addition, a few cements have been developed for use in geothermal wells
(Rieke and Chilingar, 1982; Shryock, 1982).
Extensive research work is being conducted on identifying, evaluating, and
selecting high-temperature well cementing materials. These include:
(1)
PC contain-
ing crosslinked mixtures of styrene (St); acrylonitrile (ACN); and acrylamide (As),
(2)
organosiloxanes, and (3) portland cement combined with silica sand and
vinyl-type monomers, such as methacrylate (MMA) and St, to form PC.
As pointed out by Shryock (1982, p. 313), cements exhibiting strength retrogres-
sion contain two hydration products: calcium hydroxide and dicalcium silicate
alpha-hydrate.
To
eliminate the retrogressive characteristic at high temperatures, a
finely-divided silica is added to portland cements (30-60% by weight of the cement).
The “silica
flour”
initially reacts with Ca(0H) to form dicalcium silicate alpha-hy-
drate, which converts to tobermorite at elevated temperatures (Shryock, 1982, p.
31
3).
The tobermorite group of calcium silicate hydrates provides the temperature
stability, i.e., high compressive strength and low cement permeability are maintained
at high temperatures.
Pozzolanic
cements
Pozzolans include any siliceous material (processed or unprocessed) that in the
presence of lime and water develops cementing qualities. They can be divided into
natural (mostly of volcanic origin) and artificial pozzolans. The artificial pozzolans
are mainly obtained by the heat treatment of natural materials such as clays, shales,
and certain siliceous rocks (Smith, 1976).