Chilingarian G.V. et al. Surface Operations in Petroleum Production, II
Подождите немного. Документ загружается.
5
6
where
GLR
=
gas/liquid ratio in Mcf/bbl,
q,
=
gross liquid production rate in
bbl/day,
C
=
constant
(
=
600
for units presented in
this equation), and
d,
=
diameter of the choke in
1/64
in. units. Gilbert (1954) developed the following
equation for the Ten Section Field in California
(
ptbg
is in psig):
ptbg
=
435(GLR)0’546(ql)/(dc)1’89
The severity of choke distortion due to (1) gas cutting, (2) sand cutting, and (3)
asphalt and/or waste deposition can be checked by using production data and eqs.
1-1
and 1-2. Equation
1-1
should yield a value of
600
for C, whereas eq. 1-2 should
yield a value
of
about 435 for
C.
One can also use Gilbert's nomogram (Fig. 1-3) for solving choke problems. The
nomogram is entered at the top of left-hand chart (bbl/day). Upon dropping
vertically to a given gas/liquid ratio (Mcf/bbl), one moves horizontally to the heavy
line
on
the right-hand chart (10/64 in. bean size). Then moving vertically to the
existing bean size, one can read the
ptbg(7'HP)
at the left-hand ordinate of the
right-hand chart. Equation
1-1
gives almost the same answer.
The reader
is
referred to Nind's (1981) book entitled
Principles
of
Oil Well
Production
for a detailed treatment of choke performance. This book belongs
on
the
bookshelf of all petroleum engineers.
Throttling effect (gas condensate)
The Joule-Thomson (throttling) effect is an irreversible adiabatic process which
occurs by using pressure-reducing choke
on
a high-pressure gas condensate stream.
The heat content of the gas remains constant across the choke, as the pressure and
temperature of the gas stream are reduced (see Katz et al., 1959). These chokes are
mounted at the inlet of the high-pressure separator to remove the hydrates which
form downstream of the choke due to the reduction of temperature and pressure.
Hydrates [methane (CH,
.
7H20),
ethane
(C,H,.
8H20),
propane (C,H,. 18H20),
and carbon dioxide
(C02.7H20)]
are blown into the separator and fall to the
settling section. Liquid heating coils located at the bottom
of
the separator melt the
hydrates. For comprehensive treatment of the subject, the reader is referred to the
excellent book by
Ikoku
(1984), entitled
Natural Gas Production Engineering.
SUBSIDENCE
In many areas, upon production
of
oil and gas with consequent reduction in pore
pressure,
pp,
the grain-to-grain (effective) pressure,
p,,
increases. The latter causes
compaction
of
both clays and sands, with consequent subsidence of the land. This
can cause serious damages to the surface structures and subsurface installations.
Consequently, it is imperative to develop techniques for predicting subsidence-prone
areas. One such tentative method was proposed
by
Chilingarian et al. (1985), using
shale resistivity ratio,
rsh
=
[
R,,(normal)/R,,(observed)] (see Fig. 1-4). This ratio is
7
I
w-
t-
.......
.
........
.......
\
n-
-.
.‘a,.
Ib)
......
SHORT
NORMAL
RESISTIVITY
RSh
-+
Fig.
1-4.
An example
of
a
shale resistivity profile. Numbers designate the resistivity ratio: (a)
rSH
<
1.5,
not prone to subsidence, (b)
rSH
=
1.5-2.9, slightly prone to subsidence,
(c)
rsH
=
2.9-4.0, strongly
subsidence prone, and (d)
rSH
2
4.0,
extremely prone
to
subsidence. (After Chilingarian et al.. 1985;
Courtesy of Energy Sources.)
a good indicator of undercompaction and was correlated with compressibilities
of
unconsolidated sands associated with undercompacted shales. The use of other
formation evaluation logs, such as sonic
logs,
is also recommended.
In subsidence areas, studied by Sawabini et al. (1974) and Chilingarian et al.
(1985), the effective pore volume compressibilities of unconsolidated sands
ranged from
1
x
lop3
to
1
x
psi-’, whereas bulk volume compressibilities
ranged from
5
X
psi-’, in the
0
to 4000 psi effective pressure
range (that is,
pe =pt -pp,
where
pt
is the total overburden pressure and
pp
is the
pore pressure; effective pressure,
pe,
is sometimes called grain-to-grain stress,
pg
).
Resistivity ratio,
rSh,
of associated shales ranged from
2
to 4.
A
considerable amount
of statistical and experimental research work, however, needs to be done in this
area.
The reader is referred to a comprehensive treatment of the subject by Rieke and
Chilingarian (1974), Sawabini et al. (1974) and Chilingarian and Wolf (1975, 1976).
to
4
X
SAMPLE PROBLEMS AND QUESTIONS
(1)
Determine
ptbg(THP)
given the following information:
q
=
150
bbl/day
(gross),
GLR
=
800
cu
ft/bbl,
and
d,
(bean size)
=
16/64 in.
8
(2) Give and discuss various formulas used for determining bulk and pore volume
compressibilities.
(3) Plot bulk compressibility
(
cb)
versus effective pressure
(
p,)
on log-log paper
given
the
following experimental data
on
saturated montmorillonite clay. Uniaxial
compaction apparatus (thick-walled cylinder with two pistons) was used.
Pressure Moisture content (water)
(Psi)
(Sa
dry weight basis)
1000
50
2000
5000
10,000
30,000
40,000
60,000
100,000
190,000
200,000
45
37
32
22
20
18
14
11
8
(4)
In a subsiding area with a thick sand-shale sequence, does shale or sand
compact more? Explain, with presentation of factual data.
(5)
'
Determine the time necessary to fill
a
cylindrical tank
(10
ft
high
and
5
ft in
diameter) shown in the figure below
(Fig.
1-5).
Water
flows
into the tank at a rate of
1.25
cu ft/sec.
A
3-in. hole
is
open at the bottom of the tank.
-
I
..
I
I,-
Fig.
1-5.
Schematic diagram
for
solving sample problem
(5).
'
The help extended
by
Serge
Y.
Baghdikian
is
greatly appreciated the
writers.
9
Solution.
(Q,
-
Q2)
dt=A dh
Integrating:
where
t
=
time in seconds,
A,
=
77/4(5)’
=
19.635 ft2,
Q,
=
1.25 ft3/sec,
Q,
=
A2V2
=
A2J28k
=
(3/12)2~/4(J2
X
32.2
X
h
)
=
0.3939fi,
g
=
gravitational accelera-
tion, 32.2 ft/sec2,
H
=
10
ft, and
h
=
head
of
water above the bottom hole in ft.
Thus:
t
=
L1’[19.635/(1.25
-
0.3939fi)I dh
=
49.845I1’dh/(3.173
-
fi)
0
Solving, t
=
24 min 45 sec.
APPENDIX 1.1-GEOCHEMICAL FINGERPRINTING OF NATURAL GAS
DENNIS
D.
COLEMAN
Distinguishing natural gases from different sources is of critical importance to
the petroleum industry and to the general public. Gas which migrates from gas or
oil wells, pipelines, or storage reservoirs can result in a significant
loss
to the owner
or, under some circumstances, can reach the surface or enter public water supplies
and result in hazardous situations. In other cases, gas whch is thought to be a
migrated gas is, in fact, naturally occurring (native) gas. It is, therefore, of prime
importance to be able to distinguish gases from different sources. Geochemical
fingerprinting provides a method of identifying the source of natural gas.
Most commercial deposits of natural gas were formed by thermal decomposition
of buried organic material. The composition of natural gas is a function of the type
of organic material from whch it was formed, the pressure and temperature
conditions which existed at the time of formation, and any changes which have
occurred as a result of migration or mixing with gas from other sources. Because of
the many variables involved in the formation of natural gas, it is very unlikely that
gases from two different sources will have identical compositions. The “geochemical
fingerprint” of the gas can, therefore, be used for its identification.
10
Distinguishing natural gases from different sources may sometimes be accom-
plished using only chemical analyses of the gas. This method is complicated,
however, by the fact that due to differences in the size, mass, and solubility of the
different chemical constituents, the chemical composition of natural gas can change
as it migrates.
A
more definitive method for distinguishing between natural gases
which were derived from different sources is the use of isotopic analysis (see
Coleman et al., 1977; Fuex, 1977; Stahl, 1977; and Schoell, 1980).
Isotopes are different forms of the same element, differing only in the number of
neutrons within their nuclei and thus their mass. Carbon, for example, has three
naturally occurring isotopes, carbon-12, carbon-13, and carbon-14. Carbon-14 is a
radioactive isotope formed in the upper atmosphere by cosmic rays. Carbon-14 is
not present in petroleum or petroleum gases but is present in recent bacterial gases.
Hydrogen also has three natural isotopes, protium (hydrogen-l), deuterium (hydro-
gen-2), and tritium (hydrogen-3). Protium and deuterium are stable isotopes and
tritium is a cosmogenic isotope.
The two stable isotopes of carbon, carbon-12
(”C),
and carbon-13 (I3C), are
present in all organic materials and have average abundances of 98.9 and 1.1%,
respectively. These two isotopes of carbon undergo the same chemical reactions, but
because of the small difference in mass, the reaction rates are sometimes slightly
different.
As
a result, the relative proportions of carbon-12 and carbon-13 may not
be exactly the same in the reaction products as they were in the source materials.
For example, the formation of methane by the thermocatalytic decomposition of
organic material results in methane wluch is depleted in carbon-13 (or enriched in
carbon-12) relative to the original organic material. Once methane is formed,
however, its carbon isotopic composition, or
l3
C/I2 C ratio, is relatively unaffected
by most natural processes.
The carbon isotopic composition of methane in natural gas is a function of the
nature of the source material and the conditions under which it was formed. Unlike
the chemical composition of natural gas, the isotopic composition is relatively
unaffected by migration (Sackett, 1968; Stahl and Carey, 1975; Coleman et al.,
1977; Fuex, 1980; Reitsema et al., 1981; Schoell, 1983). Consequently, the isotopic
composition of methane provides a reliable “fingerprint” for distinguishing natural
gases from different sources.
Coleman et al. (1977) demonstrated that carbon isotope analyses could be used to
distinguish between storage gas and shallow biogenic methane when, due to migra-
tional changes, chemical analyses could not distinguish between the two. In later
studies (Coleman, 1979, 1985), isotopic analysis was effectively used to identify
storage gas which had migrated to nearby oil wells. In recent unpublished studies, it
has been shown that the carbon isotopic composition of ethane and the hydrogen
isotopic composition of methane can also be used to distinguish between storage gas
and native gas.
In distinguishing gases from different sources, one must first establish the
compositional range of gases of known sources (for example, storage gases and
native gases) and determine which chemical and isotopic parameters best differenti-
11
ate these sources. Gases from unknown sources may then be classified as one type
or the other (or as a mixture) based on their chemical and isotopic compositions.
In
some cases it is even possible to determine the relative proportions of two gases
present
in
a mixture.
REFERENCES
Allen, T.O. and Roberts, A.P., 1978.
Production Operations: Well Completions, Workover, and Stimula-
tion,
Vol. 1. Oil and Gas Consultants International, Tulsa, Okla., 225 pp.
Allen, T.O. and Roberts, A.P., 1982.
Production Operations: Well Completions, Workover, and Stimulu-
tion,
Vol. 2. Oil and Gas Consultants International, Inc., Tulsa, Okla., 250 pp.
Chilingarian. G.V. and Wolf, K.H., 1975.
Compaction of Coarse-Grained Sediments,
I
(Developments in
Sedimentology, 18A). Elsevier, Amsterdam, 552 pp.
Chilingarian, G.V. and Wolf, K.H., 1976.
Compaction of Coarse-Grained Sediments,
I1
(Developments in
Sedimentology, 18B). Elsevier, Amsterdam, 808 pp.
Chilingarian, G.V., Yen, T.F. and Fertl, W.H., 1985. New method of predicting subsidence and
subsidence-prone areas.
Energy Sources,
8(1): 77-78.
Coleman, D.D., 1979.
The use of isotope ratios
to
determine the source
of
natural gas above gas storage
reseruoirs.
Paper presented at the Am. Gas Assoc. Oper. Sect. Meet., New Orleans.
Coleman, D.D., 1985.
Applications of geochemistry
to
the production, storage, and utilization of natural gas.
Paper presented at the Am. Assoc. Pet. Geol. Annu. Meet., New Orleans.
Coleman, D.D., Meents, W.F., Liu, C.L. and Keogh, R.A., 1977.
Isotopic identification
of
lenkage gas
from underground storage reservoirs ~a progress report.
Ill. State Geol.
Surv.
Ill. Pet., 10 pp.
Craft, B.C., Holden, W.R. and Graves Jr., E.D., 1962.
Well Design; Drilling and Production.
Prentice-Hall,
Englewood Cliffs, N.J., 368 pp.
Fuex, A.N., 1977. The
use
of stable carbon isotopes in hydrocarbon exploration.
J.
Geochem. Explor.,
7:
155-188.
Fuex, A.N., 1980. Experimental evidence against an appreciable isotopic fractionation of methane during
migration.
Phys. Chem. Earth,
12: 725-732.
Gilbert, W.E., 1954. Flowing and gas-lift performance.
API Drill. Prod. Pract..
p. 126.
Ikoku, Chi U., 1984.
Natural Gas and Production Engineering.
Wiley, New York, N.Y., 517 pp.
Katz, D.L., Cornell, D., Kobayashi, R., Poettmann, F.H., Vary, J.A., Elenblaas, J.R. and Weinaug, C.F.,
Mare, De la, R.F. (Editor), 1985.
Advances in Offshore Oil and Gas Pipeline Technology.
Gulf, Houston,
Nind, T.E.W., 1981.
Principles of Oil Well Production.
McGraw-Hill, New York,
N.Y.,
2nd ed., 391 pp.
Reitsema, R.H., Kaltenbach, A.J. and Lindberg, F.A., 1981. Source and migration of light hydrocarbons
Rieke
111,
H.H. and Chilingarian, G.V., 1974.
Compaction of Argillaceous Sediments
(Developments in
Sackett, W.M., 1968. Carbon isotope composition of natural methane occurrences.
Am. Assoc. Pet. Geol.
Sawabini, C.T., Chilingar, G.V. and Allen, D.R., 1974. Compressibility of unconsolidated arkosic oil
Schoell, M., 1980. The hydrogen and carbon isotopic composition of methane from natural gases
of
Schoell,
M.,
1983. Isotope techniques for tracing migration
of
gases in sedimentary basins.
J.
Geol. Soc.,
Sivalls, C.R., 1977.
Fundamentals of Oil and Gas Separation.
Proc. Gas Cond. Conf., Univ. Oklahoma,
1959.
Handbook of Natural Gas Engineering.
McGraw-Hill, New York, N.Y., 802 pp.
Tex., 383 pp.
indicated by carbon isotopic ratios.
Am. Assoc. Pet. Geol.,
65(9): 1536-1542.
Sedimentology, 16). Elsevier, Amsterdam, 424
pp.
Bull.,
52: 853-857.
sands.
SOC.
Pet. Eng.
J.,
14(3): 132-138.
various origins.
Geochim. Cosmochim. Acta,
44: 649-661.
140(3): 415-422.
Norman, Okla.
12
Stahl,
W.,
1977. Carbon and nitrogen isotopes in hydrocarbon research and exploration.
Chem.
Geol.,
20:
Stahl,
W.
and Carey,
B.D.,
1975. Source rock identification by isotope analyses of natural gases from
121-149.
fields in the Val Verde and Delaware basins, West Texas.
Chem.
Geol.,
16: 257-267.
13
Chapter
2
FLOW
RATE MEASUREMENTS
THOMAS R. SIFFERMAN
WITH APPENDIX BY
L.J.
KEMP AND GEORGE
V.
CHILINGARIAN
INTRODUCTION
Main
types
of
meters
The main types of flow rate meters in the oil industry include the turbine meter,
the positive displacement meter, and the orifice meter. The first two types are
typically selected for liquid flow rate measurement, whereas the orifice meter is used
primarily for gases. Both the turbine meter and positive displacement meter,
however, can be used for gases, and the orifice meter can also measure liquid flow
rates.
The turbine meter measures flow rate (instantaneous or cumulative) by convert-
ing liquid velocity into rotational velocity. A turbine (a propeller-like device) rotates
on a shaft. The speed of the turbine is proportional to the linear velocity (or flow
rate) of the fluid moving through the meter. The speed of the turbine is measured as
pulses that give the instantaneous flow rate. The pulses can also be accumulated to
give the total or cumulative flow rate.
A
positive displacement meter measures instantaneous or cumulative flow rate by
counting the number of
“
volumes” through the meter. The
“
volume” is based on a
selected geometry
so
that a constant, exact amount of fluid
is
trapped for each
count of the meter.
The orifice meter is a differential pressure device that produces a flow rate that is
proportional to the square root of the pressure drop across the orifice. Physically,
the device involves an orifice plate, pressure taps, and a holder for the orifice plate.
A
transducer, transmitter, or recorder converts the differential pressure into an
indication of flow rate.
DEFINITIONS
In order to have a common base for comparison of meters, definitions for
accuracy, rangeability, repeatability, and linearity are presented below. Often accu-
racy and linearity are interchanged, or linearity is quoted for a specified accuracy
band.
Accuracy
Accuracy is a measure of the ability of a flowmeter to indicate the actual flow
rate within a specified flow rate range. It is the difference between the actual and
14
measured flow rates divided by the actual flow rate. For a 100 gpm (gal/min)
flowmeter, a
kl%
of full scale accuracy would mean the measured flow rate is
within
kl%
gpm of the actual flow rate at any flow rate; i.e., 9-11 at 10 gpm,
49-51 at 50 gpm, and 99-101 at 100 gpm.
On
the other hand,
+I%
of reading
means that the flowmeter is within kO.1 gpm at 10 gpm,
f0.5
gpm at
50
gpm, and
k1
gprn at 100 gpm, i.e., 9.9-10.1 at 10 gpm, 49.5-50.5 at
50
gpm, and 99-101 at
100 gpm. The percent of reading, therefore, gives much better results throughout the
range, except for the full-scale readings where the results are the same.
The accuracy expressed as the percent of full scale (flow rate) is usually used for
orifice meters, magnetic flowmeters, and variable-area meters. The accuracy ex-
pressed as the percent of actual reading is normally used for positive displacement
and turbine meters. Some meters, such as mass flow meters, may use either, both, or
a combination of these two methods of expressing accuracy in their specifications.
Rangeability
Rangeability is the ratio, at the specified accuracy, of the maximum flow rate to
the minimum flow rate. It is usually reported as
x
:
1, where
x
is the maximum limit
divided by the minimum limit. If the maximum flow rate is 100 gpm and the
minimum is 10 gpm, the rangeability would be
10:
1.
It
is
important to know not
only the rangeability, but also the flow rate range over which it applies. One
company could quote a 10:
1
rangeability (3-30 gprn), whereas another company
could quote 15
:
1, just by decreasing the lower limit by
1
gpm (now 2-30 gprn). A
more dramatic change,
of
course, would be 3-45 gprn for the 15
:
1
rangeability.
Repeatubility
Repeatability is the ability of a meter to reproduce the same measured readings
for identical flow conditions over a period of time. It is, therefore, sometimes called
the reproducibility and is generally expressed as the maximum difference between
measured readings. Repeatability can be expressed as a percent of full scale flow
rate. An instrument may have a very good repeatability, but
a
lower overall
accuracy. If the flowmeter operates over a small range
of
flow rates, however, the
high repeatability can be used to give very good indications of actual flow rate.
Linearity
Linearity is a measure of the deviation
of
the calibration curve from a straight
line. It is usually specified over a given flow rate range or at a given flow rate.
Inasmuch as linearity can be reported as a percent
of
full scale flow rate, it is
important to note the conditions. Sometimes, the flow rate range is given over which
the flow meter remains withm stated linearity limits. Actually, a flowmeter could
have a good linearity, but a poor accuracy. That is, its calibration curve could be
linear but shifted (offset) higher or lower than the correct actual readings.