Note: Descriptions are shown in the official language in which they were submitted.
i~77939
METHODS AND APPARATUS FOR SEPARATING GASES
AND LIOUIDS ~ROM NATURAL GAS WELLHEAD EFFLUENT
Field of the Invention
This invention relates generally to the separation of
gases and vapors from the liquids present in the wellhead gas
effluent from natural gas wells. In particular, this invention
relates to a method and apparatus for improving the production
of sales gas from relatively low volume natural gas wells by the
use of compression.
Background
As described in my prior applications, many natural gas
wells produce a relatively high pressure, high volume well
stream effluent containing significant volumes of high vapor
pressure condensates which will normally contain absorbed and
dissolved natural gas, propane, butane, pentane and the like.
Currently these liquid and dissolved hydrocarbons are only
partially recovered by conventional, high pressure,
JJ:~t~ 1
A
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~277939
separator units. The liquid hydrocarbon by products normal-
ly removed from the well stream by a high pressure separator
unit, are collected and then typically dumped to a low pres-
sure storage tank means for subsequent sale and use. A
05 substantial amount of dissolved gas and high vapor pressure
hydrocarbons re~ain in the liquid hydrocarbon by-products.
Substantial amounts of these gases and hydrocarbons may
vaporize by flashing in the storage tank due to the substan-
tial reduction in pressure in the tank which permits the
volatile components to evaporate or off-gas into gas and
vapor collected ~n the storage tank over the condensate. In
this manner, substantial amounts o gas and entrained liquid
hydrocarbons are often vented to the atmosphere to reduce
storage tank pressure and are wasted. ln addition to this
initial vaporization and loss, further evaporation occurs
when the condensate stands for a period of time in the
storage tank or when the condensate is subsequently trans-
ported to another location or during subsequent storage
and/or proces6ing. ~hi6 is described in the industry as
weathering. Many users of the conden6ate specify particular
low vaporization pressure requirements for such condensate;
and the 6alability and value of the condensate depends upon
the characteri6tics of the condensate. Thus, natural gas 1
wells, which produce significant amounts of high vapor
pressure condensates along with the natural gas, present a
great opportunity~for improvement in production methods
including a reduction in discharge to the environment and
economlc gain by recovery of otherwise wa6ted by-products.
While the apparatus and methods disclosed ih my prior
applications enable enhanced recovery of ~ales gas and
hydrocarbon condensates in relatively high pressure, high
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1;2~W93~
.
volume wells, there i9 a need ~or improved production
apparatus and methods for use with relatively low volume gas
wells, (e.g., 1.5 million cubic feet per day or less). One
of the problems with relatively low volume gas wells is that
05 the pressure differential between shut-in and/or natural
flow pressure of a small volume gas well and the pressure of
the sales gas from other wells in the sales gas pipe line
may be so low as to reduce and/or restrict the volume of
production from the low volume wells because of inability to
establish and maintain flow from the wellhead to the sales
gas pipe line throuqh the production equipment. Another
problem with relatively low volume natural gas wells is that
the natural flow pressure may vary substantially dependlng
upon changes in formation conditions and the amount of
liquid hydrocarbons and water in the well. Removal of
liguid hydrocarbons and water ls dependent upon the rate of
flow of natural gas which may be 60 low in low volume wells
as to prevent removal of sufficient quantities of the liquid
hydrocarbons and water resulting in further reduction in
rate of flow and 60metimes, a well shut down condition which
reguires ~pecial procedures to unload the well to re-
establish natural flow. Thus, it iB desirable to establish
and maintaln sufficient pressure differentials between the
sales gas pipe line pressure, the production eguipment, and
the natural flow pressure of the low volume well to assure
; satisfactory flow from the well into the production equip-
ment and from the production equipment to the sales gas pipe
line. For example, if the sales gas pipe line pressure is
500 psi and the shut-in or natural flow pressure of a low
volume well is only 700 psi or lower, the pressure differen-
tial between the well head and the sales gas pipe line is
~ ` lZ7793~
only 2no psi or lower and may have an adverse effect on the
flow rate from the well head. When the pressure differen-
tial is incrèased, for example, from 200 psi to 500 psi or
more, the resistance to flow from the well head is reduced,
05 and the volume and rate of gas flowing from the low volume
well to the sales gas pipe line may be substantially in-
; creased.
The construction of apparatus and utilization ofmethods of processing natural gas wellhead effluent at the
well site requires consideration of a multitude of factors
which are unique to variable condition~ at the wellhead
site. Fir~t, many wellhead sites are located in remote
areas where there are no on-site operating personnel and
which are not readily accessible by remotely located operat-
ing personnel. Second, many wellhead sites are located ingeographical areas subject to extreme changes in climatic
conditions from a winter period with ice, snow and extremely
low temperature conditions (e.g., 32 degrees F to -50
degrees F) to a summer period with extremely h~gh tempera-
ture conditions ~e.g., 90 degrees F to 120 degrees F).
Thus, while environmental conditions may be controlled at
central processing and production plants, environmental
conditions at a natural gas wellhead site are generally 1
uncontrollable and processing and production equipment at
the wellhead site are subject to extreme environmental
conditions without constant availability of on-site mainten-
ance and operating service personnel. Thus, an important
~' consideration feature and object of the present invention is
to provide reliable, 6ubstantially maintenance free and
service free production apparatus and methods which are
usable at a wellhead site. Some types of oil-gas production
127~
apparat~s and methods which may be satisfactorily operated
in a controlled environment at a central production facility
cannot be reliably operated at a wellhead site. Thus, the
design of on-site wellhead production equipment and proce~s-
05 es requires consideration of many factors which are notapplicable to central production facilities.
The terms, gaseous hydrocarbon hydrate temperature and
the like, as used herein, are known terms of art which mean
a relatively low temperature at which gaseous hydrocarbons
form a porous solid. This solid is crystallized in a cubic
structure in which gas molecules are "trapped" in cavities.
Hydrates are capable of blocking flow of gaseous hydro-
carbons in a processing system. The formation of such
hydrateB i8 a function of the kind of hydrocarbon, associ-
ated free water and pressure and temperature conditionsthereof. Exemplary known hydrate temperatures are shown in
various prior art publications. The systems of the present
invention are designed to operate at temperatures above
gaseous hydrocarbon hydrate temperatures.
In general, the low pre6sure and high pressure separa-
tor means of the present invention comprise a vessel (tank)
of any size or shape mounted in either a vertical or hori-
zontal attitude and designed and constructed and arranged to
operate at suitable pre~sures and at elevated temperatures
in excess of process gas hydrate temperatures. Fluids in
such vessels are primarily mechanically separated into
gaseous and liquid phases by change of direction of flow,
decrease in velocity, scrubbing, etc. in a two-phase (gas-
eous/liquid separation) or three-phase (gaseous/liquid
separation and then water-hydrocarbon liquid separation).
Suitable level controls, motor valves, temperature
controllers, etc. are utilized to maintain the desired
continuous process conditions.
Brief Invention Summary
The apparatus and methods of my prior applications
05 provide for enhancing the overall production of natural gas
wells by the use of multiple stages of gas-liquid separation
in a process wherein the pressure on the condensate is
reduced in a manner that increases the recovery of absorbed
gases and vapors before the transfer of the remaining liquid
to a storage tank at nearly atmospheric pressure, and
lncludes compressing the gases and vapors recovered from
separation stages, and then reintroducing these recovered
components back into the wellhead stream, under specific
predetermined conditions, which also enhances the recovery
of both lighter and heavier hydrocarbon components which
might otherwise be wasted. Compressor means are employed to
receive and compress by-product gas from separator means
provided in the system, and for subsequently injecting com-
pressed gases and vapors into the wellhead gas stream at a
predetermined location for recycling under conditions which
facilitate enrichment of the volume, composition and B.T.U.
content of the sales gas stream as well as liquid hydro-
carbon recovery. In one embodiment, an intermediate staging
. separator may be employed which, in a preferred embodiment,
may, in addition contain heat exchanger means whereby some
; of the heat of compression imparted to the compressed gases
; and vapors by the compressor means is used to maintain a
predetermined temperature in the staging separator.
In general, the presently disclosed system enables
processing of effluent from a low volume natural gas
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1Z7793a9
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wellhead as discharged at the wellhead site at wellhead dis-
charge pressures and temperatures, the effluent constituents
comprising light end and heavy end hydrocarbons and water in
gaseous, liquid and vapor phases, to remove water and heavy
05 end hydrocarbons from the effluent and to provide an in-
creased volume of sales gas containing primarily light end
hydrocarbons in a stable gaseous phase and to provide heavy
end hydrocarbons in a relatively stable liquid phase without
I substantial loss of either of the light end hydrocarbons or
the heavy end hydrocarbons during processing of the efflu-
ent. In one embodiment, the apparatus comprises a three
phase low pressure primary separator means for continuously
receiving the wellhead effluent and for continuously separat-
ing the effluent into (l) a first relatively low pressure
body of gaseous light end hydrocarbon constituents and (2)
into a liquid body of water constituents and (3) into a
first liquid body of residual hydrocarbon constituents
including a minoral residual portion of the light end hydro-
carbon components and a majoral residual portion of heavy
end hydrocarbon components in liquid and vapor phases. A
compressor means is located downstream of the primary
separator means for reducing the working pressure in the
primary separator means while continuously inducing a flow 1,
of gaseous hydrocarbon constituents from the primary separa-
tor means and increasing the pressure thereof by compressionin the compressor means. A two phase high pressure secon-
dary separator means is located downstream of the compressor
means for continuously receiving the relatively high pres-
sure gaseous and residual hydrocarbon constituents from the
compressor means at a relatively high pressure and for
causing separation of the residual hydrocarbon constituents
to provide a second body of relatively high pressure residu-
al gaseous light end hydrocarbon components of sales gas
quality and a second liquid body of residual heavy end
hydrocarbon components. The second body of res'idual gaseous
05 hydrocarbon constituents contains primarily light end hydro-
carbon constituents with a minority of heavy end hydrocarbon
constituents therein and i8 discharged to the sales gas line
at a relatively high pressure approximately equal to the
sales gas line pressure.
The inlet suction port of the compressor means is
connected to the low pressure primary separator means to
establish and maintain a substantial constant flow rate of
effluent to and separated gas from the low pressure primary
separator means. The discharge port of the compressor means
is connected to the high pressure secondary separator means
through heating coil means in the low pressure primary
separator means so that the heat of compression in the
compressed gas is used to heat the low pressure primary
separator means. Cooling means are employed to cool the
compressed gas prior to entry into the high pressure secon-
dary means wherein additional residual heavy end hydrocar-
bons are removed from the gas prior to delivery to the sales
gas line. A condensate sump means in the high pressure l~
secondary separator means is mounted in the low pressure
primary separator means in heat transfer relationship with
the condensate liquids collected in the low pressure primary
separator means. The condensate liquids from the high
pressure secondary separator means collected in the sump
means are dumped into and mixed with the condensate liquids
in the low pressure primary separator means for recycling
therein. A natural gas powered engine means drives the
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~i27793~
I
compressor means and the engine coolant system may include
circulation lines located in the low pressure primary
separator means in heat transfer relationship with the
condensate liquids therein. The compressed gas cooling
05 means may be a forced air-engine radiator apparatus associa-
ted with the engine means. Fuel gas for the engine means
and control gas for system control devices are derived from
the sales quality gas produced in the high pressure secon-
dary separator means. A suction scrubber means may be used
between the low pressure primary separator means and the
compressor means to remove additional heavy end hydrocarbons
and water in the gas prior to delivery to the compressor
means. The system apparatus i8 mounted on a portable
platform mean~.
Brief DescriPtion of the Drawinq~
Presently preferred and illustrative embodiments of the
invention are shown in the accompanying drawings wherein:
Fig. 1 is a schematic flow diagram of a system of the
prlor applications for separating gases from the condensible
liquids present in natural gas wellhead effluent.
Fig. 2 is a partial flow dlagram of the heater, high
pressure separator, and staging separator apparatus used in
a system of the prior application~.
Fig. 3 is a schematic drawing of a typical, single,
high pressure gas-liquid separator process which does not
employ the present invention.
Figs. 4 and 4a are a schematic drawing of one embodi-
ment of a system employing methods and apparatus of the
prior applications.
, I
~77~39 `:
Figs. 5A and 5B are a schematic drawing of an illustra- ~
tive embodiment of the present lnvention as applled to a low j~;!'
volume well head.
Fig. 6 is a plan view of apparatus illustrated in Figs.
05 5 and 5a: and ' ~~
Fig. 7 is a side elevational view of the apparatus of `~
Fig. 6. t~
: .
Detailed Descrlption of Fiqs. 1-4
A gas-llquid separation apparatus and method of the
prior applications is shown schematically in Figs. 1 and 2, i~;
with a conventlonal heater means 2 having a heat exchanging
tube coil means 4 into which the gaseous product from a
wellhead are introduced from an lnlet condult 9. The
wellhead gases are conveyed via interconnected gas heating
coil means 4 and 6, which are immersed in an,indirect
heating medium 3, such as a glycol and water solution in
heater 2. A pressure reducing choke valve means 5 is -
inserted in the pipe connecting gas heating coils 4 and 6,
and is used to reduce the wellhead pressure to a pressure
compatible with the operating pressure of a conventional
three phase high pressure primary 6eparator means 20 and the
sales gas line 26. The heating medium 3 can be heated by
means of a conventional fire tube heater shown at 10. The
temperature of fire tube heater 10 is controlled by means of ~i
a thermostatically controlled gas supply valve 11 connected ~ir
1 to a gas burner unit 12, and the heater 10 is connected to a ,~
flu 13.
Heating coil 6 is connected to high pressure separator ;~
20 by means of a pipe 21. This high pressure separator 20 C~i
operates to mechanically ~eparate gaseous and liquid ,`
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_~ 127793~
components of t~le well stream at a predetermined elevated
operating temperature and pressure as is well known ln the
art. Typically the gas-liquid mixture introduced into hlgh
pressure separator 20 will be at a pressure of from about
05 1,000 psig to about 400 psig and temperature of from about
; 70 degrees F (22 degrees C) to about 90 degrees F (33
degrees C). The valve 22 is controlled by the liquid level
inside the high pressure separator 20 such that when the
liquid level of the liquid hydrocarbons reaches a prede-
termined height, the valve 22 will be opened drawing off the
liquid under the pressure of the gaseous component by means
of pipe 25 which transmits the liquid component to another
conventional separator means such as an intermediate pres-
sure staging separator 30. The gaseous sales gas components
are removed from the high pressure separator by means of
pipe 26, and are subsequently sold after further processing,
if necessary. The sales gas may advantageously be further
dried by the removal of water using for example, a conven-
- tional glycol dehydration sy6tem. Liquid water collected in
separator 20 is removed through a pipe 31 in a conventional
manner. The intermediate pressure or staging 6eparator 30
iB generally operated at pressures of less than about 125
psig. Most of the absorbed natural gas and some of the 1
higher vapor pressure components of the condensates removed
from the high pressure separator 20 will be flashed from the
liquid phase into the vapor phase in the intermediate
pressure separator 30. As shown in Fig. 2, the intermediate
pressure separator 30 consist~ of a tank 35, a water dump
line valve 36, an oil (condensate) line dump valve 37, an
oil liquid level control and water liquid level control (not
shown), a thermostat 39, a heat exchange coil i4, a bypass
11 -
1277~3~9
line 32, and a three way temperature splitter valve 33, as
well as safety and control monitoring devices such as gauge
glasses, safety release valves and the like. The oil dump
valve 37, which operates in response to the oil liquid level
OS control (not shown), passes oil from the intermediate
pressure separator 30 via pipe 44 into a conventional
storage tank means 50, (shown in Fig. 1). The primary
function of the intermediate pressure separator 30 is to
flash at a higher than atmospheric pressure most of the
absorbed natural gas and high vapor pressure components of
the condensates into a vapor phase. The flashed gases are
removed from intermediate pressure separator 30 by means of
a pipe 40 through a back pressure valve 41 and conveyed
through a conduit 42 into a multiple stage compression
system 46, shown in detail in Figs. 4 and 4a.
Residual hydrocarbons in the gas stream produced in the
- secondary separation means 30 and compressed in the com-
pression system 46 are recycled by delivery from the com-
pression system to the heated wellhead effluent stream by
conduit means 92, 94 which may include heat exchanger and
valve means 32, 33, 34 in secondary separator means 30. In
thls manner, all residual llght end hydrocarbons not re-
leased to the sales gas stream in primary separator 20 are
further processed in secondary separator means 30 which
provides a liquid body of hydrocarbon~ substantially free of
light end hydrocarbons for delivery to the storage tank
means 50 while producing a secondary gaseous 6tream of
; hydrocarbons which is recyclable after passing through the
compression system 46 as hereinafter described.
; 30 The liquid conden6ate storage tank 50 operates at
nearly atmospheric pressure. The further pressure reduction
12
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- - \
from the pressure in the intermediate pressure separator 30
will permit some further flashing of the hydrocarbons to
occur as the pressure is reduced. A pressure relief valve
51 as shown in Fig. 1, is provided for pressure control on
05 the storage tank 50. Condensate is selectively removed from
storage tank 50 through discharge pipe 52. The flashed
gases and vapors are removed from storage tank 50 by means
of a vent pipe 55. Fig. 3 shows a typical conventional
system whereln heavy end condensate (oil) is directly de-
livered from high pressure separator means 20 to storagetank means 50 in a relatively un6table condition with re-
sulting loss of substantial amounts of light end hydro-
carbons.
As shown in Fig. 4a, multiple stage compres6ion sy6tem
46 comprises a series of conventional compressor cylinder-
piston units 60, 62, 64 driven by conventional motor means
66 through 6uitable drive mean~ 66a, 66b, 66c. Gaseous
hydrocarbons in low pres6ure 6eparator 30 are delivered to
flrst stage compressor unit 60 through line 42 and com-
pressed therein to raise the temperature and pressurethereof. The compressed ga6eous hydrocarbons are then
delivered to the second stage compre6sor unit 62 throuqh a
line 68, a conventional forced draft intercooler unit 69, I~
including an inner-stage separator and a line 70. The
gaseous hydrocarbons are again compressed in compressor unit
62 and then delivered to third stage compressor unit 64
; through a line 71, a second forced draft intercooler unit
72, including an inner-stage separator and a line 73. The
intercooler units 69, 72 cause reduction of temperature of
30 the relatively high pressure high temperature gaseous
hydrocarbons resulting ln the recondensinq and then removal
1.2779~
of additional liquid heavy end hydrocarbons which are
delivered to the low pressure separator 30 or condensate
tank 50 through suitable line means (not shown). The
remaining relatively high pressure high temperature gaseous
05 hydrocarbons are delivered indirectly from the final com-
pressor unit 64 to heater unit 2 (Fig. 4) between choke
valve 5 and heating coil 6 through discharge lines 92, heat
exchanger means 34, line 94, and/or directly through bypass
line 76 as determined by temperature controlled splitter
valve means 77. Water collected in separator 30 i8 removed
in a conventional manner through discharge line 31. The
multiple stages of compression provided by compression
,, system 46 may be used to compress the gas up to the pressure
oS the gas line immediately downstream of the choke valve 5
in the heater 2. Preferably the compressed gases are trans-
ferred, as by line 92, shown in Fig. 2, to heat exchanger 34
in the staging separator 30 to recover some of the heat of
compression to heat the fluids in the staging separator for
greater gas and vapor recovery from the separated liquids in
the staging separator before the liquids are discharged to
the storage tank 50. Most preferably the compressed gases
from the transfer pipe 92 are introduced into the three way
temperature control splitter valve 33 or 77 which is exter-
1~
nal of the staging separator 30. The three way splitter
valve 33 controls the introduction of the high pressure and
: high temperature compressed gases from the compressor means
by means of a thermostat 39 which senses the temperature of
the liquids contained in the separator 30. The three way
splitter valve 33, receiving the gases and vapors from the
Iast stage of the compressor means diverts the high pres-
sure, high temperature gases either directly to heat
exchanger 34, inside the staging separator 30, when re- ~-
quired, or bypasses the heat exchanger 34, depending on the k
conditions required in the intermediate pressure separator
30, and then through transfer line 94 for reintroduction of
OSthe gas and vapor into the gas heating coil 6 contained in
heater 2 at a point downstream of choke valve 5. The heat .`
from the heated liquids in the staging separator may be used ~
to raise the temperature of the liquids going to the staging ~-
separator from the high pressure separator and to cool the ~.
liquids yoing to the storage tank 50 by providing a heat .
exchanger 93, Fig. 4, between these two lines.
.:
petailed DescriPtion of Fiqs. 5-7 ~
. r
Figs. 5A, 5B and 6 and 7, show a production system for a .~7'"
low volume well comprising a three phase low pressure
; primary separator means 100 of generally conventional ~-
construction, a compressor means 102 operable by a conven- ~?
~; tional gas driven engine means 103, and a two pha6e high
pressure secondary separator means 104 of generally conven-
tional construction. Wellhead effluent i5 delivered to low
pressure separator means 100 from a wellhead inlet line 106
through a high pressure shut-off control valve 107 for first I 1
stage separation of gaseous and liquid hydrocarbon and water
components and production of a first stage gaseous stream ~;
~ delivered to the suction ports 108a, 108b of compressor
: means 102 from a dome means 109 having a mist extractor
means lO9a through a line lO9c, a scrubber means 110 having
a mist extractor means llOa and lines 111, 112. Compressor
means 102 compresses the first stage gaseous stream and
discharges a compressed gaseous stream from outlet ports
lms~s
113, 114 to a line 115 for delivery to a heating co~l means
116 in separator means 100 through an inlet port 118. A
conventional splitter valve means 120 i5 connected to line
115 through a by-pass line 121, to heating coil means 116
05 through an outlet line 122 and to a discharge line 123 to
enable separator temperature controlled variable flow of
compressed gases from inlet line 115 to outlet line 123
through heating coil means 116 and/or to outlet line 123
through heating coil bypass line 121. Compressed gases in
line 123 are delivered to a forced draft cooler means 126,
including a radiator-type heat exchanger means 127 and an
engine driven fan means 128, for cooling the compressed
gases prior to delivery to the high pressure two phase
secondary separator means 104 through a line 130. Separator
means 104 provides a second stage, two phase separation
process for the compressed gases to produce a body of
residual liquid hydrocarbon components and sales quality
body of gases delivered to the sales gas line through an
outlet line 131 and a check valve means 132.
Separator means 104 comprises a liquid hydrocarbon
collection tank means 140 with a lowermost portion 141
extending into separating means 100 for partial immersion in
the liquids contained therein. A conventional liquid level
control means 142 and a conventional dump valve means 144
are associated with tank means 140 for returning second
stage liquid hydrocarbons to the first stage separator means
100 for recycling therein through a line 146. A conven-
tional supply gas dryer means 148, for removing water and
hydrocarbons in vapor phase by ambient cooling, provides
system fuel and control supply gas to a line 150 connected
: through a heat exchange means 152, mounted in separator
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39
means 100, a line 154, a conventlonal pressure regulator
means 156, and a line 158 to a conventional drip pot means
160, for removal of liquids, having a conventional high
level shut down control valve means 161.
05 Fuel supply gas is delivered from drip pot means 160 to
engine means 103 through a line 162 and a conventional fuel
gas volume pot means 163, for holding a relatively large
volume of pressure regulated gas, having variable pressure
chambers 163a, 163b and associated pressure control valve
means 164, 165. Engine starter gas is delivered to a
conventional starter engine (not shown) from a high pressure
side 163a of pot means 163 through line 166 including a
starter valve means 167 and a starter oil lubricating means
168. Engine running gas is delivered from a low pressure
side 163b of fuel pot means 163 through a line 169 lncluding
a fuel shutdown safety valve means 170.
Control supply gas is delivered from drip pot means 160
through a conventional pressure regulator means 171 and
lines 172 to various conventional gas-operated control
; 20 devices including pressure control valve 107 and associated
controller 174, splitter valve 120 and associated thermo-
static control 175, liquid level control valve 142 and dump
valve 144, low pressure separator liquid level control 1,
I valves 177, 178 and associated dump valves 179, 180, and
scrubber means liquid level control valve 181 and associated
dump valve 182.
Coolant for engine means 103 may be circulated through
~ a line 184, heat exchanger means 185 in pot means 163, a
,. line 186, a heat exchanger means 187 in the low pressure
separator 100, a line 188, a heat exchanger means 189 in
scrubber means 110, and a line 190. In this manner, the
t~
engine coolant may be used to provide heat to the separator
means loo and other apparatus as necessary or desirable. In
addition, the engine coolant system includes inlet and
outlet lines 192, 193, 194, 195 to radiator means 196 of
05 forced draft cooler means 126 for cooling during normal
operation, and further include~ conventional coolant expan-
sion tank means 198 and oil storage tank means 199.
Liquid hydrocarbons collected ln first stage separator
means 100 are delivered in a conventional manner to a
conventional condensate ~torage tank means 200, through a
line 201 connected to level control valve means 180.
Scrubber means 110 Is also connected to the condensate
storage tank means 200 by a line 202. ~ater collected in
first stage separator means loO is removed in a convent~onal
manner through a drainage line 204 connected to level
control valve means 179. Any gases which are vented under
abnormally high pressure operatlng conditions are removed
through a pressure relief control valve means 20,6 and
delivered through a line 207 to vent gas flare means 208 in
a conventional manner. Various conventional pressure and
temperature gauges 209, 210, 211, 212 and pressure and
temperature responsive safety vent and shutdown valve
devices 213, 214, 215, 216, 217, ?18, 219, 220, etc., are l~
employed in the system. Bypass lines such as coolant bypass
line 222 with hand valve 223 between line 188 and line 184
and gas bypass line 224 with a hand valve 225 between line
lO9c and line 115, are provided as necessary and desirable.
- In the illustrative embodiment, the low pressure
separator means comprises an elongated cylindrical tank,
having a 30 inch outside diameter and a length of approxi-
mately six and 1/2 feet which is constructed and arranged
18
for operation at a normal relatively low working pressure ~t
of, for example, approximately 250 psig. The high pressure
separator means comprises an elongated cylindrical tank,
having an outside diameter of approximately 13 inches and a
05 length of approximately four and 1/3 feet, which is con-
structed and arranged for operation at normal relatively
high working pressure of, for example, up to approximately ~;;
loO0 psig. The suction scrubber means llo comprises an
elongated cylindrical tank, having an outside diameter of
approximately 14 inches and a length of approximately five
feet, which is constructed and arranged to have a normal
working pressure of, for example, approximately 250 psig. ,l~;
The engine means 103 may be a Caterpillar Model 3306 TALCR
gas engine. The compressor means 102 may be an Ariel Model
JGP-2-1 w/2 with five and 1/8 inch DA cylinders.
Figs. 6 6 7 show an lllustrative constructlon and
arrangement of the main components of a system of the type
shown in Fig.5A on a portable skid-type platform means 230 ~-
for enabling transport to and support of the system at a
wellhead site. The platform means has flat upper and lower
surfaces 232, 234 and upwardly and outwardly inclined
opposite end surfaces 236, 238. Rigid I-beams and plate
mounting means 240, 241, 242, 243, 244, etc. are fixedly l~
attached to the platform means for supporting,the system ~f,
components. The low pre6sure primary separator means 100
and the hiyh pressure secondary separator means are mounted
at one end of the platform means. The compressor means 102
and the motor means 103 are centrally mounted on the plat-
form means 102. The forced draft gas cooler and engine
radiator means 126 are mounted on the other end of the
platform means. The system shown in Figs. 6 and 7 does not n
,.
-
employ a safety scrubber means 110, but a mounting means for
a safety scrubber means is illustrated at 246. The platform
means 230 is approximately 21 feet by 7-1/2 feet. The
construction and arrangement of the apparatus enables
OS assembly and ~ounting of the system components at a manufac-
turing plant to provide a portable production unit which may
be transported to the wellhead site on a flat-bed trailer or
truck and moved from one wellhead site to another wellhead
site while also facilitating hook-up, installation, opera-
tion and maintenance at the wellhead site. I
In normal continuous operation of the illustrativesystem of Figs. 5A & 5B, the compressor means 102 induces
and maintains continuous flow of well effluent from the well
inlet into the low pressure separator means 100 and from the
lS low pressure separator means to the compressor means 102
through the gas scrubber means 110. It is to be understood
that the use of a gas scrubber means 110 is optional and may
not be required in some situations. The compressor means
also raises the pressure of the gases discharged from
discharge ports 113, 114 to a relatively high flow pressure
sufficient to enable unrestricted flow of the gases into the
sales gas pipeline from the high pressure separator means
104. The compressor means also substantially raises the l
temperature of the discharged gases and the heat of compres-
sion is used to supply heat to the low pressure separator
means 100 by causing the compressed gases to flow through
heat exchanger means 116. It is to be understood that the
compressor means 102 may be of any suitable design including
one, two or more compression cylinders and also providing
multiple stages of compression. In order to meet sales gas
line temperature requirements, the compressed gases are
cooled by the forced draft cooler means 126 prior to deliv-
ery to the high pressure separator means 104 and the cooling
also increases the efficiency of the high pressure separator
means in removing additional liquids prior to delivery of
05 the gases into,the sales gas pipeline. Thus, the low
pressure separator lOo operates at a relatively low pressure
(e.g., 100 to 500 psig) and a relatively high temperature
(e.q., liquid bath temperatures of 70 to 150 degrees F)
while the high pressure separator 104 operates at a rela-
tively high pressure (e.g., 300 to 1000 psig) and a relative-
ly low temperature (e.g., liquid bath temperatures of 60 to
120 degrees F). Supply gas obtained from the high pressure
separator in line 150 also will have a relatively high
pressure and iB delivered to the supply gas pressure reduc-
tion regulator means 156 for pressure reduction before
entering drip pot means 160. Supply gas heat exchanger
means 152 is associated with the compressed gas heat ex-
changer means in the heated liquid bath in the low pressure
separator means 100 to increase the supply gas temperature
to a temperature sufficient to prevent freezing during
pressure reduction (e.g., 1000 psig to 75 psig) through
supply gas pressure regulator means 156. The primary
purpose of circulation of engine coolant through the fuel
gas volume pot heat exchanger means 185 and separator heat
exchanger means 187 is to assist in cold weather start-up of
the system. In normal continuous operation of the system,
heat exchanger means 187 may be bypassed or shut'off so that
engine coolant flow is terminated or limited to gas scrubber
heat exchanger means 189 when a gas scrubber means 110 is
employed.
, 21
g33
It is to be understood that the operating parameters of
the system are variably dependent on particular wellhead,
sales gas pipe line and ambient conditions and parameters.
By way of illustration, system operating conditions (at an
05 ambient temperature of 100 degrees F.) for a wellhead having
a volume of 1.5 million cubic feet per day at a specific
gravity .65 and a gas pipe line having a line pressure of
650 psig and a line temperature of 120 degrees F. may be
approximately as follows: compressor suction inlet port and
primary separator gas pressure of 240 psig and temperature
of 70 degrees F.; compressor discharge port gas pressure of
655 psig and temperature of 193 degrees F.; primary separa-
tor liquid bath temperatures of 140 degrees F.; secondary
separator gas pressure of 650 psig and temperature of 120
degrees F.; and secondary separator liquid bath temperature
of 120 degrees F.
The illustrative system provides a method of separating
liquids from gas in wellhead effluent from a low volume
natural gas well to produce sales gas while establishing and
maintaining continuous unrestricted flow of wellhead
effluent from the well to a primary separator and of sales
gas from a secondary separator to a sales gas pipeline. The
wellhead effluent is delivered to a relatively low pressure
primary separator means in which heavy end hydrocarbons in
liquid phase and water in liquid phase are separated from
gaseous hydrocarbon components while being sub~ect to
induced flow of gaseous hydrocarbon components to the low
pressure inlet port of a gas compressor means. The gaseous
hydrocarbon components are subject to compression causing an
increase of pressure to a pressure approximately equal to
the sales gas line pressure and an increase of temperature
~Z7793.9
.
sufficient to provide heat for operation of the low pressure
separator means. The compressed gaseous hydrocarbon compo-
nents are deIivered from the discharge port of the compress-
or means to a heat exchanger means~in the low pressure
05 separator means so that the liquids in the separator means
are heated by the heat of compression in the compressed
gases. Then, the compressed gases are cooled and then the
compressed gases are delivered to a relatively high pressure
separator means whereat additional liquids are removed from
the compressed gas at pressures substantially higher than
operating pressure of the low pressure separator and approx-
imately equal to or greater than standard sales gas pipe
line pressure and at temperatures approximately equal to or
less than standard sales gas pipe line temperature. More
specifically, the method compri6es causing flow of the
effluent into a low pressure ~epara*or means by compression
of the gases downstream of the low pressure separator means;
supplying heat to the low pressure separator means to
provide a relatively high operational temperature in the
separator means; separating effluent in the low pressure
separator means into a body of liquid hydrocarbons and a
body of water and,a body of gaseous hydrocarbons: causing
flow of the body of gaseous hydrocarbons from the low
pressure separator means by compression of the gaseous
hydrocarbons in compressor means located downst~eam of the
low pressure separator means: increasing the pressure and
temperature of the gaseous hydrocarbons by compression in
the compressor means to a pressure substantially equal to or
greater than the standard pressure in the sales gas pipe
line and to a temperature greater than the standard tempera-
ture in the sales gas pipe line and sufficient for supplying
127793.9
heat for processing the effluent in the low pressure separa-
tor means; delivering the compressed gaseous hydrocarbons
from the compressor means to heat exchanger means located in
the low pressure separator means and transferring sufficient
05 heat from the compressed gaseous hydrocarbons to the low
pressure separating means to process the effluent in the low
pressure separator means; delivering the compressed gases
from the heat exchanger means in the low pressure separator
means to cooling means located downstream thereof and
cooling the compressed gases to a temperature approximately
equal to the standard temperature of the sales gas pipe line
while maintaining a pressure of the compressed gases sub-
stantially equal to or greater than the standard pressure of
the sales gas pipe line; delivering the cooled compressed
gaseous hydrocarbons to a relatively high pressure separator
means located downstream of the cooling means and removing
additional heavy end hydrocarbons from the cooled compressed
gase~ at a processing temperature substantially less than
the processing temperature in the low pressure separator
means and providing a body of residual liquid hydrocarbons
and a residual body of compressed gas having a pressure
approximately equal to or greater than the standard sales
gas line pressure and continuously forcing flow of the
; residual body of compressed gas from the high pressure
separator means into the sales gas line at pressures approx-
imately equal to or in excess of the standard sales gas pipe
line pressure by continuous compression of gases in the
compression means and continuous delivery of the high
pressure compressed gases from the compression means to the
relatively high pressure separation means. The afore-
described apparatus, methods and systems may be variously
- ` ~
.
employed to achieve the advantages, objectives and results
provided by the present inventlon.
It i6 to be understood that the system of Figs. 5-7 is
constructed and arranged to operate at variable elevated
05 processing temperatures substantially in excess of the
freezing point of water (i.e., 32 degrees F) and above the
hydrate formation temperature of natural gas and variable
elevated processing pressures substantially in excess of 20
psig. While normal operating process pressures and tempera-
tures may vary and be controllably varied from well site towell site due to variations in pressures and temperatures of
wellhead effluent, gas pipe line pressures, etc. at various
well sites, the low pressure primary separator means will be
typically operated at pressures in the range of 100 psig to
600 psig and temperatures in the range of 70 degrees F to
150 degrees F; the secondary high pressure separator means
will be typically operated at pressures in the range of 400
psig to 1000 psig and temperatures in the range of 65
degrees F. to 120 degrees F.: and the compressor means will
be typically operated at discharge pressures of 300 psig to
1000 psig and discharge temperatures in the range of 150
~- degrees F. to 250 degrees F. Thus, the terms "relatively
low", "relatively high" and "elevated" and "substantially
elevated" as may be used in the specification and claims
hereof are intended to be given an interpretation consistent
with the foregoing general description.
The terms "flash" or "flashing" as used herein will be
understood to mean the release and formation of hydrocarbon
gases and vapors from liquid hydrocarbons by reduction in
pressure or increase in temperature of liquid hydrocarbons.
The term "scrubbing" as used herein will be understood to
.
1~9
mean the separation and removal of heavy end hydrocarbons
from light end hydrocarbons in gaseous or vaporous phase
and/or the separation and removal of gaseous or vaporous
light end hydrocarbons from heavy end hydrocarbons in liquid
05 phase. For example, in the low pressure separator means of
the present invention, the pressure of the incoming liquid
hydrocarbons from the high pressure separator means is
reduced at the inlet to cause removal and separation of some
of the light end hydrocarbons by "flashing". In addition,
the body of essentially heavy end liquid hydrocarbons
collected in the tanks at the bottom of the high pressure
separator means and the low pressure separator means is
heated to cause residual light end hydrocarbons to be
released and separated therefrom by "flashing". Increase in
temperature of the liquid essentially heavy end hydrocarbons
causes release of light end hydrocarbons while decrease in
; temperature of the essentially llght end gaseous and vapor-
ous hydrocarbons causes release of heavy end hydrocarbons.
Also, when the essentially heavy end liquid hydrocarbons are
delivered to the storage tank means, reduction in pressure
causes flashing of residual light end components in the
storage tank means unless stabilized to vapor pressure less
than atmospheric. It will be further understood, that the
separating processes inevitably result in a variable mixture
- 25 of both light end and heavy end hydrocarbons in either the
gaseous, vaporous or liquid phases because the processes
cause greater or lesser amounts of each to be carried away
with the other.
It is intended that the appended claims be construed to
include alternative embodiments of the invention except
insofar as limited by the prior art.
