Chilingarian G.V. et al. Surface Operations in Petroleum Production, II
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265
have become particularly important in recent years, because oilfield steam genera-
tors have been required to operate on produced or recycled water which has been
pumped out of producing wells with the oil and then separated from the oil. The
trend toward the use of produced water as feedwater for oilfield steam generators
has been accelerated for two reasons:
(1)
Many steam injection projects are located in relatively arid areas where high
volumes of feedwater are not available.
(2)
The difficulty of disposing of high-salinity brines which are separated from
the crude oil.
As steam
is
injected into a formation and condenses upon flowing through it, the
condensate leaches solids out of the formation and builds up a heavy concentration
of total dissolved solids. It is estimated that the average concentration
of
total
dissolved solids in the feedwater of oilfield steam generators currently in use in
California, U.S.A., may be in excess of
3500
ppm, with some steam generators
operating on feedwater containing as hgh as
7500
ppm of total dissolved solids.
Several factors must be considered in preparing feedwater for use in oilfield steam
generators.
Turbidity
of
feedwater
Suspended solids such as clays, silt, and corrosion products may be present
in
the
feedwater. These suspended solids may foul the ion exchange water softener, or may
bake on the tubes of the steam generator giving rise to a film having a resistance to
heat transfer. In order to avoid operating problems, the feedwater to an oilfield
steam generator must be free of turbidity. Removal of suspended solids is typically
accomplished by settling, coagulation, and filtration.
Oil
content
Any significant
oil
content in the oilfield steam generator feedwater can lead to
tube failure as a result of the oil forming a hard asphaltic scale on the tubewall and
retarding heat transfer to the water-steam mixture. In addition, oil can be especially
troublesome in the fouling of the ion exchange resins used in the water softeners.
Oil is a likely contaminant in produced water or any oilfield waste water which
may be used as a steam generator feedwater. Generally, its removal requires
skimming and filtration with coagulation.
If
anthracite filters are used, they will
probably have to be frequently backwashed with hot caustic to prevent excessive
fouling. Regardless of the oil removal procedure used, maximum reliability in steam
generator performance requires that the oil content of the feedwater must not
exceed
1-2
ppm.
Dissolved gases
in
feedwater
Dissolved gases such as oxygen or hydrogen sulfide can be extremely corrosive at
the high metal temperatures at which oilfield steam generator tubes operate. Oxygen
may be removed by steam deaeration or by using scavenging chemicals such as
sodium sulfite and hydrazine. In certain instances, oilfield steam generator oper-
266
ators are deaerating the feedwater with steam, followed by the addition of chemical
scavenging agents to remove the residual traces of oxygen. It is recommended that
the oxygen content of the feedwater must not exceed 0.01 ppm in order to prevent
corrosive attack of the tubes.
If hydrogen sulfide is present in the feedwater, it is generally removed in a steam
deaeration step. If steam deaeration is not used, then chlorination of the feedwater
may be used to reduce the hydrogen sulfide content of the feedwater.
Alkalinity
I
of feedwater
The alkalinity of the feedwater, which is primarily the result
of
the presence of
carbonates, may be influenced by the addition of hydroxides and sulfites. Although
excessive hydroxide alkalinity can contribute to caustic embrittlement, moderate
alkalinity levels help control corrosion and serve to maintain silica solubility. At
temperatures at which most oilfield steam generators operate, carbonates and
hydroxides are deposited forming scale in the presence of Ca2+ or
Mg2+
or other
divalent cations such as Sr2+ and Ba2+.
Silica content
in
feedwater
The principal problem associated with silica in once-through 80%-quality steam
generators consists of maintaining its solubility in the water. Silica solubility is
strongly influenced by the alkalinity of the feedwater. The alkalinity level in ppm
should always be maintained at a minimum of three times the silica content of the
feedwater. Satisfactory oilfield steam generator performance with silica contents up
to 200 ppm is possible in the absence of scaling ions.
Metal contaminants
in
feedwater
Iron is frequently present in steam generator feedwater in the reduced (ferrous)
soluble form. Aluminum and manganese are sometimes present in small amounts.
These constituents are similar to the hardness ions (Ca2+ and
Mg2+)
in the
problems that they can create in a once-through oilfield steam generator. They will
precipitate to form hydroxide scale at the high pH of feedwater, and will also
combine with the silica to form silicate scale.
The metallic contaminants may also be present in the feedwater as the insoluble
hydrous oxides, which may deposit on the tubewalls of the steam generator. The
hydrous oxides may also coat the resins used in the ion exchange water softeners.
These constituents should be removed from the feedwater to the lowest practical
limit.
pH
of feedwater
Acceptable oilfield steam generator operation has been obtained at feedwater pH
levels of 7-12. Lower values could lead to acidic corrosion. whereas values to
13
or
The alkalinity is defined as the total content of the bicarbonate, carbonate, and hydroxide
ions.
261
above indicate excessive hydroxide alkalinity with both caustic corrosion and
possible caustic embrit tlement.
Total hardness of feedwater
The basic design concept of the once-through, 80%-quality steam generator is
based on the use of feedwater having less than
1
ppm
of
hardness
'.
All of the solids
(TDS) must be fully soluble in the feedwater, and must remain fully soluble in the
residual liquid after
80%
of the feedwater has been converted to steam. This type of
steam generator is capable of handling feedwater with a very
high
total dissolved
solids content as long as the solids are in a form which will not deposit on the walls
of the steam generator tubes.
The most widely used feedwater softening method for steam injection applica-
tions is ion exchange by which calcium and magnesium ions are replaced by sodium
ions. Most ion exchange water softeners consist of two sets of primary and polishng
softeners, with one set operating and one set either in the process of being
regenerated with brine or in ready standby condition. Ion exchange water softeners
have the ability to remove all positively-charged ions (cations). Ths type of water
softener is capable of handling feedwater with up to approximately 6000 ppm of
total dissolved solids without requiring excessive regeneration.
When feedwaters containing between 6000 and
10,000
ppm total dissolved solids
are to be used in once-through, 80%-quality steam generators, it is normal practice
to use ion exchange softeners followed by carboxylic softeners in order to reduce the
hardness to
1
ppm. The high cost
of
acids
or
caustic required to regenerate the
resins used in a carboxylic softener, can be significantly reduced by removing much
of the hardness in ion exchange softeners. If the feedwater contains in excess of
10,000
ppm of total dissolved solids, it becomes almost mandatory to use only the
carboxylic softeners.
Flue
gas scrubbers
Many once-through, 80%-quality oilfield steam generators are fired with sulfur-
bearing crude oil, and the sulfur in the fuel is converted to sulfur dioxide and sulfur
trioxide in the combustion process. In areas such as California,
U.S.A.,
where strict
flue gas emissions regulations are in effect, means must be provided to reduce the
content of sulfur compounds before the flue gases can be released to the atmosphere
(see Fig. 7-24).
A
typical
50
MMBtu/hr oilfield steam generator fired with crude oil containing
1.1%
by weight of sulfur will consume 3247 lb/hr of fuel having a lower heating
value of 17,500 Btu/lb. The 35.72 lb of sulfur contained in the fuel will be
converted to approximately 69.3 lb/hr of
SO,
and 2.68 lb/hr of
SO,.
If the unit is
operated at
10%
excess air, the combustion would produce 52,926 lb/hr of flue
'
Hardness is defined as the total content
of
the calcium and magnesium ions present in the water.
268
Fig.
7-24.
A
50-MMBtu/hr oilfield steam generator burning high-sulfur crude oil and provided with a
horizontal flue gas scrubber. (Courtesy
of
Struthers Thermo-Flood Corporation.)
gases, and the concentration of
SO,
compounds in the flue gases would be
1360
PPm-
After sulfur dioxide has been discharged to the atmosphere, it can quickly oxidize
to sulfur trioxide and produce “acid rain”, which is, a primary environmental
concern. In addition, sulfur dioxide has an adverse effect on the respiratory system
and on plant life, even prior to its conversion to sulfur trioxide. For this reason, flue
gas scrubbers must be used in conjunction with oilfield steam generators, which are
fired with sulfur-bearing fuels and are located in areas where stringent emission
standards are in effect.
A number
of
flue gas scrubber designs are in use on oilfield steam generators in
California,
U.S.A.,
where stringent
SO,
emission limits are in effect. One design
involves the use of a double-alkali-solution to absorb the sulfur compounds from
the flue gases and produce water-soluble reaction products. This type
of
system
utilizes either sodium hydroxide
or
soda ash as the makeup chemical, and then uses
slaked lime [Ca(OH),] in a secondary reaction loop to precipitate calcium sulfite
dihydrate (CaSO,
.2H,O)
while simultaneously regenerating the absorption solu-
269
Fig.
7-25.
View
of
multiple 50-MMBtu/hr oilfield steam generators having stacks manifolded into a
common
flue
gas duct and discharging into a single flue gas scrubber. (Courtesy of Struthers Thermo-Flood
Corporation.)
tion. Because of the relatively hgh capital cost associated with the secondary
chemical reactor, the slaked lime handling equipment, and the vacuum filtration
system necessary to operate a double-alkali process, this type of scrubber normally
can be justified only when multiple oilfield steam generators are manifolded
together to produce a large single source of
SO,
(Fig.
7-25).
Where sulfur dioxide sources of possibly less than
12,000
lb/D are available, it
becomes economically more attractive to use a non-regenerative type of scrubbing
system, utilizing either soda ash or sodium hydroxide as the makeup chemical. This
type of system is operated in almost the same manner as the absorption step in the
double-alkali process. Rather than regenerating the liquid from the scrubbing
process, however, the spent liquid is simply discarded. Ths minimizes the capital
cost and the amount of operator attention required. The operating costs for the
non-regenerative scrubbing system often become much lower than would be the case
with double-alkali systems. Such systems are used extensively for all but projects
having a large concentration of oilfield steam generators in one area.
The maximum theoretical sulfur dioxide removal efficiency for any given flue gas
scrubbing system is dictated by the partial pressure of sulfur dioxide over the
scrubbing solution at an equilibrium temperature lying between that of the scrub-
bing liquid and that of the saturated gas stream.
As
an example, if the content of
270
sulfur dioxide over a given scrubbing solution is 30 ppm by volume, and the
scrubbing unit is mechanically capable of achieving true equilibrium conditions
between the gas and the liquid at its discharge, it would be possible to achieve
90%
collection efficiency
or
greater only with an inlet sulfur dioxide concentration
of
not
less than 300 ppm by volume. In other words, the sulfur dioxide concentration in
the exit gases is established by the equilibrium conditions for the system, and the
sulfur dioxide removal efficiency becomes simply a function of the sulfur dioxide
concentration in the gases entering the scrubber.
Low-temperature economizers
The minimum exit flue gas temperature from an oilfield steam generator is
primarily a function of the flue gas initial dew point. For steam generators fired
with sulfur-bearing fuels, the dew point may range from 260 to 340"F, depending
on
the sulfur content of the fuel and the percentage of excess air at which the burner
is
operated. Care must be exercised in the design of the steam generator convection
section in that condensation can occur on metal surfaces which are colder than the
flue gas initial dew point, even though the main body flue gas temperature
is
well
above the dew point. For this reason, most oilfield steam generators, which are fired
with sulfur-bearing crude oil, are designed for flue gas temperatures of 400°F
entering the stacks (see Fig. 7-26).
Fig.
7-26. View of a 50-MMBtu/hr oilfield steam generator with a low-temperature convection section
discharging into
a
horizontal flue gas scrubber. (Courtesy of Struthers Thermo-Flood Corporation.)
271
The rapidly escalating cost of fuels has generated a considerable interest in
increasing the net thermal efficiency of oilfield steam generators by extracting more
heat from the flue gases before they are discharged to the atmosphere. As a result, a
low-temperature economizer designed to cool the flue gases to within about
50
OF
of
the inlet feedwater temperature is commercially available, and a number of such
units are in successful operation of oilfield steam generators in California, U.S.A.
The low-temperature economizer is designed to cool SOx-bearing flue gases well
below the dew point, and
is
of alloy or plastic coated steel construction to resist the
corrosive action
of
the acidic condensate. Field tests have shown the condensate to
have a pH of approximately
2.4.
The low-temperature economizer is
so
arranged
that acid condensate cannot drain back into the regular convection section
of
the
steam generator which is provided with carbon steel tubes. The low-temperature
economizer can be provided as an integral component
of
a new oilfield steam
generator,
or
can be added on to an existing steam generator.
If an oilfield steam generator is fired with 15O-API crude oil having a lower
heating value of
17,500
Btu/lb and the burner is controlled to
10%
excess air, the
net thermal efficiency of the steam generator with a 400
OF
stack temperature would
be about
9096,
based on the lower heating value of the fuel. If the flue gases are
further cooled to
150
O
F
by a low-temperature economizer, the steam generator net
thermal efficiency would be increased by approximately
6%.
The use of a low-temperature economizer also has the following advantages when
the system incorporates a flue gas scrubber:
(1)
Reduction in scrubber size, as cooling of the flue gases results in their volume
reduction.
(2)
Significant reduction in the amount
of
scrubber water, lost as vapor in the
flue gases leaving the scrubber as a result of removal
of
the temperature quenching
burden placed on the scrubber by
400
O
F
gases.
(3)
Reduction in the SO, concentration in the flue gases entering the scrubber.
High-temperature thermal packers
A packer is designed to seal the annulus between the injection tubing and the
casing at a point immediately above the zone where steam is introduced into the
oil-bearing stratum. The function of the packer is to prevent the escape of steam
and oil vapors to the atmosphere through the annulus.
Packers are required to be expandable when they are properly positioned
so
that
they may form a relatively tight seal against both the casing and the steam injection
tube. They must also be collapsable,
so
that they may be opened and the injection
tube withdrawn. The use
of
high-temperature and high-pressure steam as required
on the deeper wells, ranging from
2500
to
5400
ft in depth, has forced the
development of thermal packers capable of withstanding the much more severe
operating conditions to which they may be exposed. Several satisfactory designs are
currently available for the higher-temperature applications.
212
Casing vent systems
In a typical steam displacement installation, steam breakthrough occurs in six to
twelve months after the initiation of steam injection. This phenomenon results from
the channeling of high-pressure steam (injected into the oil-bearing formation)
through the intervening strata to a producing well. With the breakdown of steam
flow resistance between injector and producer wells, pressures as high as
30
psig
may be developed in the producing well casing. This pressure has the undesirable
effect of inhibiting the flow of reservoir fluids into the wellbore, thereby decreasing
oil production. Producers have resolved the casing pressure buildup problem in the
past by simply opening the casing valve, and venting the continuous vapor flow into
the atmosphere.
In recent years, it has become common practice to install casing vent gathering
systems
on
steam injection projects for two basic reasons:
(1)
Vapors vented from a well casing are typically composed of
95%
steam and
5%
condensible hydrocarbons. The light hydrocarbons present in a casing vent
system represent considerable value and justify recovery.
(2)
Increasingly stringent emission regulations restrict the release of significant
volumes of hydrocarbon vapors to the atmosphere.
The most cost-effective technique for recovery of the hydrocarbon vapors is to
collect them in a piping system and condense them at a central point. In many
respects, a casing vapor recovery system is similar to a natural gas gathering system.
The basic concept of moving a gas through piping by utilizing the wellhead pressure
is identical. There are, however, certain factors peculiar to casing vent collection
systems which distinguish them from other piping networks.
Casing vent collection piping is normally laid directly on the ground because
there is no need for insulation. In laying out the piping system, low spots in which
condensate can accumulate should be avoided. Condensate accumulation in low
spots can restrict the carrying capacity of the piping system, and undulations
exceeding ten feet, in which condensate can collect, may actually create an undesir-
able backpressure on the casing. A preferred arrangement is to provide gas-liquid
separators at the low points in the pipeline system, and then to carry the piping on a
continuous uphill grade to the highest point in the system where the condensers
should be located. With this type of arrangement, condensate flows continuously
downhill to the vapor-liquid separators countercurrently to the vapor flowing from
the wellheads to the condensing equipment.
Either air-cooled or water-cooled condensers may be used for this service. Where
the steam generator feedwater is at a sufficiently low temperature, it makes an ideal
coolant for the casing vent condensers.
Downhole steam generators
The application of the steam injection technique for enhanced oil recovery to
wells over
2500
ft in depth has recently received increasing consideration. One
273
TORCH IGNITOR
,
TL
,AIR
STEAM AND PRODUCTS
OF
COMBUSTION
Fig. 7-27.
Typical
downhole
steam generator.
concern relative to injection of steam in deep wells is the high rate of heat
loss
from
the injection tubing to the subsurface strata. One solution to the deep well heat loss
problem is to use surface oilfield steam generators in conjunction with insulated
downhole tubing.
This
arrangement is in commercial use and has proven successful.
Recently, a large development effort has been concentrated on the production of
a downhole steam generator which can produce steam near the point where it is
injected into the formation and thus avoid the heat losses when transporting steam
from the surface to a depth
of
several thousand feet (see Fig. 7-27). Two basic
downhole steam generator designs have evolved from this development effort:
(1)
A
design in which the steam and products of combustion are intimately
mixed and injected into the formation.
(2)
A
design in which the steam and products of combustion are kept separate,
with the steam being injected into the formation and the products
of
combustion
being transported to the surface and discharged into the atmosphere.
Whereas some experimental work has been performed using downhole steam
generators to inject steam into actual wells, there are at this time
no
installations
214
which can be considered commercial. Of the two basic designs, the one in which the
steam and the products of combustion are intimately mixed appears to be the more
promising.
At the present time, there appears to be a number
of
economic and operational
drawbacks to downhole steam generators, which may be partially or totally resolved
with continuing development work.
(1)
Need for expensive fuels such as natural gas, naphtha, or light oil.
(2) Both fuel and combustion air or oxygen must be compressed to the injection
pressure, which requires a very large horsepower for the compressors, particularly at
injection pressures of 2000-2500 psia.
(3)
The partial pressure reduction effect of the combustion products mixed with
the feedwater would result in a steam temperature of
600
O
F
at 2500 psia generation
pressure, or
68
F
lower than the saturation temperature
of
steam at 2500 psia. This
would reduce the thermal driving force for transferring heat from the steam to the
formation.
(4) On cyclic injection projects, the downhole steam generator must be removed
for each production cycle.
The downhole steam generator appears to show promise with a continuing
development effort; however, at this time it does not appear to be either economi-
cally or operationally suitable for large-scale commercial use.
Solid-fuel-fired oilfield steam generators
The single highest operating cost on a steam injection project is the cost of the
fuel to be burned in the steam generator to produce the injection steam. For
example, a 50 MMBtu/hr oilfield steam generator operating 24 hr a day for
330
days per year would consume approximately
80,000
barrels of oil as fuel. Priced at
$28 per barrel, the annual fuel cost would be in the range of $2,240,000.
In order to reduce the cost of generating injection steam, various designs of
oilfield steam generators capable of using solid or waste liquid fuels have been
under investigation for some time. One commercial
50
MMBtu/hr oilfield steam
generator utilizing a circulating fluidized bed combustion system has been installed
in the United States, and has operated successfully for approximately two years.
The unit is installed on a tar sand project, and is generating 50,000 lb/hr of steam
at 2240 psia (see Fig. 7-28).
The one solid-fuel-fired oilfield steam generator which is in operation has been
successfully fired with lignite, coal, or petroleum coke. The unit incorporates
two-stage combustion to reduce the formation of
NO,
and utilizes limestone
addition for sulfur capture. It has fully met all environmental emission standards
when burning any of the three fuels for whch it was designed.
The commercialization
of
solid- or waste liquid-fired oilfield steam generators
has the potential of appreciably improving the economics of heavy crude oil or tar
recovery by the steam injection process. This type of oilfield steam generator would