SECONDARY AND TERTIARY METHODS IN SOVIET OIL PRODUCTION

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• Collection: General CIA Records
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• Document Creation Date: December 22, 2016
• Document Release Date: June 4, 2009
• Sequence Number: 5
• Publication Date: April 1, 1984
• Content Type: REPORT

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Directorate of Secret
Intelligence
Secondary and Tertiary
Methods in Soviet Oil
Production
Secret
SOV 84-10047
April 1984
Copy `i 9 3
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Intelligence
Secondary and Tertiary
Methods in Soviet Oil
Production
This paper was prepared byl of the
Office of Soviet Analysis, with technical support by
Comments and queries are
welcome and may be addressed to the Chief, Soviet
Economy Division, SOYA,
Secret
SOV 84-10047
April 1984
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Preface Soviet oil production is encountering interrelated problems in exploration,
drilling, production, field processing, and transportation. Crude oil produc-
tion operations are concentrated in West Siberia's Tyumen' oblast, which
in 1983 was assigned a quota of 362 million tons-almost 60 percent of the
619 million tons planned for the USSR as a whole. At one point, Tyumen'-
production reached the record rate of 1 million tons per day, but the
industry could not maintain it, and the total for 1983 was 359 million tons.
The Soviets may no longer be able to cope with their mounting production
problems. In 1983 one-third of the Tyumen' wells were reaching the end of
their producing life, and drillers were putting into operation only half as
many new wells as would be needed to replace them. Reporting often
mentions idle wells, as well as inefficiency in well operation due- to lack of
maintenance.
The Soviet press has commented that, with Tyumen's inadequate infra-
structure, any weak link in production, processing, or transportation
weakens the entire operation. This paper discusses one of those links-the
industry's trouble in applying secondary and tertiary oil recovery tech-
niques, at a time when.declining well flows and rising, water-cuts call for
their more intensive application.
iii Secret
SOV 84-10047
April 1984
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Summary
Information available
as of 7 March 1984
was used in this report.
Secondary and Tertiary
Methods in Soviet Oil
Production
Soviet application of secondary and tertiary methods of oil production is
becoming increasingly critical to sustaining oil output at a high level. In
primary production, the flow of oil depends on natural reservoir pressure,
which drops as oil is removed. Secondary methods (waterflooding, artificial
lift) and tertiary methods (flooding with steam or chemicals) can prolong
the flow. They demand substantially more investment, manpower, and
technology than natural well flow but promise higher oil recovery.F 25X1
Secondary production methods are widely used in the USSR. Waterflood-
ing to maintain pressure in a well is initiated soon after the onset of
primary production; as larger volumes of water are injected into the oil
reservoir, more artificial-lift equipment (pumps and gas lift) is required to
stabilize the flow of oil. In 1982, 85 to 90 percent of total Soviet oil output
came from fields that had been waterflooded.
In the new areas being developed, the reservoirs are likely to be smaller and
well-flow rates lower than at currently operating fields; the application of
secondary production methods will be costly in investment, labor, and
maintenance. The 1981-85 plan calls for the number of oil wells on
artificial lift to increase by more than 60 percent. To produce the 630
million tons of oil planned for 1985, the Soviets must lift 2.1 billion tons of
fluid (oil plus water)-over 40 percent more than in 1980. More than 1.4
billion tons of this would be lifted by pumps. Beyond 1985 the require-
ments for artificial lift will be even greater.
Soviet industry probably will not be able to satisfy these massive needs.
During the past several years, it has failed to meet its goals for artificial-
lift.equipment by 15 to 20 percent annually. Moreover, the domestic
equipment is poorer in quality than that available in the West. US-made
electric submersible pumps have been important in Soviet secondary
recovery since the 1970s, when some 1,200 units were imported. The
Soviets wish to buy more of these pumps, as well as spare parts, but US li-
censing policy has had the effect of delaying purchases.
Equipment shortages contribute to the wells' increasing downtime for
mechanical repairs. The magnitude of the maintenance task was illustrated
in 1978, when -about 250,000 well repairs were performed, 216,000 of
which involved artificial-lift equipment. By the late 1980s the oilfields
could require more than 500,000 repairs annually, and an even greater
share could involve artificial-lift equipment
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In one plan for the 1980s, the Soviets calculated that the use of Western
equipment in secondary recovery would provide significant savings. Plan-
ning (unrealistically) to put some 40,000 oil wells on gas lift and 8,000 wells
on new hydraulic pumps during 1981-90, they estimated that by using
Western equipment they could do the job with thousands fewer pumps and
workover rigs, save 1 million well repairs over the decade, and cut their
maintenance force by 25,000 workers. The combined savings were calcu-
lated at perhaps 9.0-9.5 billion rubles.
In recent years the USSR has undertaken a program of tertiary production
methods to recover more oil from old reservoirs, but the commercial results
have been insignificant. In 1981 the Soviets obtained only about 3 million
tons of oil from these enhanced oil recovery (EOR) techniques, or about 0.5
percent of total Soviet oil production. They appear to have conducted
laboratory and pilot tests on almost all of the FOR processes known in the
West, but commercial application is hampered by shortages of equipment,
chemicals, and trained personnel.
Published plans call for FOR to yield*oil output of 17 million tons in 1985
and 36 million tons in 1990. These plans appear to be extremely ambitious,
in view of the limited domestic capacity to supply the equipment. The
Soviet Union currently depends on Western assistance in these complex
and costly operations. Even if they give FOR an all-out priority, we doubt
that the Soviets could meet these goals. We estimate that oil production
from FOR methods could reach some 4 million tons in 1985 and no more
than 10 million tons in 1990.
In the West, the slack market for crude oil has slowed the use of EOR,
which not only is capital intensive but also requires long leadtimes before
oil is produced. Oil production by FOR methods in the United States has
remained nearly constant since 1980, although some indications suggest a
significant rise in application of FOR techniques in the coming decade.
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Contents
Summary
Background
Secondary Methods
Waterflooding-Pro and Con
1
Soviet Waterflooding Practices
2
Increasing Requirements for Artificial Lift
5
Impact of Aging
6
Soviet Plans and Performance
9
Equipment and Maintenance Requirements
13
Development of the Soviet FOR Program
16
Dependence on Western Equipment and Technology
21
Plans and Prospects for the 1980s
21
Enhanced Oil Recovery Techniques
23
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Secondary and Tertiary
Methods in Soviet Oil
Production
Background
The techniques for extracting crude oil from petro-
leum reservoirs are commonly classified as primary,
secondary, and tertiary. Primary production entails
drilling a production well into a crude oil reservoir.
There oil, gas, and connate water' are trapped in the
small pores of the reservoir .rock beneath a sealing
layer of cap rock and are subject to considerable
pressure from the overlying rock and from the hydro-
static force of the underlying ground water. At this
pressure, a large share of the gas present in the
reservoir is usually dissolved in the oil. Once the
impermeable cap rock is pierced by the drill, the
compressed connate water, the oil, and the gas in
solution expand and move into the wellbore and
upward. As this natural reservoir energy declines, so
does the rate of oil production from a flowing well.
To sustain pressure in the reservoir and to maintain
oil flows at an efficient rate over a longer period,
secondary production methods are normally initiated
soon after the onset of natural production. These
methods involve injecting a medium into the oil
reservoir (figure 1). The medium is usually treated
water or gas, depending on reservoir conditions. Wa-
ter is most often employed early in the cycle of Soviet
field development. Over time this causes an increase
in the water-cut (the proportion of water in the
mixture of oil and water produced from an oil well).
Water is heavier than oil, and water-cuts of 30
percent or more necessitate the extensive use of
artificial-lift (pumping and gas lift) equipment to
stabilize the flow of oil as increasing volumes of water
must be produced together with the oil.
Even after a successful waterflood, substantial quanti-
ties of oil remain in the reservoir. If it is considered
worthwhile, tertiary production methods (thermal
and/or chemical treatment).may be employed to
' Connate water is the water present in a petroleum reservoir in the
same zone occupied by oil or natural gas. It is a film of water
around each grain of sand in granular reservoir rock and is held in
increase the oil recovery still further (though at a,
lower rate of output) by altering the natural forces
that hold the oil-in-place in the pores of the reservoir
rock. Tertiary methods, usually referred to as en-
hanced oil recovery (EOR), are technically more
complex and considerably more expensive than sec-
ondary methods of production.' In addition, they
themselves consume substantial amounts of energy-
to generate heat for steam or to manufacture the
necessary petroleum-based solvents and other chemi-
cals. Soviet attempts to apply FOR have been hin-
dered by the need:
? For tailoring the FOR applications precisely to the
local conditions at each oilfield-often, indeed, at
each well.
? For large amounts of geological data on the
reservoir.
? For a high degree of specialized expertise on the
part of technicians at the production site.
Secondary Methods
Waterflooding-Pro and Con
As natural reservoir pressure declines, the flow of oil
slows and eventually stops. However, both the.oil-
production rate and the amount of oil ultimately
obtained from a deposit can be increased by appropri-
ately engineered waterflood pressure-maintenance op-
erations. The waterflood process involves pumping
water into the oil-bearing reservoir through wells
drilled at its flanks and base to force the oil to flow to-
ward the production wells. As a rule, water can raise
reservoir pressure quickly because of its higher densi-
ty, relatively efficient displacement characteristics, 25X1
'The terms enhanced, secondary, and tertiary recovery are various-
ly defined in oil industry and legal circles. Some experts employ
enhanced recovery as a generic category to include all of the.
techniques subsumed in secondary and tertiary recovery; others use
the term as a synonym for tertiary recovery only. We use enhanced
oil recovery (EOR) in the latter sense and define the other terms
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and nearly incompressible nature. By prolonging the
economic life of a producing oil well, waterflooding
can substantially reduce the requirement for drilling
and can hold down the cost of producing additional
Waterflooding leaves behind significant amounts of
oil, however, for two reasons. First, as the water
moves through the reservoir rock, it does not flush all
the oil from the pore spaces. Because oil and water do
not mix, oil is left behind in the form of droplets and
pools held within the smaller pores; these can add up
to more than 50 percent of the oil originally in a
reservoir. This problem may be alleviated somewhat
by the use of additives. Second, as the water "front"
advances, it tends to follow the larger channels and
sometimes bypasses significant portions of the reser-
voir because of changing lithology or microgeological
conditions. Thus, the waterflood may not sweep all
areas as efficiently as planned and may leave much of
the oil behind.
Soviet Waterflooding Practices
Since World War II, waterflooding has been em-
ployed in most new Soviet oilfields soon after the start
of production and has been continued throughout the
life of these fields. Water-injected fields accounted for
more than half of the oil produced in the USSR as
early as 1955 and for 85 to 90 percent in 1982
By providing higher initial output per well than would
be possible under natural drive alone, waterflooding
has enabled the Soviets for more than two decades to
minimize their initial oilfield investment by holding
down the number of wells and pumps required.'
Although waterflooding results in high production
rates in the early years of an oilfield's life, it can
produce complications:
In some fields, the Soviets carried the practice to
extremes, raising pressures beyond the original level
enough to rupture the reservoir seals and cap rock.
In'the United States, primary natural drive production was used
exclusively in the 1950s because of the fragmented ownership of
oilfield minerals. It took years of negotiation to get a majority of
the owners to agree to "pooling" and "unitization" of all rights, so
that pressure maintenance operations could begin. In the USSR,
however, the state owns the minerals, so there are no legal obstacles
Before 1977 this malpractice was reported at many
Volga-Urals fields and at several large West Siberi-
an fields, including Samotlor.
o Ideally, the injected water moves through the oil-
bearing formation in a broad front, from the injec-
tion well to the producing well; however, if a
"finger" of water under pressure breaks through to
the producing wells, the rest of the water will follow
this easier path. When this "coning" happens, addi-
tional wells must be drilled (infill drilling) to locate
the bypassed pockets of oil, and more of the expen-
sive pumps or gas-lift equipment must be installed.
The productivity of artificial-lift equipment and the
maintenance burden associated with its use are often
affected by unwanted consequences of waterflooding.
In the Middle Ob' producing region of West Siberia,
for example, the underground aquifers have insuffi-
cient volume to supply all the region's water injection
needs. Therefore, the Soviets added untreated surface
water from lakes and rivers to the aquifer water and
recycled water. Untreated water in some Soviet wa-
terflood projects has created problems in the
reservoirs: .
Oil recovery was reduced by the lowering of bottom-
hole temperatures when cold surface water was
injected into the highly paraffinic Uzen-Zhetibay
reservoirs of the Mangyshlak Peninsula. The same
problem occurred at Samotlor and Ust'-Balyk in
West Siberia.
Injection of untreated water has led to excessive salt
formations in well bores and downhole pumping
equipment at Samotlor and in West Siberian fields.
Organic material and dissolved gases in untreated
surface waters injected into hot oil reservoirs have
also caused prolific bacterial growth, reducing rock
permeability and porosity.
Many West Siberian reservoirs consist of sands and
montmorillonite clays, which when flooded tend to
swell and lower the formation's permeability and
porosity.
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 Figure 1
Oil Well Pressure Maintenance
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From
gas source
Compressor
Gas injection well
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Figure 2
USSR: Oil Well Fluid Production, 1970-90
USSR
Oil.
Water
Increasing Requirements for Artificial Lift
With increasing numbers of new wells being drilled
and old wells "watering out" rapidly because of
waterflooding, the Soviet oil industry's requirements
for artificial lift of fluid will escalate rapidly. Its
ability to meet these requirements will be critical to
oil-production prospects during the remainder of the
1980s. The burgeoning proportion of water in oil well
field production is illustrated in figure 2. Many
fields-including most of the largest and best-have
passed their prime. Stabilization of oil output (that is,
its maintenance at a planned level) at the large fields
will require conversion of a large number of. flowing
wells to artificial-lift operation (major types of artifi-
cial-lift equipment are shown in figure 3). It will also
require continued development by infill drilling.. The
increasing dependence of oil output on development of
numerous small new fields is an additional factor
bearing on the need for- pumping equipment.
Although the Soviets plan to employ large gas-lift
systems in some key fields, the sharply rising fluid-lift
requirements point to an urgent near-term need for
many high-quality pumps of appropriate size to cope
with increasing volumes of water and oil. The Soviets
have recently placed a large order for submersible
pumps with a US firm (see discussion in the section on
pumping requirements in 1981-90).
Pumps can be installed faster and with less capital
cost than gas lift, but are more costly to maintain and
are down more often for repairs. The impact on-the oil
industry of large-scale use of pumps and the concom-
mitant maintenance burden is already serious. On the
basis of information from Soviet technical journals,
we estimate that at any one time about one-third of
West Siberia's 20,000 active wells are idle because of
equipment failures. Around Samotlor, for example,
pump breakdowns are occurring with increasing fre-
quency-the average time between breakdowns has
decreased in recent years from about 130 days to 80
days.
The importance of submersible pumps in Soviet oil
production is illustrated by production data of 1980.
In that year approximately 20 percent of the active
wells in the USSR were exploited by submersible
pumps, which accounted for:
? About 40 percent of the total oil produced.
? More than half of the total fluid produced.
? About 66 percent of the oil produced by artificial-
lift methods.
By 1980 the USSR had imported some 1,200 high-
volume, US-made submersible pumps with a com-
bined annual capacity of about 150-175 million tons
of fluid-enough to recover roughly 30 percent of the
oil produced by all submersible pumps in the USSR.
By 1980 the USSR had also imported Western gas-
lift equipment for another 2,500 to 3,000 oil wells; but
in 1980 only 10 to 20 percent of this equipment was
estimated to be in operation. In 1980 the combined
capacity of the Western gas-lift equipment in Soviet
oilfields was probably around 15-20 million tons of
fluid per year, and it produced about 11 million tons
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of oil. This was nearly half of the total amount
produced by all gas-lift equipment, Soviet and West-
ern-but only about 2 percent of total crude oil
output in that year.
The role of artificial lift is graphically illustrated by
the experience in the Volga-Urals fields. Between
1970 and 1980 the average water-cut in the oilfields
of the Bashkir ASSR rose from 63 percent to over 80
percent. This meant that for every ton of oil recov-
ered, the producers had to lift 3 tons of water in 1970
and 4 tons in 1980. Only special high-volume pump-
ing equipment can cope with such increases in the
amount of fluid, and the equipment most commonly
chosen is the submersible pump
Impact of Aging
As oil wells age, operating problems intensify. After
an initial five- to seven-year period of rising oil
production, fields reach a period of "maturity," char-
acterized by almost flat, or stable, production; this
lasts from five to 10 years. Thereafter, output gradu-
ally declines to a point where production at that field
is no longer economical.
It is technically impossible to stabilize oil production
for more than about 10 years. During the years when
it is feasible, stabilization requires constant infusions
of new capital, labor, and other resources for new
installations at the mature fields. In addition to these
expenses, conversion of flowing wells to artificial-lift
operation usually leads to a sharp rise in maintenance
requirements due to breakdowns of pumps and gas-lift
equipment and to well-casing leaks. The magnitude of
such conversion and maintenance requirements facing
the Soviet oil industry is evident from the rapid
increase in the percentage of fluid to be produced by
artificial lift (figure 4).
In Soviet practice, pumps are usually installed at the
producing well once the water-cut exceeds 30 percent
of a well's total fluid output. The volume of fluid that
must be lifted is, of course, substantially increased
when waterflooding is used. Nearly all of the largest
oilfields in the USSR are more than 12 years old, and
in 1982 the nationwide average water-cut was over 62
percent (it was 44 percent in 1970). Trends in water
injection, fluid production, and water-cut are shown
Major Types of Oilfield Pumps
The rod-and-beam (sucker-rod) pumps used exten-
sively in oil well service employ a relatively primitive
technology. A cylindrical working barrel attached to
the lower end of tubing is' suspended from the well-
head inside the casing. A power-actuated walking
beam at the surface raises and lowers (by means of a
column of "sucker" rods) a plunger set below the
fluid level inside the working barrel. Oil trapped by
valves in the working barrel is lifted through the
tubing with each upward stroke.
The electric centrifugal submersible pumps used in
high-volume artificial-lift operations involve more
sophisticated technology in both materials and fabri
cation. Their three parts-an electric motor, a pro-
tective chamber, and a pump unit-are encased in
seamless steel tubing with watertight joints. The
entire assembly is suspended in the well on tubing
through which the fluid is pumped to the surface.
Electric current is transmitted from the surface to the
downhole pump motor by an armored cable clamped
at intervals to the outside of the discharge tubing
in table 1. In 1983 the Tyumen' oilfields were expect-
ed to produce 362 million tons of oil (with a water-cut
of 47 percent). About 140 million tons were to come
from Samotlor, where the water-cut is 54 percent and
production is in the early stage of decline. By 1985 the
nationwide water-cut will approach 70 percent.
The one-year and five-year plans for oil industry
operations ought ideally to be .geared to total fluid
recovery-that is, the goal for oil production in a
given year contains an implicit assumption of what
the water-cut will be in that year, and this assumption
ought to be realistic. Estimates of the volume of water
that must be coped with in a given year are always
subject to a variety of factors. Achieving the target
for oil production depends on there being enough
pumps of the right size (or, for some fields, gas-lift
equipment). But in the USSR the supply of equipment
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 Figure 3
Artificial Lift Equipment
Pump rod
(sucker rod)
Barrel
fT
Plunger
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IGas
Oil, gas, and
water
P
Heavy duty
flexible
power cable
Motor
Pump
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Figure 4
USSR: Increase in Percent of Fluid Being
Produced by Artificial Lift
Flowing wells
45
Artificial lift Artificial lift
55 70
Flowing wells
30
is undependable, unpredictable, and almost always
less than total requirements. Operational planning is
forced to proceed on a day-by-day basis, largely
because of the scarcity of artificial-lift equipment.
Consequently, oil-production targets frequently are
scaled down later in a plan period to levels more
realistic than those originally set
Soviet Plans and Performance
During the mid-1970s, Soviet planners clearly recog-
nized that their drilling and pumping problems were
escalating. They had discussed the possibility of a
rapid rise in pumping requirements in the late 1960s,
when requirements for the 1970s were being exam-
ined. Up to 1970, however, pumping was not a
significant problem because of the relatively large
number of high-yield "flowing" wells (those that did
not require artificial lift), the wide spacing of wells,
and the youth of the big fields being exploited. After
1970, however, the average space between wells was
reduced steadily as infill drilling programs gained
momentum at Romashkino, Tyumazy, Bavly, Arlan,
and other large Volga-Urals fields. At older produc-
ing fields, the tighter well spacing means that each
new well has a shorter period of water-free oil produc-
tion and old wells have greater requirements for
pumps as their water-cut increases.
During discussions of the plan for 1976-80, oil indus-
try officials noted the sharply declining share of total
oil production yielded by flowing wells (nearly all of
which were under pressure maintenance by water-
flooding) and the rise in the share yielded by artificial
lift. We estimate that fluid production from flowing
wells had fallen from about 55 percent of the total
fluid produced in 1970 to 45 percent in 1975.?
Oil Ministry officials clearly realized that pumps
would be crucial for efficient exploitation of the
oilfields, but even so the plans they issued for 1980
included only about 80 percent of the pumps that the
period would require. Thus, during the late 1970s (in
the optimum "window"-when the water-cuts were
only 30 to 50 percent and pumps would be lifting
more oil than water), the Soviets failed to install
enough pumping equipment. This led to lower than
planned oil production in 1980, to a more rapid
"watering out" of wells, and to some reduction in the
ultimate potential oil recovery. As a consequence of
that shortage of pumps in the 1970s, the task of
maintaining the level of national oil production in the
1980s entails a greater drilling effort than it should-
and, consequently, a greater resource drain on the
economy.
Soviets were preoccupied with pumping requirements
for the 1980s and that efforts to expand pump
production were deemed most urgent. Planned pro-
duction of domestic gas-lift equipment, submersible
pumps, and rod-and-beam pump units was to be
' This percentage has continued to fall and is likely to reach 30
percent in 1985. More significant was the fact that the nationwide
water-cut passed 50 percent in 1977 and 62 percent in 1982. By
1985, both the water-cut and the total fluid produced by artificial
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Table 1
USSR: Water Injection, Fluid Production, and Water-Cut
Oil
Production
Average Water-Cut as
Percent of Total Fluid
1960
189
NA
148
NA
1965
329
443
243
45
1970
559
625
353
44
1975
985
935
491
47
1980 1,560 1,435
603
58 plan
1985 plan 1,900-2,100 plan 2,100 plan
630 plan
70 estimate
West Siberia only
1970
45
33
31
5
1975
259
173
148
14
1980
650 plan
465 estimate
313
33 estimate
1985 plan
1,035 plan
800-1,000 estimate
385-395 plan
52-60 estimate
a We estimate total fluid production on the basis of water-cut data
and plans reported in Soviet publications.
Note: Figures show actual production reported by the USSR except
where indicated; plan means official Soviet production plans, and
estimate indicates a CIA estimate.
boosted sharply just to stabilize crude oil produc-
tion.' at least 40,000
submersible pumps, 20,000 gas-lift units, and 21,000
more rod-and-beam pump units would be required
over the 1980s.
Production of such pumps trailed far behind the need,
and the effect of the shortage is evident in the
statistics on oil production by primary (natural flow)
and secondary methods. For example, a Soviet oil
industry journal reported that in 1979 only 49 percent
of oil production came from wells on artificial lift,
instead of the 60 percent or so that had been planned.
In 1980, artificial lift probably accounted for no more
than 53 percent of oil output. This means that oil
' It is noteworthy that in 1979 the Soviet planners foresaw that
crude oil production would remain flat at 580 million tons from
1980 to 1990. This view reflected their projections that the
nationwide average water-cut would reach 63 percent in 1985 and
68 percent by 1990. Total oil production includes small amounts of
crude oil production by the Gas Ministry, as well as condensate
output by natural flow from old watered-out wells and
from newly drilled infill wells, even though it was
declining, still accounted for a greater share of total
production than had been planned (47 percent instead
of the planned 37 percent) because of the lack of
pumping equipment for artificial lift.
Between April 1978 and February 1981, the planners
revised sharply upward their estimates of total fluid
(oil plus water) output in 1985, from about 1.7 billion
tons to 2.1 billion tons. This called for a hefty increase
over 1980's record of 1.4 billion tons (table 2). If the
planned 2.1 billion tons were a firm commitment, the
plans for pump production by 1985 would also have
had to be revised sharply upward. If pump production
is rising as the plans require, these trends suggest that
total fluid output could hit. 2.7 billion tons in 1990.
The water-cut is rising faster than the Soviets had
expected. We anticipate that the nationwide average
water-cut will increase from 58 percent in 1980 to
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Secret
Table 2
USSR: Total Fluid Production
Water.injected in wells
(million tons)
559
Number of active wells (yearend)
53,400
63,600
82,500
129,000 P
175,000 e
Flowing wells
8,600
8,600
11,430 P
13,000 P
20,000
Artificial-lift wells
44,800
55,000
71,070 P
116,000 p
155,000 e
Equipped with:
Electric submersible pumps
5,400
9,900
17,200 p
36,500 a
40,000 p
Gas lift
900
2,200
2,300 p
6,500 c
12,000 e
Rod-and-beam pumps
38,500
42,900
51,570
73,000 e
103,000 e
Total fluid recovered
(million tons)
625
935
1,435
2,100 p
2,500-2,750
Percent of fluid produced by
artificial lift
45
Fluid produced by artificial lift
(million tons)
280
Tons of fluid per day per unit
17
26
35
35,
33-37 e
Average water-cut (percent)
44
47
58p
70e
78e
Oil production (million tons)
353
491
603
630 P
550-600 e
Note: p = Soviet five-year plan figures, and e = CIA estimates
based on review of Soviet publications. Derivative calculations in
the table are approximate because of rounding and inconsistency in.
available data.
about 70 percent in 1985-well above the 63 percent
earlier projected by Soviet planners. Our estimate
takes into account the 62-percent nationwide water-
cut reported for 1982 and the Soviet projections of a
47-percent water-cut in Tyumen' and a 54-percent
water-cut at Samotlor in 1983
The substantial impact of each 1-percent change in
water-cut on total fluid-lift requirements may be
illustrated by reference to the Soviet oil industry's
experience in 1980, as shown in table 2. If the average
water-cut had been 57 percent, as originally planned,
the 603 million tons of oil output would have implied
a total fluid production of 1,402 million tons. With
the 58-percent water-cut in the revised plan, however,
the implied production of total fluid for the year
amounted to 1,435 million tons. A 1-percent change
in water-cut implies the lifting of an additional 33
Pumping Requirements in 1981-90
In late 1982, in an article discussing requirements for
the coming decade, the Oil Minister stated that in
1985 and 1990 only 10 percent of the active wells are
expected to flow (either with natural reservoir pres-
sure or with pressure maintenance from water or gas
injection). This low proportion of flowing wells, com-
bined with the rapidly rising water-cut, implies a
tremendous need for more and better pumps of the
proper capacity if the Soviets are to avert a decline in
total oil production in the mid-1980s. The sharp
increases in requirements for artificial-lift equipment
estimated for 1985 and 1990 are illustrated in figure
million tons of fluid)
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Figure 5
USSR: Utilization of Artificial Lift, by Type
Gas lift
? Electric submersible pumps
? Rod-and-beam pumps
lift very rapidly-from over 71,000 to some 116,000
within five years. They expect to achieve much of the
planned increment in oil production from wells on
artificial lift by equipping about 19,000 more oil.wells
with submersible pumps and 4,000 more with gas lift.
The Soviets expected water-cut in the Tyumen' fields
of West Siberia to reach 47 percent in 1983, and the
conversion of roughly 20,000 flowing wells to pumps
should be well under way. The timing and rate of
decline of the older fields in. Tyumen' will not be easy
to offset or moderate by infill drilling because new-
well productivities there are declining. Thus, artificial
lift will be a major factor determining West Siberian
oil production. Nearly two-thirds of.the wells on
artificial lift in West Siberia are already equipped
with submersible pumps, according to a Soviet oil
industry journal.
To meet their current crude oil production plans for
1985, the Soviets have estimated that they must cope
with a 50-percent increase in total production of fluid
(oil and water) from oil wells. This is a planned
increase from about 1.4 billion tons in 1980 to about
2.1 billion tons in 1985. The task will call for
9oa expanding the number of producing wells on artificial
Since 1978, growth in Soviet oil production has
slowed to a crawl. A critical need for large amounts of
Western fluid-lift technology and equipment already
exists. This need should intensify as more of the giant
and supergiant fields age, become depleted, and begin
to produce mostly water. If adequate artificial-lift
equipment is not made available, Soviet oil output will
almost certainly decline sooner and more rapidly. The
oil-production history of the Tatar ASSR provides an
example of the requirement for artificial lift as water-
cuts increase. Tatar oil production reached a maxi-
mum of 104 million tons in 1974, when the average
water-cut for the region passed 40 percent. By 1980
the water-cut exceeded 60 percent, 98 percent of the
region's 14,000 active wells were on artificial lift, and
submersible pumps produced 75 percent of the 82
million tons of oil recovered
In early 1984 the USSR took initial steps to obtain
better pumps from the West, concluding a contract
with a US firm for the sale of 400 hi h- rformance
submersible pumps Their com-
bined annual capacity will be about 150 million tons
of fluid. Delivery and installation of all 400 pumps
will probably take 18 months and come too late to
have much impact on Soviet oil output in the current
five-year plan. These pumps will, however, help stem
decline in the 12th plan. Follow-on orders may be
included in future Soviet plans.
We believe that a failure to meet the massive needs
for artificial-lift equipment (which could stem in part
from constraints on investment and manpower alloca-
tions) would be a powerful force for decline in Soviet
oil production in the late 1980s. With respect to
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artificial lift alone, equipment supply in recent
years-under far less ambitious programs than will be
called for in the second half of the 1980s-has trailed
demand by about 15 to 20 percent annually.
Equipment and Maintenance Requirements
The USSR's oil output targets imply the need for a
sharp increase in the supply of artificial-lift equip-
ment. As water-cuts climb, so do the requirements for
high-volume submersible pumps. Providing them will
be a burdensome task for an economic system that in
1976-80 could supply no more than 82 percent of the
oil industry's pumping needs. It also implies a sub-
stantial additional task of providing the increase in
manpower and industrial supplies necessary for per-
forming maintenance tasks. Both will be difficult to
achieve.
Soviet industry has made little progress in developing
improved high-volume pumps since the need for these
items was first recognized in the 1970s. A plant was
activated at Al'met'yevsk in 1981, but in late 1982 its
serial production of these pumps still failed to meet
standards for quality and quantity. The Soviets have
made some advances by using their existing equip-
ment more efficiently, but significant technological
breakthroughs cannot be expected before 1990 unless
they improve their capabilities in metallurgy and
precision manufacturing.
Soviet plans for development of new oil reserves deal
with deposits much smaller in size than the giant
fields now being exploited. Thinner reservoirs and, in
some cases, higher viscosity crude oil will certainly
lower the well productivities and increase the need for
artificial lift. The heavier crude oil, in addition to
being more difficult to pump, usually contains more
corrosives and contaminants. The increase in average
viscosity; coming at a time when the Soviets will have
to pump over 3 tons of water for each ton of oil, will
greatly complicate their artificial-lift operations
Both factors-many more active oil wells and much
more artificial-lift equipment-could create a short-
age in well-maintenance services. In 1978, for exam-
ple, about 250,000 well-repair jobs (workovers) were
performed in the oil industry, ranging in difficulty
from cleaning the wellbore through repairing the
casing and pumps to reperforating the casing to
permit freer flow of oil into the wellbore. Some
216,000 of these repair jobs involved artificial-lift
equipment-submersible pumps, gas-lift units, and
rod-and-beam pumps. Workovers that require pulling
the equipment up to the surface occur three to four
times as often in the USSR as in the United States,
according to Soviet data.
The magnitude of the maintenance task is highlighted
by the following Soviet forecast of the approximate
number of oil wells that would have to be equipped
with artificial lift in 1985 and 1990 under the produc-
tion assumptions (in number of oil wells) underlying
the estimates shown in table 2:
Electric submersible pumps
36,500
40,000
Gas-lift units
6,500
12,000
Rod-and-beam pumps
73,000
103,000
Unless marked improvements in Soviet equipment
and technology reduce the time between repairs, the
requirement for well-repair jobs in the late 1980s
could top 500,000 a year.
Rod-and-Beam Pumps. Soviet rod-and-beam pumps
have an average service life of about 100 days be-
tween repairs (in the United States the equivalent
figure is 350 days). Most mechanical breakdowns are
caused by: (1) breakage of pump rods (currently,
nearly 16,000 per year because of their low tensile
strength), (2) poor sleeve bearings, and (3) sleeve
misalignments. Soviet oil wells using this type of
pump are deeper on average than those in the United
States, a factor contributing to the relatively greater
incidence of pump-rod failures.
For exploiting high-volume wells, rod-and-beam
pumps are less efficient than submersible pumps and
gas-lift equipment.
Submersible Pumps. Increased use of high-quality,
high-volume submersible pumps from the United
States-to date the only proven supplier-could re-
duce substantially Soviet manpower and maintenance
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requirements for oilfield operations and probably per-
mit higher oil output. Soviet and US electric submers-
ible pumps are of the same general design; indeed,
Soviet design standards are based on published US
pump specifications. However, the lack of appropriate
metallurgy and machining prevents Soviet pumps
from matching US standards for fluid output and
service life.
Submersible pumps have been installed at one time or
another in most oilfields with high-productivity
wells-Samotlor, Romashkino, Fedorovo, Arlan, Ne-
bit Dag, Uzen-Zhetibay, and many other Volga-Urals
and West Siberian deposits. Depending on pump size
and well conditions, US units can lift 200 to 3,000
tons of fluid per day. Soviet pumps average less than
100 tons of fluid daily, with only a few units lifting
more than 165 tons. (Soviet prototype units of 500- to
700-ton-per-day capacity are being tested.)
The Soviets have concluded-after many years of
experience in the same oilfields with domestic sub-
mersible pumps and with US Reda (TRW) and B-J
(Byron-Jackson) units-that the US pumps are about
twice as efficient as their own. Breakdowns are fewer
and average service life is longer-520 days between
major overhauls for US imports and some 240 days
for Soviet pumps-because of the more corrosion-
resistant metals and the far greater precision used in
the manufacture of US units.
Moreover, for pumps immersed in hot, corrosive
fluids, the Western-made electric-power cable is
much better than Soviet cable. The cost of any cable
for this purpose is high (usually exceeding the cost of a
pump at depths greater than 1,000 meters), but the
extra original cost of Western cable can provide
overall economies by reducing the incidence of short
circuits and burned-out pump motors
Gas-Lift Units. Gas-lift equipment requires less
maintenance than either rod-and-beam or submers-
ible pumps. It includes "downhole retrievable" pack-
ers, valves, and mandrels, all of which can be operated
from the surface by wireline tools. The related wire-
line tools (which are lowered into the well by small-
diameter steel cable) and special workover rigs permit
rapid workovers and minimum downtime for repairs,
but these advantages are largely offset by the much
greater initial capital costs of gas lift: the gas must be
brought to the oilfield and compressed before it can be
used. (If this initial cost is included, the US-made
submersible pumps are economically as efficient as
gas lift over the life of the well, despite their more
frequent repairs.)
In 1980 there were only about 2,300 gas-lift wells in
the USSR, but this number would at least double and
might increase tenfold by 1990 if the Soviets could
acquire (or copy) and assimilate more of the better US
gas-lift equipment and technology. In this event, the
Soviet need for high-capacity submersible pumps
could be lowered by about 50 percent, with consider-
able savings in maintenance manpower. This scenario
is unlikely, however: gas lift requires longer leadtimes,
associated with supplying and installing the necessary
compressors, downhole equipment, and gas supply
pipelines.
Currently, the huge 1,800-well Samotlor gas-lift proj-
ect is at least two or three years behind schedule. The
smaller 600-well Federovo project is nearing comple-
tion, but it was also delayed. Both projects were
supplied with critical US gas-lift equipment through a
US affiliate in Ireland. Other fields slated for gas-lift
operations include Barsa Gelmes, Kotur Tepe, Uzen-
Zhetibay, and several offshore fields in the Caspian
Sea.
Hydraulic Pumps. Hydraulic (rodless) pumps are
installed downhole, as are electric submersible pumps,
but they are operated by a fluid pumped at high
pressure from the surface instead of by electric mo-
tors. Hydraulic pumps are being tested in the USSR,
and oil industry planners have indicated an interest in
obtaining as many as 8,000 by 1990.
Workover Rigs, Self-Propelled Units, and Other
Equipment. During the 1970s the Soviet Union made
no substantial progress in well-repair engineering or
the manufacture of repair equipment. The number of
wells that need to be worked over each year increases
steadily, however, and now exceeds Soviet repair
capabilities. New workover rigs capable of lifting 100
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to 125 tons of pipe and of moving over snow and
swampy terrain are needed to service deep wells.
Better snubbing devices (small blowout preventers) are
required for raising and lowering tubing in high-
pressure wells. Development of new and improved
equipment is slow. For example, Soviet output of most
types of oilfield equipment lagged behind demand by
20 to 30 percent during 1971-79. Pump rods and
workover rigs were in especially short supply, and the
industry delivered only 58 percent of the dewaxing
equipment needed for cleaning deep wells, 46 percent
of the centrifugal pumps for water injection, and 73
percent of the wellbore compressors for gas-lift wells.
Soviet oil industry managers. recognize the efficiency
of Western equipment. Evidence of this is a plan of
1978 that-unrealistically-contemplated putting
some 40,000 oil wells on gas lift and 8,000 wells on
new hydraulic pumps during 1981-90
the use of West-
ern equipment for these installations over the decade
could yield the following savings:
? 32,300 rod-and-beam pumps and 2,200 workover
rigs.
? 1 million well repairs.
? 25,000 maintenance workers (they planned to re-
duce the maintenance force by this amount).
? Combined savings of perhaps 9.0-9.5 billion rubles.
The term enhanced oil recovery refers to a spectrum
of methods and techniques increasing the ultimate
recovery of oil from a reservoir beyond that attainable
by primary methods (natural reservoir energy) and
secondary methods (artificial maintenance of reservoir
energy and artificial lift). FOR extends oil production
by altering the forces that hold the oil in place.
The major categories of FOR are thermal and chemi-
cal. Thermal methods, aimed at reducing the viscosity
of the oil by heating, include:
? Cyclic steam injection (steam soaking).
? Steam drive (steam flooding).
? In situ combustion (fireflooding).
Chemical methods (also called miscible flooding) are
aimed a reducing the surface-tension forces between
the oil and the driving fluid. They include:
? Hydrocarbon miscible flooding.
? Carbon dioxide miscible flooding.
? Polymer-augmented waterflooding.
? Micellar-polymer flooding.
? Alkaline flooding.
A basic description of FOR methods and their appli-
cation is provided in the appendix, and three common-
ly employed methods are illustrated in figure 6.
The success of an FOR operation is critically de-
pendent on the composition and consequent behavior 25X1
of the injected fluids, the accuracy of the reservoir
engineering and modeling, and the process technology
employed. Each reservoir presents a different set of
technical problems, and the complex technology is not
directly transferable from one geologic formation to
another. Each oilfield requires at least one pilot test, 25X1
lasting up to five years. Once a pilot test is successful, 25X1
many new injection wells have to be drilled to bring
the project up to commercial size. After these wells
are drilled and injection of heat or chemicals has
begun, it may take as long as two years for additional
oil to appear at the original producing wells. Conse-
quently; FOR can be up to 10 times as labor intensive
as conventional oil production. 25X1
FOR offers high potential benefits. Its use can permit
the ultimate recovery of.as much as 90 percent of the
original oil in place (under ideal conditions), whereas
waterflooding can be expected to recover 30 to 40
percent. FOR also entails high cost and high risks.
Large expenditures for chemicals, equipment, man-
power, and capital must be made before it can be
known whether application of the process in an oilfield
is a success or a very expensive failure
Western oil companies' application of major technical
advances in FOR has been slowed temporarily by the 25X1
worldwide surplus of crude oil that has depressed
price levels, increased the risk element, and made
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FOR activities uneconomic. Company budgets are
now emphasizing projects with short payback periods,
and FOR is not only capital intensive but also slow to
pay off
Development of the Soviet EOR Program
Soviet petroleum specialists have recognized the need
to increase oil recovery from existing oilfields since
the early 1960s, but an FOR program was not given
high priority until 1976. In February of that year the
25th Congress of the Communist Party of the Soviet
Union stressed the importance of providing the econo-
my with an adequate supply of fuels and energy and
noted that the task would require a substantial im-
provement in the technology for exploiting oil depos-
its.
In September 1976 the deputy chairman of Gosplan,
A. Lalayants, announced a high-priority plan de-
signed to increase oil recovery from existing oilfields.
It called for:
e Setting timetables for adopting new recovery
methods.
c Establishing a special association within the Minis-
try of the Petroleum Industry for enhanced oil
recovery techniques.
Creating a special fund to help cover costs incurred
by oil-production enterprises adopting the new
technology.
Building new plants to produce large quantities of
specialized chemicals.
Producing large amounts of special equipment.
Training workers.
The Committee on Science and Technology of the
Council of Ministers was to be responsible for coordi-
nating the FOR program. The planners hoped that by
the early 1980s they would be recovering an addition-
al 10 to 15 percent of the original oil in place.F_~
Soviet petroleum officials have continued to empha-
size the importance of FOR endeavors. In September
1977 the Minister of the Petroleum Industry, N. A.
Mal'tsev, indicated that a long-term comprehensive
program had been formulated for commercial use of
new FOR methods-especially those employing sur-
face-active agents (surfactants), polymers, and carbon
dioxide-that would facilitate an increase in oil pro-
duction equivalent to the opening of several large
oilfields.
In January 1978 the Ministry of the Petroleum
Industry established a scientific-industrial association
for thermal oil recovery techniques, called Soyuzterm-
neft. This organization, centered at the Krasnodar
Scientific Research and Planning Institute for the
Petroleum Industry, is responsible for developing and
applying thermal oil extraction processes, designing
the machinery and equipment for these processes, and
supervising the operations at oilfields where these
processes are applied. N. K. Baybakov, Chairman of
Gosplan (and a former Minister of the Petroleum
Industry), has voiced a strong belief that FOR meth-
ods could make a significant contribution to improv-
ing the USSR's oil situation by increasing the amount
of recoverable reserves
Despite these optimistic plans and expressions of
confidence, the program is still in low gear. Commer-
cial production of oil via FOR techniques is only
about 60,000 barrels per day (3 million tons per year),
or approximately 0.5 percent of total Soviet oil pro-
duction. thermal
methods-injection of steam and hot water and in situ
combustion-account for about 70 percent of the
increased yield being achieved by use of FOR meth-
ods.
Although FOR technology will probably account for
only a low total yield of oil in the USSR during the
next 10 years, the Soviets will continue to use it in
existing fields into the 1990s and beyond. This is
because FOR offers the possibility of producing addi-
tional oil from existing fields, where the infrastructure
is already in place. Therefore, despite its costliness,
FOR is claimed to be cheaper than the exploration
and development of small West Siberian deposits and
potential new fields in East Siberia and offshore in the
Arctic seas. And the Soviets can expect oil recovery to
increase with improvements in technology and equip-
ment-much of it to be acquired from the West.
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Figure 6
Selected Methods of Enhanced Oil Recovery
Steam flooding
302810 4-84
Producing well
Oil and water
In situ combustion
Micellar-polymer flooding
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Soviet FOR efforts have been hampered by shortages
of equipment and chemicals. In 1979 the Soviet press
reported that domestic industry had delivered only 2
percent of the equipment for that year's planned FOR
work and that much of what it delivered was of
inferior quality. The inadequacies of domestic steam
generators were especially noted, as was a shortage of
chemicals. Two years later the first deputy minister of
the petroleum industry in charge of FOR work, E. M.
Khalimov, indicated that Soviet machine-building
plants had not fulfilled their plans for the manufac-
ture of equipment and spare parts for thermal opera-
Table 3
Oil Produced by Enhanced
Oil Recovery Methods
Total
1,616
8,598
Over 10,000
Thermal methods
1,421
5,922
About 7,000
Chemical methods
195
2,676
About 3,000
tions and that the chemical industry had not produced,
nearly enough chemical agents. The results of the Romashkino. This mature supergiant oilfield has
Soviet FOR program during the past 15 years are dominated oil production in the Tatar ASSR since the
summarized in table 3. early 1950s; until 1977 it was the largest oilfield in
the USSR, in terms of both production and reserves.
Soviet Application of FOR
Since the mid-1960s, Soviet specialists have conduct-
ed laboratory and pilot tests on various thermal and
miscible flooding processes, with varying success.
They appear to be aware of every FOR process that
has been tried in Western fields and laboratories, and
they are pioneers in the thermal mining of extremely
.viscous deposits and the nuclear stimulation of oil
deposits. A summary of the major FOR projects
conducted or planned is shown in table 4. FOR
techniques applied or planned at major oilfields in-
clude chemical (polymer) flood at Arlan, miscible
flood at Romashkino, thermal methods at Baku, and
thermal mining at Yarega.
. Arlan. The giant Arlan field is a major producer of
heavy, viscous oil. Output has been declining steadily
since peak production was reached in the early 1970s.
The nature of the reservoirs at Arlan is such that
polymer flooding is the only technique that offers
promise for increased oil recovery, and the Soviets
have been experimenting with it there since 1966.
They.are still in the experimental stage. Polymer
injection on the large scale required at Arlan has
never been employed before; its effectiveness is uncer-
tain, and the cost and risk would be very high. In any
case, the Soviet chemical industry cannot currently
supply polymers in the amounts needed for a full-scale
polymer flood at Arlan.
It still ranks second only to the Samotlor field as a
major producer, though its output has been declining
after reaching a peak of 80 million tons in the early
1970s.
The Soviets consider the carbon dioxide method of
FOR the most suitable for conditions at Romashkino
and have announced elaborate plans for its use there.
Because of the complex nature of the producing
formations (already damaged by the way in which
waterflooding was applied earlier in their exploita-
tion), the Soviets probably cannot use CO2 in more
than 10 of the field's 23 producing areas. Even so,
however, this project would need 10 times as much
CO2 as may be available from a chemical plant built
near Tol'yatti by a West German firm.
Even if sufficient CO2 were available, the Soviets
probably would recover no more than 130-200 million
tons of additional oil over a 20-year period. This
would be a very modest return at a very high cost. The
Soviets appear to be having second thoughts about the
project-they recently delayed indefinitely the con-
struction of the pipeline that was to deliver the CO2 to.
the Romashkino area.
Baku Area. Production at Baku, the oldest producing
oil region of the USSR, has been declining despite
efforts to explore and develop new fields in the
offshore areas of the Caspian Sea. Since the 1970s,
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Table 4
Major Soviet Enhanced Oil Recovery Projects
Kura flood plain fields (Azerbaijan
SSR) Tatar fields (Tatar ASSR)
Pilot projects in operation.
Polymer
Arlan (Bashkir ASSR)
Major pilot project has increased oil yields.
Alkaline
Arlan (Bashkir ASSR)
Projects are under way in heavy oil deposits.
Acid
Tatar fields (Tatar ASSR)
Pilot tests have been under way for some years.
Miscible flood
Enriched gas
Bashkir fields (Bashkir ASSR)
Tests have used hexane, methane, and propane.
Carbon dioxide
Romashkino (Tatar ASSR)
Major project is planned, but delayed because of -
uncertain CO2 supplies and shortage of hard currency
for Western equipment.
Steam drive
Baku (Azerbaijan SSR)
Produced 40,000 tons of additional oil at three
deposits during 1976-80.
Cyclic steam flooding
Karazhanbas (Kazakh SSR)
Test project is under way.
In situ combustion
Khorosany and Balakhany (Azerbaijan
SSR)
Incremental output of 100,000 tons produced during
1976-80.
Process has been in commercial use since 1972.
Grachevka (Bashkir ASSR), Osa
(Bashkir ASSR), Salym (West Siberia)
No details are available on increases in oil yields at
these fields over time.
FOR methods have been applied in several oilfields in
the region and have provided small additional yields
of oil. During the five-year period 1976-80, applica-
tion of surfactants to oilfields in the Kura flood plain
facilitated the output of an additional 140,000 tons of
oil, steam injection in old deposits near Khorosany
produced an additional 40,000 tons of oil, and in situ
combustion at old oilfields near Ramaninskoye and at
the Artem Islands produced an additional 100,000
tons
Shortcomings abound in FOR work in the area,
however. Open Soviet sources describe producers as
reluctant to experiment as long as there is no prospect
of an immediate payoff, equipment shortages persist,
and much of the available equipment is of poor
Yarega. The field at Yarega contains a highly viscous
crude that is not recoverable by conventional means.
To exploit it, the Soviets developed a thermal mining
method that has been in commercial use since 1972;
they claim that it permits recovery of 50 percent of
the original oil in place
In the thermal process, two mine shafts are sunk to a
level above the pay zone, and horizontal passages are
drilled and blasted to form galleries for underground
drilling and production operations. From these galler-
ies shallow production wells-either slanted or hori-
zontal-are drilled into the reservoir. Steam is inject-
ed, and the resulting flow of oil and water is
quality.
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channeled into a sump. Oil is separated from the For thermal FOR work, the USSR purchased 15
water and pumped to a central collecting point, where high-capacity steam generators from a US firm in
it is heated and pumped to storage tanks on the March 1978 for use in pilot projects in five old oil-
surface producing areas. None was placed in operation before 25X1
mid-1980, because of the lack of competent Soviet
Dependence on Western Equipment personnel. The Soviets apparently had appropriated
and Technology $81 million in 1981 for purchase of US steam injec-
As the Soviets seek to increase the application of FOR tion equipment to increase oil production in the Baku
technology, their reliance on Western equipment and region by 5.5 million tons per year and at the Uzen'
know-how will continue until they can train their own oilfield in Mangyshlak by 6.25 million tons per year.
personnel and develop their own manufacturing capa- After the US embargo on sales of oilfield equipment
bilities. Since 1978 the Soviet Union has entered into to the USSR was imposed in that year, the Soviets
negotiations and signed contracts with US, Japanese, began trying to obtain Western-built steam genera-
and West European firms for the supply of FOR tors
equipment, chemicals, and plants to produce carbon F_
dioxide and surfactants.
In the fall of 1977 an Italian firm, Pressindustria, was
awarded a $24.5 million contract to build a plant for
the annual production of 250,000 tons of surfactants
for tertiary oil recovery. It was to have been complet-
ed in 1979, but no reports of its. operational status are
yet available. Two carbon dioxide liquefaction plants
(together valued at $38 million) were ordered in 1978
from a West German company, Borsig, to support
miscible flooding operations. One of these, with a
capacity of 1 million tons per year, was built near
Tol'yatti for a miscible flood project at the Romash-
kino deposits. The second, with a capacity of 400,000
tons per year, was to have been installed at Kemerovo
in Siberia; information on its status is not available.
The Tol'yatti plant will take the CO2 produced as a
byproduct at nearby ammonia synthesis plants and
liquefy it. To use the liquid for FOR projects, the
Soviets will have to build a 300-km pipeline to the
Romashkino fields, plus pumping stations, CO2 han-
dling equipment, and CO2 injection facilities. In about
1980, they began negotiating with US, French, and
Japanese firms for assistance in this CO2 flood proj-
ect, but in 1981 they downplayed it for various
reasons. In April 1981 they claimed that it was
delayed indefinitely because of uncertainty about CO2
supplies from the ammonia plants and disagreement
on whether the CO2 should be piped in gaseous or
liquid form. In March 1982 the project was reported
to be "on the shelf' because other projects had higher
priority.
but no additional units have
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In early 1982, Soviet officials stated that efforts to
obtain Western steam generators and FOR technol-
ogy had been suspended indefinitely for lack of hard
currency.
however, any future purchases of steam generators
would have to include a turnkey package because
Soviet petroleum engineers and technicians cannot
properly use the equipment already obtained. Without
Western equipment and technology, the Soviet FOR
program probably will remain insignificant.
Plans and Prospects for the ]1980s
The Soviet enhanced oil recovery program is unlikely
to achieve significant increases in oil production dur-
ing the 1980s and probably will never reach the goal 25X1
(set in 1976) of recovering an additional 10 to 15
percent of the original oil in place. The evidence
shows ambitious plans repeatedly being downgraded
as the realities of the task strike home
In 1980 a deputy minister of the petroleum industry
revealed that the USSR wanted to obtain an addition-
al 125 million tons per year of oil from FOR opera-
tions by 1985, but he admitted that this timetable
could not be met because of serious technical and
bureaucratic problems. A few months later he ac-
knowledged that this goal was to be attained "eventu-
ally."
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17.1 million tons in 1985 and 35.7 million tons in
1990. Announcements in 1981 revealed that the
amount of oil to be obtained from FOR techniques
during 1981-85 would be double the more than 10
million tons produced during 1976-80. But in October
1981, First Deputy Minister E. M. Khalimov, the
director of FOR efforts in the Oil Ministry, was
dismissed for falsifying data and wasting materials-
casting further doubt about the realism of the Soviet
FOR goals.
Enhanced recovery operations are often viewed by
Soviet specialists as a straightforward development
and application of new technologies. But, when new
techniques (developed and tested under laboratory or
pilot project conditions) are applied in the field to
heterogeneous oilfield reservoir structures and per-
meabilities, unforeseen difficulties can crop up. Ef-
forts to cope with these difficulties are very expen-
sive-requiring careful management and control,
large quantities of specialized chemicals and equip-
ment, and considerable time. On the basis of the
revised plans and Soviet performance thus far, we
judge that-oil production from FOR methods will
reach only about 4 million tons in 1985 and no more
than 10 million tons in 1990.
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Appendix
Enhanced Oil Recovery
Techniques
Enhanced oil recovery (EOR) methods are generally
categorized as thermal and miscible. Thermal meth-
ods are considered to be the most advanced, and
large-scale applications are under way in several
countries. Field tests of the miscible flooding process-
es are under way, as well as some commercial applica-
Steam Drive (SteamfloodingA This process involves
the continuous injection of steam or hot water, or a
mixture, into a group of outlying wells to push oil
toward producing wells. It creates a series of tempera-
ture zones in the reservoir: nearest the injection wells
is a steam zone, pushing a zone of hot water, which
pushes a zone of hot water plus oil. The steam and hot 25X1
water heat the oil, removing it from the deposit and
Thermal Methods
Thermal methods are aimed at reducing the viscosity
of the oil by heating and, in some cases, changing the
characteristics of the oil. These methods are most
widely used for highly viscous, low-gravity crude oils
Cyclic Steam Injection (Steam Soak). High-pressure
steam generated at the surface is injected into a
producing well for several weeks. Then the well is
capped and allowed to "soak." After four to 10 weeks,
the well is placed back on production and the accumu-
lated oil and water are allowed to backflood to the
surface. As the pressure in the well decreases, some of
the water that had condensed under pressure from the
injected steam vaporizes and drives heated oil toward
the producing well. Oil production is highest when the
well is first reopened and declines as steam is con-
sumed. When it has declined to a predetermined level,
the entire cycle can be repeated, but the process
gradually becomes less efficient. Because of its cyclic
nature, the process is often called the huff-and-puff
method of oil recovery.
The value of cyclic steam injection lies not so much in
improving ultimate recovery as in increasing the oil-
production rate. The average rate when the well is
reopened is 10 to 30 times the pretreatment rate. The
major inefficiency of the process is the loss of heat. It
is not useful in strata of oil-bearing sands thinner than
20 feet, because too much heat escapes to the rocks
23
forcing it to the producing wells
Steam drive is likely to be the technique most widely
applicable. It recovers an additional 35 to 50 percent
of the original reservoir oil in place, depending on oil
and reservoir characteristics." The success of a steam- 25X1
ing project depends on the rapid, continued growth of
a steam zone with resulting high rates of oil displace-
ment. Heat losses must be minimized. The major
practical problems are isolating the geologic zone to
be steamed, injecting steam into selected wells, pump-
ing the hot wells, handling the excess associated water
production, controlling the sand produced (to avoid
sand-plugging of the well or of lines at the surface),
and coping with the weakening effect of high tem-
peratures on the equipment.
In Situ Combustion (Fireflood). This is another meth-
od of heating the oil in the reservoir to reduce its
viscosity. Air is injected into the reservoir, providing
oxygen so that some of the trapped oil will burn.
Combustiorimay be spontaneous when the injected
airflow is large enough to cause gas saturation, or a 25X1
heater may be lowered to initiate combustion. Heat
from the burning oil thins the remaining oil, partially
vaporizing it, and the steam, hot water, and hot gas
' Raising the recovery rate from 33 percent of oil in place (OIP) to
45 percent actually recovers only 12 percent of OIP. This is the
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produced by the fire push this more fluid oil toward
the producing wells. Usually air is injected through
one set of interlocking wells, and oil is produced from
another set.
The three basic types of in situ processes are: conven-
tional, or forward combustion; wet combustion, a
combination of forward combustion and waterflood;
and reverse combustion. In forward combustion, a fire
is started in the formation at the bottom of an
injection well. In wet combustion, a similar fire is
started, then water is injected alternately with air to
transfer heat (in the form of water vapor) from the
burned region through and ahead of the combustion
front. In reverse combustion, the reservoir oil is
ignited at the production wells rather than at the
injection wells.
In situ combustion is the most difficult of the tertiary
processes to model and predict. Most of the operating
problems arise from the high temperatures involved.
Thermal stresses on cement, pumping equipment, and
tubing increase the frequency of their failure, and the
composition of the combustion gases, together with
high temperatures, accelerates corrosion problems.
Sand production causes clogging and severe wear
(abrasion) in pumping equipment
Miscible Methods
Miscible methods of enhancing oil production are
aimed at reducing the surface-tension forces that bind
the oil to rock. These include the use of hydrocarbons
and carbon dioxide and the chemically augmented
methods (polymer, micellar, and alkaline flooding). F
Hydrocarbon Miscible Flooding. Light-to-intermedi-
ate-weight hydrocarbons-such as dry gas, propane,
butane, and liquefied petroleum gas (LPG)-are in-
jected to mix with the reservoir oil, forming a bank of
oil and driving it toward producing wells. This tech-
nique requires high pressures and is limited to fairly
deep fields, where the. threat of rupturing the cap rock
is small. It is also energy intensive, not only because
the miscible slug is a hydrocarbon derivative (that is,
it uses oil to produce oil) but also because compression
is required
Carbon Dioxide Miscible Flooding. Injected CO2
dissolves in crude oil, reduces its viscosity, and in-
creases its permeability and bulk. The swelling in-
creases reservoir pressure, while the reduced viscosity
lets the oil flow more readily toward the production
wells. A slug of water injected after the slug of CO2
drives the gas away from the injection well. When
CO2 appears at the producing well, it is recovered,
cleaned of impurities, compressed, and reinjected. F
Carbon dioxide flooding appears to be the most
promising of the miscible. methods. However, its use
probably will be limited to fields of light oils that are
relatively close to sources of CO, because the com-
pression and transport of the gas is expensive and
energy intensive. The effectiveness of this FOR meth-
od depends greatly on reservoir homogeneity, and at
best it can probably recover no more than 10 to 15
percent of the oil remaining after waterflood.0
Polymer-Augmented (Enhanced) Waterflooding.
Chemicals with high molecular weights (polymers)
can be added to injected water to increase its effective
viscosity and its efficiency as a front to drive oil
toward producing wells. The increased viscosity re-
duces the flow of water in the reservoir formation and
improves its ability to sweep out the oil. The use of
polymers reduces the ratio of water to oil and thus
reduces overall operating costs.
Enhanced waterflood can potentially recover more of
the original oil in place than can a plain waterflood.
However, the rate of oil recovery with either method
is the same during the first few years of operation.
Moreover, enhanced waterflooding poses formidable
engineering problems, and there are no well-defined
measuring techniques to optimize the process
Micellar-Polymer Flooding (Surfactant Flooding).
This category of FOR includes a number of processes
based on the injection of detergent solutions. Chemi-
cals are employed to wash the reservoir rock, much as
laundry detergent washes away greasy stains. In a
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micellar flood, a water.slug containing a small
amount of surfactant is injected into the reservoir.
The solution is called micellar because its concentra-
tion causes the surfactant molecules to cling together
in clusters called micelles. Because the microemulsion
formed is miscible with oil, it dissolves the oil in the
formation. At the same time, the emulsion reduces
interfacial tension between the oil and water, permit-
ting the oil to flow freely out of the rock pores
As is the case with most FOR processes, each surfac-
tant flood must be precisely designed for the specific
reservoir. The concentrations and types of chemicals
used will depend on the crude oil composition, the
reservoir temperature and clay content, and the ion
concentrations in the reservoir water. The surfactant
injection must be carefully designed for minimum
absorption by the. porous media in the reservoir and
maximum sweep efficiency.
Alkaline Flooding. Caustic chemicals like sodium
hydroxide or sodium silicate reduce the interfacial
tension between the injected fluids and the reservoir
oil. Added to injection water, they form surfactants
within' the reservoir by neutralizing the petroleum
acids. Alkaline flooding processes are still in a testing
stage. Their success depends on the chemical and
physical properties of the reservoir materials, the
composition of the crude oil, and the effectiveness of
surfactants formed when the caustic chemicals react
with different acidic compounds in the reservoir.
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 S
Major Soviet Petroleum Deposits and Oil Pipelines
For Release 2009/06/04: CIA-RDP85TOO313R000100040005-4
Nethei ds Norway a s+ a~ jJ~ J(~/J~~
9
Fed. Rep. Den .., QI A r c t i c O c e a n
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.01965(54373314-63
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25X1