Note: Descriptions are shown in the official language in which they were submitted.
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TITLE OF THE INVENTION
Steam Anti-Coning/Cresting Technology ( SACT) Remediation Process
BACKGROUND OF THE INVENTION
As illustrated in Figure 1A, many oil reservoirs have an active bottom water
zone 20 beneath a
net-pay zone containing oil. If oil, particularly high viscosity in-situ oil,
is pumped from a
vertical well completed in the oil zone, water can cone up to the production
well and inhibit
production. In terms of production, coning will reduce oil cuts and increase
water cuts until it is
no longer economic to produce the well. In the industry, the well is said to
have "watered off".
The mobility ratio of the oil determines the rate and extent of water coning.
Typically, when the
oil is heavier, the worse the water-coning problem is. As illustrated in
Figure 2, the problem may
also be exhibited in SAGD for bitumen recovery with bottom water reservoirs.
Attempts have been made to prevent coning/cresting when reservoir
characteristics are known.
However, these attempts have had limited impact. Examples of attempts include
the following:
1) The production well is completed higher up in the net pay zone, so the
water cone has to be
elongated before the well waters off. This is a temporary fix at best, and
extra production is
often marginal.
2) As illustrated in Figure 1B, a horizontal well is drilled so the pressure
drop of pumping is
spread over the length of the horizontal well. However, water will eventually
encroach to the
well and produce a water crest zone 10 of high water saturation. Similar to a
vertical well, the
well will water off.
3) Oil production rates are minimized to delay or prevent coning/cresting
4) As illustrated in Figure 3, downhole oil/water separator 30 (DHOWS) with
downhole water
disposal is installed. (Piers, K. Coping with Water from Oil and Gas Wells,
CFER, June 14,
2005). The downhole device can be a cyclone. This device, however, requires a
suitable disposal
zone 40 for water, and it works best on light oils with a high density
difference between water
and oil. This is not practical for heavier oils.
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5) As illustrated in Figure 4, a reverse coning system 50 is installed (Piers,
2005). Water 60 and
oil 70 are produced or pumped separately in this system to control coning.
Again for heavier oils,
the water pumping rate to control coning is very large and impractical.
There have also been attempts to limit the coning/cresting when reservoir
characteristics are
unknown or coning/cresting isn't large enough to justify prevention
investments. Known
remediation attempts have had limited impact. Examples of these attempts
include the following:
(1) Blocking agents are used to inhibit water flow in the cone/crest zones.
Blocking
agents include gels, foams, paraffin wax, sulfur, and cement. Each of these
have been
tried with limited success (Piers (2005)), (El-Sayed, et al., Horizontal Well
Length:
Drill Short or Long Wells?, SPE 37084-MS, 1996).
(2) Another reactive process is to shut in the oil well that has
coned/crested. Gravity will
cause the cone/crest zone to re-saturate with oil. However, when the oil is
heavier, the
time for re-saturation can be very long and the benefits can be marginal.
(3) A slug of gas is injected into the cone/crest zone. In the early
1990's, a process called
anti-water coning technology (AWACT) was developed and tested in medium/heavy
oils (AOSTRA, AWACT presentation, March 1999). The AWACT process involves
injecting natural gas (or methane) to displace water, followed by a soak
period
(Luhning et al, The AOSTRA anti-water coning technology process from invention
to
commercial application, CIM/SPE 90-132, 1990). Lab tests indicated that the
preferred gas (CO2 or CH4) has some solubility in oil or water (Figure 9). The
following mechanisms were expected to be activated.
a. On the "huff' part of the cycle or when gas is injected, methane displaces
mobile
water and bypasses the oil in the cone zone.
b. On the "soak" cycle or when the well is shut-in, methane absorbs slowly
into the
oil to reduce viscosity, lower interfacial tension, and cause some swelling
c. On the "puff' cycle or when the well is produced, gas forms ganglia/bubbles
that
get trapped to impede water flow. As illustrated in Figure 5, this creates a
change
in relative permeability. Oil cuts are improved and oil production is
increased.
However, benefits only last a few years, and the process can only be repeated
5 or 6
times. Table 1 below summarizes AWACT field tests for 7 reservoir types
(AOSTRA
(1999)). Oil gravity varied from 13 to 28 API, and in situ viscosity varied
from 6 to 1200
cp. AOSTRA suggested the following screens for AWACT ¨ 1) sandstone reservoir;
2)
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oil-wet or neutral wettability; 3) in situ viscosity between 100 to 1000 cp;
4) under
saturated oil; and 5) greater than 10m net pay.
Table 1:
AWACT Reservoir Characteristics
th Jenner AWACT Treatment Summarx
(Rased on 34 treatments evaluated)
Average Prixlitetion AWACT AWACT Net
Prechter* AwAer Gas Slug
Well Pre AWACT Nast AWACT Duration
m3 oil/ m3 wale Site Ratio
Grouping MOPE) OC% MOM) AC% Months One
Year Duration km3 at3m3
1. All welts 30 9.7 29 199 22
'73079003 3151(17.700) 144 220
2. 30 wets with increased 30 10.0 2.9 211 23
10208,800) 365/(19,900) 148 22..0
OC
3. 15 welk with iortrascd 2.5 11.7 31 25 5 23 630,0
t,t00) 1.350426.5002 148 25.4
MOPE)
4. 19 wells with decreased 3.4 7.9 2.2 15.2 21
(370)05400) t0y(10,700) 151 20.1
MOPE)
5. 14 wells with increased 26 120 4.1 273 23
650011.700) 14001(27,900) 154 33,0
MOPE) & OC
6. 10 water wetting mated 2.9 94 3.3 19.0 28 21547003
60011.240001 119 21.4
wells
7. 23 nort.ekernically 30 9.6 2.8 20.6 19 010001
165015.000) 167 27.4
treated wells
) numbers in brackets are negative
* ratio is m3 gas per 1113 of cumulative oil production prior to treatment
Reservoir Characteristics of Other .Aymer Treated Pools
Net Meer 011 OS
Pay Permeability Parise
Saturation Gravity V lecosity Pressure At) =
Field Formation Am c11 kPit
m3/n3
frac.
Bershil Lake Basal 12 - 13 900 0.23 0.29 28
9.2 5900 20
OuartriElletslie
Provost , Dina 8.5 1000 0.22 0.35 28 8.5
nal 30
, Chin Coulee , Taber 7.8 56$ - 1000 0,20 0.30 24 140
8274 res
Suffield _qpper Mannville 16 1000 0.27 0.25 13 -
14 500 8780 20
NOW& , McLaren 15 1000-5000 0.31 0.30 13 1200
nia 14
Jenner upper Mannville 32-16 1000- 2000 0.26
0.27 16 - 17 66 , 9010 33
Grassy Lake Upper Mannville 18 - 17 1000- 2000 0.27
0.23 17 - 19 7$ 9600 11
*Initial Reservoir GOR
As illustrated in Figures 6 and 7, AWACT was not always a success (Lai et al.,
Factors
affecting the application of AWACT at the South Jenner oil field, Southeast
Alberta,
JCPT, March 1999). As illustrated in Figure 8, a test on a horizontal well was
inconclusive (AOSTRA (1999)).
=
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4) Cyclic CO2 stimulation is also a method to recover incremental oil. (Patton
et al,
Carbon Dioxide Well Stimulation: Part 1 ¨ A parametric study, JPT, August
1982). As
illustrated in Figure 10, process efficacy drops off dramatically for heavier
oils.
Because of the limitations of the prior art, there is a need for a remediation
process that
reacts to the cresting/coning in oil wells, preferably heavier oil wells.
SUMMARY OF THE INVENTION
The following terms and acronyms will be used herein:
AOSTRA Alberta Oil Sands Technology Research Authority
AWACT Anti-Water Coning Technology
UNITAR United Nations Institute for Training and Research
JCPT Journal Canadian Petroleum Technology
CIM Canadian Institute of Mining
SPE Society of Petroleum Engineers
JPT Journal Petroleum Technology
SAGD Steam Assisted Gravity Drainage
GOR Gas to Oil Ratio
OC Oil Cut
Kro Relative permeability to Oil
Krw Relative permeability to Water
SACT Steam Anti Coning/Cresting Technology
STB Stock Tank Barrels
SRC Saskatchewan Research Council
HZ Horizontal (well)
VT Vertical (well)
OSR Oil to Steam Ratio
SOR Steam to Oil Ratio
DHOWS Down Hole Oil Water Separator
EOR Enhanced Oil Recovery
REC Recovery
00IP Original Oil in Place
Because of the need for a cresting/coning remediation process, SACT is a
process that adds
steam to the cone/crest zone and heats oil in the cone/crest zone and at the
cone/crest zone edges.
In a preferred embodiment, the steam addition is followed by a soak period to
allow further
heating of oil and to allow gravity to cause a re-saturation of the cone/crest
zone. Preferably after
the soak period, the oil well may then be returned to production.
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Preferably, the SACT process is applied to 1) heavy oils where native oil
viscosity is too high to
allow rapid oil re-saturation of the cone/crest zone, preferably where the
viscosity is >1000cp,
and 2) bitumen (SAGD) wells.
According to a primary aspect of the invention, there is provided a cyclic
remediation process to
restore oil recovery from a primary well that has watered off from bottom
water encroachment
(cone or crest) whereby:
(1) The primary well has a produced water cut in excess of 95% (v/v),
(2) The oil is heavy oil, preferably with in-situ viscosity > 1000 cp,
and wherein said process comprises:
(3) Injection of steam in the cone/crest zone preferably by a steam slug
with a
preferred volume of 0.5 to 5.0 times the cumulative primary oil production,
preferably where said steam is measured as water,
(4) After steam injection is complete, the well is shut in for a soak
period,
(5) The well is then produced until the water cut exceeds 95%
In a preferred embodiment of the process the well was previously steamed.
Preferably the steam is injected using the existing primary oil production
well.
In an alternative embodiment, the steam is added using a separate well.
In another embodiment of the process, the primary well is a horizontal well
and bottom water
encroachment forms a water crest zone beneath the primary well.
In another embodiment, in the event that the primary well is not suitable for
steam injection,
several substantially parallel horizontal wells may be linked with a separate
perpendicular
horizontal well completed in the steam crest zone of each of the parallel
horizontal wells.
Preferably several of the substantially parallel horizontal wells may be
linked at or near the
midpoint of the horizontal well lengths, in the crest zone.
In another embodiment, the heavy oil is bitumen (API <10; >100,000 cp).
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In another embodiment, there is provided a cyclic remediation process to
restore bitumen
recovery from a bitumen well that has watered off from bottom water
encroachment (cone or
crest) whereby:
(1) The primary well has a produced water cut in excess of 70% (v/v),
(2) Injection of steam in the cone/crest zone preferably by a steam slug with
a
preferred volume of 0.5 to 5.0 times the cumulative primary oil production,
preferably where said steam volumes is measured as water volumes,
(3) After steam injection is complete, the well is shut in for a soak period,
(4) The well is then produced until the water cut exceeds 70%.
In another embodiment, the bitumen production well is used for steam
remediation injection.
In another embodiment, steam injection rates (measured as water) are 0.5 to
5.0 times fluid
production rates when the primary well had watered off.
Preferably the steam quality at the steam injector well head is controlled
between 50 and 100%.
Preferably the well is shut in for a soak period of 1 to 10 weeks.
BRIEF DESCRIPTION OF THE DRAWINGS
Figures IA and 1B respectively depict the water cone lean zone of a vertical
production well and
the water crest lean zone of a horizontal production well
Figure 2 depicts a SAGD Bitumen Lean Zones (Bottom Water)
Figure 3 depicts the prior art DHOWS concept
Figure 4 depicts the prior art Reverse Coning Control
Figure 5 depicts the AWACT effects on Relative permeability
Figure 6 depicts the Incremental AWACT Reserves in pre and post AWACT oil
recovery
Figure 7 depicts the Frequency distribution of incremental oil following AWACT
Figure 8 depicts oil production and oil cut history of horizontal wells pre
and post AWACT
Figure 9 depicts the AWACT laboratory tests and water-oil ratios versus time
of various gases
Figure 10 depicts the stimulation of CO2 of Oil Wells versus oil viscosity
Figure 11 depicts the injection of steam via a steam string for SACT according
to an
embodiment of the present invention
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Figure 12 depicts the injection of steam via a separate steam injector for
SACT according to an
embodiment of the invention
Figure 13 depicts SACT well for Crested Heavy Oil Wells
Figure 14 depicts SAGD partial coning/ cresting
Figure 15 depicts heat conducted around a hot well
Figure 16 depicts SACT simulation in vertical and horizontal wells according
to the present
invention
Figure 17 depicts SACT simulation in horizontal wells
Figure 18 depicts SACT Scaled Physical Model Steam Injection Rates
Figure 19 depicts SACT Scaled Physical Model Steam Slug Sizes
Figure 20 depicts SACT Scaled Physical Model Water Cut Offs
Figure 21 depicts SACT Scaled Physical Model Horizontal Well Lengths
DETAILED DESCRIPTION OF THE INVENTION
SACT is a remediation process for heavy oil wells (or for SAGD) that have
coned or crested due
to bottom water encroachment. The process is cyclic and has the following
phases:
(1) The primary production well is shut-in due to high (or excessive) water
cuts from
bottom water encroachment (coning or cresting).
(2) Steam is injected into the cone or crest zone with at least a
sufficient volume to
displace the bottom water in the cone/crest zone.
(3) The well is shut-in to soak for a period of time (weeks-months). This
allows heat
from the steam to be conducted to oil in/near the cone/crest zone, reducing
the oil
viscosity by heating and allowing the oil to re-saturate the cone/crest zone
by
gravity.
(4) The well is put back on production.
(5) The process can be repeated.
One of the issues for a conventional heavy oil production facility is that
primary production
wells are not designed for steam injection. The production wells can be
damaged by thermal
expansion, and the cement isn't designed for high temperature operations. This
problem can be
mitigated by one of the following options:
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(1) As illustrated in Figure 11, the use of an injection string 80 with
separate tubing
(and insulation) for steam 90 injection to minimize the heating of the primary
well
110; or
(2) As illustrated in Figure 12, drill and thermally complete a separate
steam injection
well 100 for remediation of a single well 130; or.
(3) As illustrated in Figure 13, drill and thermally complete a separate
steam injection
well 100 linked to several wells 140 150 160, allowing for simultaneous
remediation.
Referring to Figure 11, an injection steam string 80 with separate tubing and
insulation to
minimize the heating of the primary well 110 is shown. The well in this
instance may be vertical
or horizontal.
Referring to Figure 12 a separate steam injection well 100 is used to inject
steam in to the water
cone 120 according to the present invention. In this Figure, a vertical well
configuration is
shown for use with a single primary production well 130.
Referring to Figure 13 a SACT steam injector horizontal well 100 is linked to
a plurality of
horizontal producing wells 140, 150 and 160 to ensure crested heavy oil wells
are simultaneously
remediated according to the present invention.
Bitumen SAGD is a special analogous case for SACT process applications. If the
SAGD project
has an active bottom water 20, we can expect that the lower SAGD production
well will
cone/crest eventually (Figure 2). Bitumen (<10API, >100,00cp in situ
viscosity) is heavier and
more viscous than heavy oil (1000 to 10,000cp), but after bitumen is heated it
can act similarly to
heavy oil.
If bitumen is above an active bottom water, SAGD can, theoretically, produce
bitumen without
interference from bottom water, if process pressures are higher than native
reservoir pressure, if
the pressure drop in the lower SAGD production well doesn't breach this
condition, and if the
bottom of the reservoir (underneath the SAGD production well) is "sealed" by
high viscosity
immobile bitumen underneath the production well. But, this is a delicate
balance for the
following reasons:
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(1) Steam pressures can't be too high or a channel may form allowing
communication with the bottom water. Subsequent fluid losses can, at best,
reduce efficiency and at worst, shut the process down. Water production will
be
less than steam injection.
(2) The initial remedy to this is to reduce pressures. But, steam pressures
can't be too
low or water will be drawn from the bottom water zone into the production well
(coning/cresting). Water production will exceed steam injection. Also, one of
the
process controls for SAGD is sub-cool (steam trap control) assuming the near-
well bore zone is at saturated steam temperature. This control will be lost
when
bottom water breaches the production well.
(3) As illustrated in Figure 14, if the SAGD reservoir is inhomogeneous or
if the
heating pattern is inhomogeneous, the channel or the cone/crest can be partial
and
the problem can be accelerated in time.
(4) Initially, cold bitumen underneath the production well will act as a
barrier to
prevent channeling, coning or cresting. But, as the SAGD process matures,
after a
few years, the bottom bitumen will be heated by conduction (Figure 15) and in
situ viscosity will be similar to heavy oil, with increased chances of
channeling,
coning and cresting.
Once the production well has coned/crested, the SACT process can be applied.
Unlike heavy oil,
the SAGD production well has been thermally completed and it can be used as a
SACT steam
injector.
Again, the SACT process is cyclic with the following steps:
(1) Shut-in the SAGD producer and convert it to a steam injector.
(2) Maintain target pressures in the SAGD steam chamber closer to but
slightly above
in situ pressures by using the steam injector well.
(3) Inject a slug of steam into the SAGD production well.
(4) Shut in both SAGD wells for a soak period (weeks-months) to allow
bitumen to
be heated and to re saturate the cone/crest area.
(5) The process can be repeated.
Example
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Nexen conducted a simulation study of SACT using the Exothenn model. Exotherm
is a three-
dimensional, three-phase, fully implicit, multi-component computer model
designed to
numerically simulate the recovery of hydrocarbons using thermal methods such
as steam
injection or combustion.
The model has been successfully applied to individual well cyclic thermal
stimulation
operations, hot water floods, steam floods, SAGD and combustion in heavy
hydrocarbon
reservoirs (T.B. Tan et at., Application of a thermal simulator with fully
coupled discretized
wellbore simulation to SAGD, JCPT, Jan. 2002).
We simulated the following reservoir:
Pressure ¨ 6200 kPa
Temperature ¨28 degrees Celsius
Porosity ¨ 33%
Initial water Sat. ¨ 30%
1n-situ viscosity ¨ 2000 cp
Oil pay¨ 16m
Bottom water ¨ 10 m
HZ well spacing ¨75 m
HZ well length ¨ 1000 m
We simulated SACT after primary production coned/crested wells. For a vertical
well we used
steam slug sizes from 50-200 m3. For horizontal wells we used slug sizes an
order-of-magnitude
larger.
Figure 16 shows simulation results for SACT and a comparison of horizontal and
vertical well
behavior. Based on the simulation results, the following is observed:
(1) The primary production period for vertical wells is much shorter than
for
horizontal wells ¨ about a quarter of the time ¨ until the wells are watered
off.
(2) The primary productivity of vertical wells is about a factor of 10 less
than for
horizontal wells. SACT productivities maintained this ratio.
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(3) The SACT cycle times are larger for horizontal wells. In the period
shown in
Figure 16 ¨ about 3 yrs. ¨ we have 11 SACT cycles for vertical wells compared
to
only 3 cycles for horizontal wells.
Figure 17 shows a comparison of SACT for horizontal wells, where the steam
injection was
applied at the heel and at the mid-point of the wells.
Based on the results shown in Figure 17, the following is observed:
(1) Primary recovery factor for a horizontal well is about 9% 00IP.
(2) The SACT process, over a period of 2 years after primary production,
recovered
an extra 5% 00IP for SACT applied at the heel of the horizontal well and an
extra 12% 00IP for SACT applied at the mid-point of the horizontal well. This
incremental RF is significant when compared to primary production.
(3) The first cycle of SACT applied to the mid-point of the horizontal well
produced
a production profile better than the primary producer.
In 1995-96 Nexen contracted SRC to conduct a scaled-physical model test of the
SACT process
based on the following:
14m oil pay column
16m active bottom water column
32% porosity
4D permeability
3600 cp in-situ viscosity
980 kg/m3 oil density (API=12.9)
28 C, 5Mpa reservoir T,P
150m well spacing, 1200m horizontal well length
Tables 2, 3, 4 and Figures 18, 19, 20, 21 present the results of the studies.
Based on the results of
these studies, the following was observed:
(1) For horizontal wells, steam slug sizes varied from about 36,000 to
54,000 cubic
meters (225 K bbl to 340 K bbl) (Table 2). For vertical wells, steam slug size
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varied from about 500 to 1100 cubic meters (3100 to 7000 bbls. At least within
the range studied, steam slug size is not very sensitive (Figure 19)). The
slug size
ratio horizontal/vertical is about 50-70. (Table 3).
(2) Steam injected rate varied from about 300 to 400 m3/d (1900 to 2500
bbl/d) for
horizontal wells (Table 2) and at about 9.3m3/d (60 bbl/d) for vertical wells
(Table 3). The horizontal/vertical ratio, defined as the ratio of length of
contact
with oil portion of reservoir, is from about 30 to 43. Steam injection rate is
not a
sensitive variable (Figure 18).
(3) The SACT process was tested for 4 to 7 cycles for horizontal wells and
3 cycles
for vertical wells.
(4) Recovery factors varied from 25 to 36% for horizontal wells and 36 to
43% for
vertical wells (00IP is much higher for horizontal well patterns).
(5) OSR is the key economic indicator. Horizontal wells SACT OSR varied
from
0.73 to 0.95 (SOR for 1.4 to 1.1). Vertical well OSR varied from 0.47 to 0.56.
In
comparison, a good SAGD process has an OSR =.33
(6) Figure 20 shows water cut offs (when production is stopped) are best at
higher
levels (90% vs. 50%).
(7) Figure 21 shows better performance for longer horizontal wells (300m
vs. 150m)
but it is not necessarily at optimum lengths.
Based on the studies and simulations discussed herein, it appears that the
SACT process of the
present invention works best for heavy oil cone/crests, since heating the zone
and the oil can
improve oil mobility dramatically compared to light oils.
If the heavy oil is produced using horizontal production wells and crests have
formed from an
active bottom water, a preferred way to link the well crests is a
substantially perpendicular
horizontal well about mid-way along the crest. (Figure 13) The well is
thermally completed for
steam injection.
The steam slug should be preferably 0.5 to 5.0 times the cumulative primary
oil production, on a
water equivalent basis (ie. steam measured as water volumes). The steam
injection rate is
determined by injection pressures ¨ preferably no more than 10% above native
reservoir
pressures at the sand face.
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Enough time is needed for the steam to heat surrounding oil and the oil to re
saturate the cone
(crest zone) ¨ based on the above, it is preferably between 1 to 10 weeks
after the end of the
steam cycle.
The process may be repeated when the water cut in produced fluids exceeds
about 95% (v/v).
Some of the preferred embodiments of the present invention are provided below.
(1) Heavy oil (>1000 cp in-situ viscosity)
(2) Well geometry to connect/link to parallel primary horizontal producers in
cresting
zone.
(3) Preferred linkage near mid-point of horizontal producers.
(4) Steam slug size limits
(5) Soak period limits
(6) Application to SAGD bitumen producer with bottom water
(7) Cyclic remediation process (not continuous)
(8) Applies to both horizontal and vertical wells
(9) Steam injection rate limits
(10) Steam quality limits
Other embodiments of the invention will be apparent to a person of ordinary
skill in the art and
may be employed by a person of ordinary skill in the art without departing
from the spirit of the
invention.
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Table 2:
Scaled Physical Model Test Results Horizontal Wells
Reservoias.;
Porosity (%) 35.8 - 35.0 34,8 35.7 35.2
001P (m1) 816100 819300 817500 - 798700 785000
Oil Sat. (%1 93.3 94.0 94.1 91.1 91.1
Prim Prod. 2.8 1.7 5. 3.7 2.7
__ %( 00IP)
____ Tests.
No. of Cycles 7 6 4 6 7
Run length_(yr) 21.9 20.9 16.0 21.0 24.3
_Stm. inj. rateleid) 301.4 401.6 299.1 300 300
Stm. slug size (in3) 36120 48200 - 53840 36000 54000
Cum. stm. inj. (m3) 260187 291663 219269 217751 384664
Steam Q (%) 70 70 70 70 70
Cycle shut off (%w) 90 90 90 50 50
_Recovery (%001P) -29.0 26.1 25.0 26.2 36.4
Cum. OSR .91 .73 __ .93 __ .95 .73
Oil Rate (m /cd) 29.6 28.0 34.9 27.3 322
Wat. Rate (rn3/cd) 53.5_ 48.5 33.2 _ 3,4 6.4
(SRC (1997))
Where (1) primary production used in all cases to establish water crests.
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Table 3:
SA CT Scaled Physical Model Tests Vertical Wells
Res rvoir_Conditionc:
00IP _____________________ 4205 4205
Spacing (m2) 900 900
Oil Sat._(%) 94.0 31.2
Prim. Prod. (%00IP) 15.3 14.1
_______ Gas Cap yes" no
_____ Tests:
No. of Cycles 3 3
Run length (yrs) 5.8 6.5
Stm. inj. rate (m3/d) 93 9.3
Stm. slug size (tri3) 1116 558
Cum. stm. inj. (m3) 3348 1674
_____ Performance:
__ Recovery (%00IP) 43.4 35.9
Cum. OSR 0.47 0.56
Oil Rate (m3/cd) 0.86 0.63
Wat. Rate (m3/cd) 3.19 ______ 0.84
SRC(1997)
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Table 4:
SA CT Scaled Physical Model Tests Vertical vs. Horizontal Wells
iEnd of I End of End of End of End of
i ________________________ Primary cycle __ cycle cycle cycle
)--- _____________________ Production ___ 1
_ 2 3 4
i Vertical Well Tin 207L,,,,, ,,
= time: start oilprimary production 3.0
4.2 - 5.7-1- 6.5 -
: start of EORR1.2 , 2.7 3.5 -
, ..---
_______________________ .,... -
= OSR: in c . ycle 0.39 0.73 0.56
-
____ : cumulative ______________ 0.39 0.56 0.56 -
-
,
. ,
= Recovery: in cycle 14.1 5.3 9.8
6.3 -
- .
-(%oOlP) : cumulative 14.1 19.4 29.2 35.9 -
Horizontal Wells ...
. = time: start of primary production , 6.0 11.6 15.6 18.1
22.1
: start of EORR 5.6 9.6 12.1
. _
= OSR: in cycle - 1.17 1.06
0.70 0.77
: cumulative- 1.17 1.12 0.98 0.93
,
,
i = Recovery: in cycle , 5.9 7.8 13.1 4.7 5.3
L (%ow) : cumulative , 5.9 7.8 20.9 25,6 30.9
(SRC (1997))
