Mixed well steam drive drainage process

A thermal oil recovery process is disclosed for use in an oil reservoir containing a plurality of laterally separated generally vertical wells that have been used for cyclic steam stimulation and that have left in the reservoir at least one of a heated depletion zone and a channel. The process includes the steps of: drilling a well having a horizontal section and an opening therein that is located laterally between at least two of the vertical wells and at a depth within the lower part of the reservoir; injecting a heated fluid through the two vertical wells to establish thermal communication with said horizontal well; and using steam drive and gravity drainage to recover oil from the reservoir through the horizontal well.

TECHNICAL FIELD 
This invention relates to the general subject of production of oil and, in 
particular, to a process or method for enhanced recovery of oil in 
underground formations which have previously experienced cyclic steam 
stimulation. 
BACKGROUND OF THE INVENTION 
There exists throughout the world major deposits of heavy oils which, until 
recently, have been substantially ignored as sources of petroleum since 
the oils contained therein were not recoverable using ordinary production 
techniques. For example, it was not until the 1980's that much interest 
was shown in the heavy oil deposits of the Alberta province in Canada even 
though many deposits are close to the surface and represent an estimated 
petroleum resource upwares of many billion barrels. 
It is well known that heat can be employed to recover hydrocarbons from 
underground formations through wells, drilled in the underground petroleum 
deposits. Various methods have been developed over the years for primary 
and secondary recovery of oil from underground formations by thermal 
means. 
Moreover, it is well-recognized by persons skilled in the art of recovering 
oil or petroleum from subterranean deposits that only a small fraction of 
the viscous petroleum may be recovered from subterranean formations by 
conventional, primary and secondary means. Some method, such as a thermal 
recovery process or other treatment, must often be applied to the 
formation to reduce the viscosity of the petroleum to a level where it 
will readily flow to wells from which it can be recovered to the surface 
of the earth. Steam and/or hot water flooding are commonly used for this 
purpose and have been very successful in some formations for stimulating 
recovery of viscous petroleum which is otherwise essentially 
unrecoverable. Steam flooding is a thermal oil recovery method which has 
enjoyed increased popularity in recent years and is often the most 
commercially practical method or process. 
Steam flooding can be utilized in a single well by the so called 
"huff-and-puff" technique. That method involves first injecting steam into 
a vertical well, then shutting in the well for a "soak", wherein the heat 
contained in the steam raises the temperature and lowers the viscosity of 
the petroleum. Thereafter, a production period begins wherein mobilized 
petroleum is produced from the well, usually by pumping. This process can 
be repeated over and over again. 
Steam flooding may also be utilized as a stem or thermal drive means or a 
steam through-put process, wherein stem is injected into the reservoir 
through one or more vertical injection wells. This steam then moves 
through the subterranean reservoir mobilizing and volatilizing the 
petroleum it encounters. This steam-flood front moves through the 
reservoir towards a production well wherefrom the petroleum fluids are 
produced. This steam drive process is often more effective than the 
"huff-and-puff" method inasmuch as the potential volume of the reservoir 
which can be swept by the process is greater. 
Although the steam drive process is very effective in recovering petroleum 
from the portions of the reservoir through which the steam sweeps, in 
practice, the success of the stem drive method is often poorer because the 
processes inability to develop liquid communication and because of low 
vertical conformance efficiency. It is typical that less than 50% of a 
petroleum contained within a formation can be recovered by the steam drive 
process thereby leaving large amounts of petroleum within the reservoir 
after the completion of the process. 
Another common thermal recovery technique is the "cyclic steam stimulation" 
method, wherein production of oil from a well is periodically interrupted 
and steam is injected into the well. The steam supplies heat to reduce the 
viscosity of the oil remaining in the oil-bearing strata surrounding the 
well so that it will flow more readily to the well for production 
therefrom. The cycle is repeated until the production index becomes 
smaller than a minimum profitable level. Sometimes the term cyclic steam 
stimulation and huff-and-puff are used interchangeably. 
One of the problems faced with a thermal oil recovery method arises from 
the varying permeabilities of the reservoir. Where there is a permeable 
zone with a considerable increase in permeability when compared to the 
oil-bearing strata, the injected steam will flow into the permeable zone 
preferentially, or, on occasion, almost exclusively. Another problem 
encountered is the loss of a portion of the heat already transferred to 
the oil-bearing strata by the stem as a result of conduction way into the 
permeable zone. Clearly improvements are needed. 
SUMMARY OF THE INVENTION 
A general object of the invention is to improve the low ultimate recovery 
experienced with cyclic stem stimulation. 
Yet another objective of the invention is to provide an improved means for 
recovery of oil that utilizes existing cyclic steam stimulation 
infra-structure. 
Still another object of the invention is to provide a new process for the 
recovery of oil from undeveloped oil sands. 
In accordance with the present invention a thermal recovery process is 
disclosed for use in a oil reservoir containing a plurality of laterally 
separated generally vertical wells that have been used for cyclic steam 
stimulation and that have left in the reservoir at least one of a heated 
depletion zone and a channel, the reservoir having a top and a bottom and 
each vertical well having a lower end located within at least part of the 
reservoir. In one embodiment the process comprises the steps of: drilling 
a well having a horizontal section and an opening therein that is located 
laterally between at least two of the vertical wells and at a depth within 
the lower part of the reservoir; injecting a heated fluid through the two 
vertical wells to establish thermal communication with the horizontal 
well, the location where the heated fluid leaves the vertical wells being 
relatively close to the opening in the horizontal section; and using steam 
drive and gravity drainage to recover oil from the reservoir through the 
horizontal well. 
The invention is a follow-up process to cyclic stem stimulation and 
utilizes existing pre-heated channels for accelerated recovery, resulting 
in higher productivity and more economical recovery. This improvement is 
due, in part, to the utilization of a new horizontal well, the use of 
existing vertical or deviated wells and pad facilities, and the use of a 
combination of steam drive and gravity drainage process. A horizontal well 
has a greater effect that drilling more vertical wells. In other words, a 
properly positioned horizontal well should produce the same effect as 
multiple new vertical wells and at a lower cost. Moreover, the combination 
of steam drive and gravity damage provides high oil rates, low 
steam-to-oil ratios and the formation of a steam chamber which results in 
relatively higher water-to-oil ratios, thereby improving water resuse 
potential. The result is an improved oil recovery of at least 50%. 
Numerous other advantages and features of the present invention will become 
readily apparent from the following detailed description of the invention, 
the embodiments described therein, from the claims, and from the 
accompanying drawings.

DETAILED DESCRIPTION 
While this invention is susceptible of embodiment in many different forms, 
there is shown in the drawings, and will herein be described in detail, 
one specific embodiment of the invention. It should be understood, 
however, that the present disclosure is to be considered an 
exemplification of the principles of the invention and is not intended to 
limit the invention to the specific embodiment illustrated. 
This invention is a follow-up process to cyclic stem stimulation (CSS). 
Referring to FIG. 3, the recovery scheme or process involves drilling one 
or more horizontal wells between rows of existing vertical wells at the 
base of a reservoir. The horizontal well is used as a production well 
while the existing vertical wells are used as continuous injection wells. 
No vertical well recompletions should be needed. The horizontal wells may 
undergo some cyclic steaming in order to establish inter-well 
communication. The scheme is dominated initially by steam drive. However, 
after thermal communication is established between the vertical injectors 
and the horizontal producer, gravity drainage dominates the recovery 
process. The process is enhanced by the heat left in the reservoir under 
cyclic steam stimulation. Reservoir fluid mobility is higher than at the 
virgin reservoir conditions so inter-well communication and production are 
accelerated. Further, the process steam requirements are lessened because 
of the heat left behind. Reservoir simulation indicates that this 
follow-up process could improve ultimate recovery to as high as 50% of the 
original oil in place. 
Referring to the drawings, in one embodiment of the invention, horizontal 
wells 10 were drilled from a new pad located roughly 600 meters south east 
of an existing pad 12, into the reservoir for a length of approximately 
1280 meters. As shown in FIG. 2 the horizontal wells extend beneath pads 
E, L and M. Pads E, L and M are mature pads that can no longer by 
cyclically steamed economically. Their production histories are summarized 
in Table 1. 
TABLE 1 
______________________________________ 
Cumulative Recovery through April 1, 1993 
PAD Total/Average Fraction 
(cycles) 
Cubic Meters CSOR CWOR Total C 
______________________________________ 
E(6) 121304/6065 6.513 5.382 0.126 
L(7) 124592/6922 6.857 5.008 0.119 
M(5) 123212/7701 6.364 4.535 0.096 
______________________________________ 
CSOR = Cumulative Steam Oil Ratio 
CWOR = Cumulative Water Oil Ratio 
Two pattern areas and configurations were tested. In FIG. 2, the two 
horizontal wells 10 and 11 am approximately 165 meters apart. One 
horizontal web 10 was drilled between two rows of existing vertical webs 
15 having an effective pattern area of approximately 38 acres. The second 
well 11 was drilled immediately adjacent to a row of vertical wells 19 and 
have rows 15 and 17 on either side supporting production. Its effective 
pattern area is estimated to be 60 acres. The vertical webs 19 adjacent to 
the horizontal well 11 on the 60 acre spacing are not part of the method. 
Future horizontal well spacing may depend on production results of and on 
the spacing of existing vertical wells. 
The orientation of the horizontal wells can be either parallel (FIG. 1) or 
perpendicular (FIG. 2) to the fracture trend found in the reservoir. 
Reservoir simulation has shown that performance can be superior for 
horizontal wells oriented perpendicular to the fracture trend. 
Pressures are maintained below parting pressure (8500 kPa). Under normal 
operations steam injection will occur at 4500 kPa. 
Bitumen saturated unconsolidated sands form the reservoir unit in one test 
of the invention. Examination of drill cores cut through reservoir areas 
shows that the reservoir is divided in descending order, into C1, C2 and 
C3 sands. The C1 and C2 sands are separated by about 4 meters of sandy 
mud. The C2 and C3 sands are separated by 45 cm of interbedded sand and 
mud. Tight to low permeability calcite cemented sands are abundant. A 
stratigraphic correlation of closely spaced wells in E, L and M pads 
reveals that these calcite cemented sands are laterally discontinuous. 
Oil sand pay in the project area was estimated to be 15 m. No gas or water 
legs were evident in the area. The reservoir properties are summarized as 
follows: 
______________________________________ 
Reservoir unit C3 C2 
______________________________________ 
Depth of pay (meters) 
448 445 
Net oil sand pay (meters) 
15.1 1.8 
Average porosity 32% 28% 
Initial water saturation 
36% 34% 
______________________________________ 
"Net pay" is defined as sand with porosity greater than or equal to 25%, 
V.sub.sh less than or equal to 25% and GWO greater than 8%. GWO or grain 
weight oil is the weight percent bitumen of a dry bulk sample (water 
removed). 
The horizontal well 10 has three main parts: a surface casing, an 
intermediate casing, and a horizontal slotted liner section. 
The surface casing was cemented to a depth of approximately 150 meters. An 
intermediate hole was drilled utilizing a stabilized mud motor assembly 
and a MWD (measurement while drilling) system. The well was kicked off at 
a depth between 50 mKB and 150 mKB, with a 6.degree./30 meter build rate 
utilized to intersect the pay zone at 90.degree. at an approximate depth 
of 465 meters true vertical depth (800 meters measured depth). A 298.5 mm 
intermediate casing (L-80 SL, 59.52 kg/m) was run to this depth and 
cemented to surface with a thermal cement (Class C+40% silica flour). An 
MWD dual induction or gamma-ray log was run on the intermediate hole. A 
222 mm horizontal hole was drilled using a slick mud motor assembly and a 
MWD system for a total 1280 meter horizontal displacement within a 2 meter 
vertical target. The conductor pipe (339.7 mm, K-55 MFW, 81.1 kg/m) was 
set at 20 meters TVD and cemented (3/4" Construction Cement, 3000 psi) to 
the surface. Finally, a 177.8 mm slotted liner (K-55, LT&C, 34.22 kg/m) 
was rim, which was not cemented. 
The horizontal sections of the wells are drilled through depleted cyclic 
steam pads so there is some potential for drilling difficulties. Several 
precautions can be taken to minimize these difficulties. Temperature and 
fluid level surveys conducted on the existing E and L pad wells were used 
to determine the reservoir temperatures and pressures prior to drilling. 
Moreover, 2 D seismic can be used to indicate temperature changes across 
the pattern area, which may be related to depleted areas. 
There is little potential for encountering pressurized zones near surface. 
Potential drilling difficulties are most likely to be either lost 
circulation or borehole sloughing. Lost circulation may be rectified with 
lost circulation materials. Observation webs may be drilled through a 
depleted zone to gauge the potential for sloughing, and to determine what 
action can be taken to remedy the problem. Finally, a directional drilling 
and survey program may be used to minimize interference with any existing 
deviated wells. 
The horizontal webs can be produced using either conventional rod pumping 
or gas-lift systems. The wellheads were designed to handle the maximum 
stem injection pressure of 9,000 kPa (formation fracture pressure is 
approximately 8,500 kPa). 
Vertical observation wells may be drilled over the project area to monitor 
pressure and temperature of the producing formation during steam injection 
operations. Observation well information may be collected using a 
datalogger located at each site. On a regular basis, the dataloggers 
transmit data back to a central computer, located at the main plant site, 
for further processing and reporting. 
The first three years of operation are expected to produce 377,400 m.sup.3 
of oil, 2,409,000 m.sup.3 of water and 3.8 MM m.sup.3 of gas (average GOR 
of 10). The cumulative steam-oil ratio as expected to be 6.4. The 
cumulative water-oil ratio is expected to be 6.8. Table 2 outlines the 
projected performance of the two combined wells. 
TABLE 2 
______________________________________ 
Bitumen 
Production SOR WOR 
Year m.sup.3 /d Instantaneous 
Instantaneous 
______________________________________ 
1 209 8.2 11.2 
2 414 5.0 5.2 
3 411 4.9 5.1 
4 308 6.0 6.3 
5 189 5.5 5.8 
6 168 6.3 6.6 
7 148 7.3 7.7 
8 141 7.6 8.0 
9 125 7.2 8.3 
10 109 9.3 8.9 
11 88 9.6 10.1 
Average 210 6.3 6.9 
______________________________________ 
No modifications should be needed for the CSS control facilities which 
consist of equipment necessary for bitumen treatment, water disposal, stem 
generation, and fuel gas processing. 
This process should not necessitate immediate or long term increase in the 
consumption of fresh water for steam generation. Table 3 illustrates the 
projected steam and water requirements. 
TABLE 3 
______________________________________ 
Steam Produced Make-Up 
Excess/Disposed 
CWE Water Water Water 
Year (1000 m.sup.3) 
(1000 m.sup.3) 
(1000 m.sup.3) 
(1000 m.sup.3) 
______________________________________ 
1 631 858 0 227 
2 754 782 0 29 
3 742 769 0 27 
4 678 709 0 30 
5 379 398 0 20 
6 384 406 0 22 
7 392 413 0 21 
8 391 410 0 20 
9 362 379 0 17 
10 336 354 0 17 
11 308 323 0 14 
Cumulative 
5355 5802 0 475 
______________________________________ 
This information is based on numerical simulation, wherein it was assumed 
that the process of the invention is independent of other operations in 
the area. In practice, any excess water produced would be recycled to mak 
up for shortfalls elsewhere, rather than disposed. 
The simulation predicted greater water production than steam injection. 
This imbalance results because the produced fluids that are drained from 
the steam chamber have a greater volume than the condensed equivalent 
volume of stem. Moreover, the reservoir has higher than virgin water 
saturation due to prior cyclic steam operations, so this also contributes 
to the imbalance. 
High resolution, high frequency 3 D reflection seismic data may be used to 
remotely monitor steam progression. A Surface Displacement Monitoring 
Technology (SDMT) program may be used to determine the distribution of 
steam during the project along with a 3 D seismic. This program may 
require cut lines across the entire site so that surface heave monuments 
can be installed. 
From the foregoing description, it will be observed that numerous 
variations, alternatives and modifications will be apparent to those 
skilled in the art. Accordingly, this description is to be construed as 
illustrative only and is for the purpose of teaching those skilled in the 
an the manner of carrying out the invention. Various changes may be made, 
materials substituted and features of the invention may be utilized. For 
example, the invention is applicable to reservoirs that have been depleted 
through water-flooding as well as to fractured and non-fractured 
reservoirs. Moreover, while steam is the preferred fluid, other fluids, 
such as hot water, having a temperature greater than that of the 
underground formation, should be considered. Thus, it will be appreciated 
that various modifications, alternatives, variations, etc., may be made 
without departing from the spirit and scope of the invention as defined in 
the appended claims. It is, of course, intended to cover by the appended 
claims all such modifications involved within the scope of the claims.