CA2026483C - Wellbore heating process for initiation of below fracture pressure steam stimulation from a horizontal well located in an initially immobile tar sand - Google Patents

Abstract

A steam stimulation process for removing viscous hydrocarbonaceous fluids from a reservoir penetrated by a horizontal wellbore. Steam is injected into the wellbore slightly above the reservoir pressure. Injection is continued so as to allow the steam to heat the reservoir by conductance. once thermal-stimulation is obtained to the extent desired, steam injection is stopped and hydrocarbonaceous fluids are produced to the surface. A void is created in the area adjacent the wellbore and hydrocarbonaceous fluids removed therefrom. Steam in an amount sufficient to fill the void is injected into the formation at pressures slightly above the reservoir pressure but below its fracture pressure. Afterwards, the steps are repeated.

Description

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A WELLBORE HEATING PROCESS FOR INITIATION OF
BEL~nT FRACTURE PRESSURE STEAM SI~IATION
FROM A HORI?pNTAL WELL LpCATED IN AN
TNITPTAT.T ~( ~$jj~, Field of the Invention This invention is directed to a method for the recovery of viscous hydrocarbonaceous fluids frarn a formation. More specifically, it is directed to the removal of said fluids from a formation containing heavy viscous hydrocarbons or tar sands by the application of steam heat.
BACKGROUND OF THE INVENTION
The use of horizontal wells in oil reservoirs is currently of high interest within the oil industry. Horizontal wells allow more reservoir surface area to be contacted and thereby reduce inflow pressure gradients for reasonable oil production rates.
Alternatively, for typical pressure gradients within the wellbore region, the productivity of a horizontal well is greater than that in a vertical well.
She possible benefits of horizontal wells are c~rently being exploited in the Canadian tar sands. Reservoirs in Canada that may be categorized as immobile under reservoir conditions include the Gold Lake and Athabasca deposits.
Current practices for producing the above immobile tar sands include mining and steam stimulation by formation fracturing.
However, minirig is not practical below very shallow depths.
Furthermore, steam stimulation by formation fracturing is not feasible in those reservoirs underlain by water aquifers. In general, fracturing in zones underlain by water aquifers results in large amounts of water production and nonuni.form development of the steam zone. tame water influx is due to penetration of the fracture into the water aquifer.
Steam stimulation belay fracture pressure in vertical wells is not practical due to the very low injectivity of the formation to steam and the very small area of reservoir contact. IrKxeased area of contact can be achieved by the use of long horizontal wells (1,000 to 3,000 ft as oarnpared to 30 to 100 ft for a vertical well). 'Ibis increased area of contact allcyws more of the reservoir's area to be heated by steam injection. This results in more oil production due to the increased volume of the heated zone. Unfortunately, for immobile tar sands, even when heated, injectivity may remain very law.
Injection of a large steam slug into a horizontal well underlain by a water aquifer may result in a fracture into the aquifer.
Therefore, what is needed is a method for removing hydrocarbonaceous fluids fraan immobile tar sands or viscous fluids via a horizontal wellbore which will allow steam injectivity therein before a substantially large steam slug is injected so as to avoid fracturing into an aquifer.
St~RY OF THE INVF3~1TION
Zhis invention is directed to a process for obtaining initial steam injectivity at below fracture pressure in initially immobile tar sands or other very viscous hydrocarbonaoeous fluid containing formation, where at least one horizontal wellbore is utilized. A
horizontal well is drilled into the formation or immobile tar sand reservoir. Steam is then injected into the formation at a previously determined rate and at a pressure slic~tly above the formation or reservoir pressure. The steam is continuously circulated for a pre-determined time which causes the horizontal well to act as a heat conducting rod in the formation. Steam, however, does not enter the formation. Upon reaching the pre-determined time, steam injection is discontinued and a hydirocarbonaoeot~.s fluid mixture is produced to the surface via said well.

.. 226483 Once the hydrocarbonaceous fluids have been removed from the portion of the formation or reservoir heated by the steam, a voided area is created. (hereafter, a substantially large steam slug is injected into the voided area of the formation or reservoir and a steam stimulation enhanced oil recovery (DAR) is ooamnenoed.
It is therefore an object of this invention to heat a portion of the formation penetrated by a horizontal well where initial steam injectivity is substantially small or none estistent.
It is another object of this invention to steam heat a desired portion of the formation so as to subsequently remove hydrocarbonaceous fluids while keeping the formation from being fractured.
It is yet another object of this invention to cause a radial space to be created longitudinally in a reservoir along a horizontal wellbore by steam heating through conduction in said ~llbore.
BRIEF DF~S~'ION OF T~ DRAWINGS
Fig. 1 is a schematic representation of a horizontal wellbore in a formation while steam is being injected therein.
Fig. 2 is a graphical illustration depicting heat front movement by conduction in a reservoir via a horizontal. wellbore.
Fig. 3 is a graphical illustration shaving various rates of heat transfer fr~an a horizontal w~ellbare into a reservoir.
Fig. 4 illustrates graphically optitrnun steam injection rates sufficient to satisfy conduction requirements during the initial stages of operation.
Fig. 5 depicts graphically oil viscosity distribution around a horizontal wellbore in space and time.

DESCRIPTION OF 'Iii PRg'E~Rm ~pp~VTS
In the practice of this invention as shown in Fig. 1, steam is circulated through a horizontal wellbore 10 through over~en 12 and into an oil rich zone 14. Oil rich zone 14 can ~ri.se immobile tar sands, asphalt, or asphaltic materials for example. The steam which is circulated into wellbore 10 has a pressure slightly higher than the reservoir pressure but at a pre lower than the reserve~ir~s fracture pressure. For this reason, a reservoir fracture 18 is not created so as to avid coa~u~amicating with water aquifer 16.
The steam is allowed to remain in wellbore 10 while avoiding the injection of steam into oil rich zone 14. It is necessary for the wellbore 10 pressure to be slightly higher than the reservoir pressure to obtain steam penetration into wellbore 10. Thus steam does not enter the reservoir as it passes wellbore 10.
Although not shown, wellbore 10 contains perforations at desired intervals along its length. Maintainir~ the steam injection rate as above causes wellbore 10 to act as a co~luctir~g rod within oil rich zone 14. Heat ~r~ductance away from wellbare 10 is used to preheat the area of the reservoir adjacent to wellbore 10. After the oil rich zone 14 has been heated for the amount of time desired, immobile viscous hydrocarbons in oil rich zone 14 are warmed sufficiently to beg mobile. Mrobile hydrocarbons flora into wellbore 10 where they are produced to the surface.
Once the warmed hydrocarbons have been rte, a void is created in oil rich zone 14 adjacent to wellbore 10. This wided area is then used as an area in which to initiate steam stimulation of oil rich zone 14. A steam stinailation method which can be used to fill the wid created by the removal. of warmed hydrocarbons is discussed in U.S. Patent No. 3,434,544 which issued to Craig et al.
on March 25, 1969.
Steam stimulation is continued for a time sufficient to remove desired hydrocarbons from oilrich zone 14.
Steam passing horizontal well 10 may be repented by the following partial differential equation:

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aT r t - ~ at(r.t2 + 1 ~T r.t ( ) at ar r ar with boundary conditions T(r,t) -~ finite as r -~ ~ (2) and T(r,t) = Ts at r = w (3) amd an initial condition T(r,t) = o at t = 0 (4) where vCis the thermal diffusivity of the formation, T(r,t) is the temperature at any time and radial distance from the wellbore, Ts is the steam temperature, T is the initial reservoir temp~xature, r is o.
the radial distance frown the wellbore, w is the radius of the wellbore, and t is the time.
The above set of equations have an analytical solution which has been presented by H. S. Carslaw and J. C. Jaeger in a publication entitled Conduction of Heat in Solids, Second Edition, Oxford Press, (1959) pp. 334-338. This resultant temperature profile, as a function of time, detxxmines how long the well must be operated in conduction mode.
Heat transfer rates away from the wellbore are given by R. B.
Eird, W. E. Stewart ~.ncl F. LT.. L;ic~tfrn~ ire a ra~h~ ~!~.ati~~ ~~~itl~
Transport Phenomena, published by John Wiley & Sons, New York, N. Y.
(1960) p. 319. These rates are presented by the following equation.
q = -k aT(r.t) (5) ar r~
w where q is the heat flux fr~n the wellbore and k is the thermal conductivity of the formation. This flux is the amount of heat input to the well, in terms of steam injection, required to exactly satisfy the heat conduction away from the well. Zhe integral has been presented graphically in Carslaw and Jaeger mentioned above.
An example of calculations for time and steam injection rates during the conduction heating phase follow. For these calculations, a reservoir pressure of 3,000 KPa has been ass~mved. A reasonable wellbore pressure to achieve heat conduction in the absence of either connective heat transfer away from the wellbore or a formation fracture is assumed to be 4,000 KPa.
Figure 2 depicts the thermal history of the well. The abscissa presents radial distances from the center of the wellbore. Table 1 lists all physical parameters used in the calculation.

Oil Density = 60 lxm/ft3 Water Density = 62.4 ll~n/ft3 Rock Density = 165 lxm/ft3 Formation Density = 133 ltxn/ft3 Oil Saturation = 0.77 Water Saturation = 0.23 Oil Heat Capacity = 0.5 Btu/lbin F
Water Heat Capacity = 1.0 Btu/ltm F
Rock Heat Capacity = 0.24 Btu/lbn F
Formation Heat Capacity = 0.352 Btu/lbtn F
Formation Thermal Conductivity = 38.2 Btu/ft day F
Formation Thermal Diffusivity = 0.81 ft2/day Representative Length of Well = 1,000 ft.

2o~e~s~

Oil Viscosity as Function of Temperature Temperature (F) Viscosity (cp) 50 26,725 100 1,508 350 6.3 400 4.0 450 2.8 500 2.0 550 1.5 The representative horizontal wellbore was taken as 9 inches and its length 1,000 feet (these are typical Values of horizontal wells).
Calculation of the heat capacity, thermal conductivity, and density of the overall formation proceeded as described by Pmts (1982).
Implicit in these results is the assumption that the wellbore is raised essentially instantaneously to steam temperature at time zero.
After 0.5 day a radial isotherm of 200°F exists to a radial distance of 1.0 ft frcen the well center. After 35 days, this isotherm has moved to slightly less than 3.5 ft.
Figure 3 presents calculated rates of heat transfer fr~n the wellbore. Clearly, the heat transfer rate has declined by a significant amount after 35 days. These heat transfer rates are converted to steam injection rates in Figure 4. These steam injection rates are the optimum rates necessary to operate the well in conduction mode. After 35 days the steam injection rates drop and plateau.

Frcfln these calculations, the optimum time to heat the horizontal well in conduction mode is 35 days. The optimum steam injection rates range frarn about 200 BBL/day to slightly less than 100 BBL/day, cold water equivalent (GWE).
The oil viscosity distribution, based on the oil viscosity data in Table 2, is shown in Figure 5. This distribution is a result of the heat conduction frown the wellbore. After 35 days, the oil viscosity is reduced to less than 100 cp for all distances less than 3.5 ft. Since the horizontal well is so long this represents a significant total heated volume of 38,000 ft3. Ass~ning that 30% of the heated fluid can be recovered upon well flawback then this heated zone can be drained of 3,420 ft3 of fluid.
Thus, a steam slug consisting of 3,420 ft3 of fluid can be injected into the zone that was initially immobile as a result of using the long horizontal well as a conductor.
Obviously, many other variations and modifications of this invention as previously set forth may be made without departing from the spirit and scope of this invention as those skilled in the art readily understand. Such variations and modifications are considered part of this invention and within the purview and scope of the apper~d claims.

Claims (13)

1. A method for pretreating a formation or reservoir, containing immobile viscous hydrocarbons, prior to initiation of a steam stimulation process comprising:
(a) injecting steam into a horizontal wellbore at a pressure higher than the reservoir pressure but below the reservoirs fracture pressure so as to substantially avoid injecting steam into the reservoir;
(b) allowing the steam to circulate in said wellbore for a time sufficient to preheat the reservoir by transient heat conduction to a desired temperature at a desired distance from the wellbore, whereby immobile viscous hydrocarbons in the area adjacent to said wellbore are warmed sufficiently to become mobile; and (c) ceasing circulation of steam in the wellbore and producing hydrocarbonaceous fluids to the surface thereby creating a void in an area adjacent to said wellbore.

2. The method as recited in claim 1 where after step (c) steam is injected into said wellbore as in step (a) in an amount sufficient to fill the void and initiate steam stimulation.

3. The method as recited in claim 1 where after step (c) steam is injected into said wellbore as in step (a) in an amount sufficient to fill the void, steam stimulation is initiated, and hydrocarbonaceous fluids are subsequently removed from said reservoir.

4. The method as recited in claim 1 where the immobile viscous hydrocarbons comprise tar sands or asphalt.

5. The method as recited in claim 1 where the horizontal well is up to about 3,000 feet in length.

6. A method for initiating steam stimulation in reservoir containing immobile viscous hydrocarbons comprising:
(a) injecting steam into a perforated horizontal wellbore at a pressure higher than the reservoir pressure but below the reservoir's fracture pressure so as to substantially avoid injecting steam into the reservoir;
(b) allowing the steam to circulate in said wellbore for a time sufficient to heat the reservoir by transient conduction to a desired temperature at a desired distance from the wellbore;
(c) ceasing circulation of steam in the wellbore and producing hydrocarbonaceous fluids to the surface thereby creating a radial void in an area adjacent to said wellbore; and (d) injecting thereafter steam via said wellbore as in step (a) in an amount sufficient to fill the void and initiate steam stimulation.

7. The method as recited in claim 8 where after step (d) steam injection is ceased, hydrocarbonaceous fluids are removed from the reservoir, and steps (a) through (d) are repeated.

8. The method as recited in claim 6 where the immobile viscous hydrocarbons comprise tar sands or asphalt.

9. The method as recited in claim 6 where the horizontal well is up to about 3,000 feet in length.

10. A method for removing immobile viscous hydrocarbons from a formation or reservoir penetrated by a horizontal wellbore comprising:
(a) injecting steam into a horizontal wellbore at a pressure higher than the reservoir pressure but below the reservoir's fracture pressure so as to substantially preclude steam entry into said reservoir;
(b) allowing the steam to circulate in said wellbore for a time sufficient to heat the reservoir by transient conduction to a desired temperature at a desired distance from the wellbore;
(c) ceasing circulation of steam in the wellbore and producing hydrocarbonaceous fluids to the surface thereby creating a void in an area adjacent to said wellbore;
(d) injecting thereafter steam via said wellbore as in step (a) in an amount suffcient to fill the void and initiate steam stimulation; and (e) terminating steam injection and removing hydrocarbonaceous fluids from the reservoir.

11. The method as recited in claim 10 where steps (a) through (e) are repeated until a desired amount of hydrocarbonaceous fluids have been removed from the wellbore.

12. The method as recited in claim 10 where the immobile viscous hydrocarbons comprise tar sands or asphalt.

13. The method as recited in claim 10 where the horizontal well is up to about 3,000 feet in length.