CA2567399C - Method and apparatus for stimulating heavy oil production - Google Patents
Method and apparatus for stimulating heavy oil production Download PDFInfo
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- CA2567399C CA2567399C CA002567399A CA2567399A CA2567399C CA 2567399 C CA2567399 C CA 2567399C CA 002567399 A CA002567399 A CA 002567399A CA 2567399 A CA2567399 A CA 2567399A CA 2567399 C CA2567399 C CA 2567399C
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- solvent
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
- E21B43/2405—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection in association with fracturing or crevice forming processes
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
Abstract
A method and apparatus for stimulating heavy oil production from an oil bearing formation. The method includes the steps of placing a downhole heater in the formation adjacent to the oil producing zone to heat heat transfer fluid and then energizing the downhole heater. The method further includes the step of passing the heat transfer fluid through the heater to heat the heat transfer fluid and then injecting the heat transfer fluid into the oil bearing formation. This brings the heated fluid into contact with the oil to increase the flowability by decreasing the effective viscosity of the oil. In this manner, an oil extraction chamber can be quickly formed in the oil bearing formation. In another aspect of the invention, the apparatus, includes a source of energy and flow through heater connected to the source of energy. The flow through heater is attached to the end of coil tubing, and placed downhole. The apparatus further includes a control system for monitoring the heater, a source of injection fluid, a pump to inject the injection fluid and a pressure reducer on the exit of the heater, to maintain fluid pressure in the heater for efficient heat transfer.
Description
_2_ TIT : METHOD AND APPARATUS FOR STIMULATING HEAVY
OIL PRODUCTION
FIELD OF THE INVENTION
This invention relates generally to the extraction of hydrocarbons s such as heavy oil and bitumen from naturally occurring formations such as tar sands or the like. Most particularly this invention relates to a means to accelerate the recovery process thereby increasing the rate of return on capital and decreasing the financial risk of such heavy oil production projects.
io BACKGROUND OF THE INVENTION
Heavy oil and bitumens, such as may be found in deposits known as tar sands, may have viscosities greater than 1000 centipoise or specific gravities greater than .934 at 60°F (i.e. less than 20° API).
Hydrocarbons with such a high specific gravity and viscosity are difficult to efficiently is recover because they do not readily flow.
It has been long known that heat can be used to decrease the viscosity of heavy oils and hence improve the flow . Currently steam is the most common thermal stimulation used for heavy oil extraction. However, steam stimulation is subject to a number of problems, including heat losses 2o during injection, clay swelling problems, thief zones, emulsions, capillary surface tension effects and lack of confinement for shallower zones. In addition to these problems, the heating equipment is expensive to purchase and install and even more expensive to run, because of the large energy consumption required. For these reasons alternate techniques are being 2s sought.
Another thermal extraction technique, known as fireflood, is generally uneconomic due to very severe operating problems including corrosion, scale precipitation and explosion hazards after breakthrough.
One of the factors affecting the recovery of in situ oil, is the well 3o configuration. There are many different well configurations used. Different well configurations are used in different recovery techniques. The two main approaches in the past have been "huff and puff' (i.e., cyclic steaming) and steam floods. Recently, steam assisted gravity drainage (SAGD) has also been proposed and used.
SAGD requires the formation of a steam chamber. The steam chamber is essentially what is left behind in the oil bearing formation after the oil has been recovered from the chamber; as more oil is recovered, the chamber grows. Essentially in SAGD, water is heated above grade to form s steam, and then the steam is injected into the formation into the chamber.
The heated oil flows down the walls of the chamber and drains into the producing well. The advantage of SAGD that the countercurrent flow of steam upwards into the chamber in the reservoir and oil down and out of the reservoir is relatively efficient, thus the fluid flow rates may be high enough io to provide favorable economics.
There are many possible SAGD geometries including single well (injection and production from the same well) and dual or mu~iple well. The wells may be either horizontal or vertical. Generally horizontal wells are favored because they offer a longer exposure to the oil rich pay zone and is thereby facilitate economic production rates for highly viscous oils.
Single well SAGD requires the least capital cost, but heat losses due to countercurrent flow of steam into the well and oil out of the well having passing contact in the wellbore can be quite severe. For example, at an injection pressure of 1000 psig and 285°C, the enthalpy of the steam is 2o btu/lb and the enthalpy of the water is 542 btu/lb. Due to countercurrent heat exchange the temperature of the produced fluids (water and oil) will lower the temperature of the injected steam to some low temperature equilibrium point. Usually, the steam quality is 80% (i.e., 80% vapour and 20% liquid). Thus, the maximum heat delivered to the formation is only the 2s latent heat of vaporization (i.e. about 50% of the total heat input). With additional heat losses through the well casing during injection, the net heat delivery to the formation is quite low and therefore this technique inefficient.
The idea of replacing steam with cold solvent was first proposed by Nenniger' (1979). This technique has shown much promise for production 30 of heavy oil with minimal environmental impact, primarily because oil production would not require the use of significant amounts of water and energy to form the needed steam. Energy requirements for cold solvent extraction are expected to be less than 4% of those required for steam extraction. Insitu recovery with cold solvent has minimal environmental ' Nenniger, E.H., Hydrocarbon Recovery, Canadian Patent 1,059,432 impact compared to surface mining techniques.
The physics of cold solvent stimulation are not fully understood. The measured solvent diffusion rates are typically 100-1000 times higher than predicted by theory~3. A key economic requirement is efficient recovery of s : the solvent, so light gases such as ethane and propane which can be recovered by pressure blowdown are generally preferred. A recent study has reported the ratio of ethane solvent loss to bitumen produced, was low as seven percent (wtlwt).
However, the calculated production rates for solvent extraction are to believed to be too low to justify commercial application and a field test of cold solvent extraction has never been performed. Bench tests4 with warm solvent (propane) have shown that production rates can be increased about 20 fold simply by increasing the temperature from 20°C to 90°C.
However, the heat capacity of heated solvents (i.e. vaporized propane and ethane) is is very low, so it is impractical to heat hydrocarbon gas above grade and pump the same downhoie and achieve any heat delivery at the reservoir.
The Vapex process4 proposes to combine heat with solvent to benefit from possible synergies. However, the heat is provided by steam or hot water which is heated above grade and consequently suffers from the ail 2o problems mentioned above (countercurrent heat exchange, formation damage problems with clays, emulsions; capillary pressure, water treatment, water supply, etc).
Lab tests and modeling have shown that the viscosity reduction of the oil occurs due to dissolution of the solvent into the oil and the upgrading of 2s the oil by de-asphaiting. The de-asphalting appears to occur locally when the oil is initially mobilized by dilution with solvent. Thus, in lab scale tests there has not been evidence of formation damage due to asphaitene accumulation in the near wellbore area.
A key requirement for both steam assisted gravity drainage and Z Dune, S.G.; E.H. Nenniger, V.S.V. Rajah, A Study ofBitumen Recovery by Gravity Drainage Using Low Temperature Soluble Gas In-jectiQn, The Canadian Journal of Chemical Engineering, Vol 67, December 1989.
3 Lim, et al, Three dimensional Scaled Physical Modelling of Solvent Vapour Extraction of Cold Lake Bitumen, JCPT, April 1996, Page 37 4 See Table 1 and Figure 7 of Butler et al, A New Process for Recovering Heavy Oils using Hot Water and Hydrocarbon Vapours, JCPT Jan 1991, pg 100 solvent assisted gravity drainage is the formation of a steam or solvent chamber in the reservoir. The chamber allows efficient countercurrent flow of solvent (or steam) upwards and flow of the heavy crude downwarcls along the walls of the chamber. The predicted oil drainage rate is proportional to s the square root of the height of the chamber (reference 4). Thus the oil production rates are predicted to be small initially and then grow with time until the roof of the chamber encounters a boundary such as an impermeable shale. Lab tests have confirmed the beneficial effect of the formation of the solvent chamber. Lab tests have also shown that the io maximum oil production rates will not occur until a large solvent chamber is formed. Unfortunately, this means that peak oil production rates do not occur until 3-4 years after the well is placed on production.
Thus, for cold solvent extraction the peak oil production rates are not expected to be achieved until perhaps three years after the capital costs of is the well and the production facilities are incurred. The delayed production response decreases the rate of return and increases the risk to the operator.
For example thief zones, etc, may not be identified until substantial costs have been incurred and yet before the recovery has become economic.
Thus, there is potential for a significant economic benefit, if the 2o solvent chamber could be quickly established. For example, the capital cost of drilling and completing a horizontal well might be typically 500,000 dollars.
The minimum internal rate of return for a oil project is typically about 15%.
Thus, the opportunity cost of a one year delay in the peak production rate is 75K$. If peak production is accelerated, so it occurs in the first year rather 2s than the third, then the value added by early development of the solvent chamber would be 150K$ to 250K$ per well.
Thus, while the cold solvent extraction process has great advantages due to energy effrciency and minimal environmental damage, it has never actually been field tested. The primary reason for this is the belief that the 3o cold solvent production rates will be too low to be economic, particularly with the expected 3-4. year delay in achieving peak production rates.
BRIEF SUMMARY OF THE INVENTION
What is desired therefore, is a means to accelerate the initial oil production rate by encouraging the rapid formation of a solvent gravity 3s drainage. According to one aspect of the present invention there is provided a method to accelerate the process of forming a gravity assist drainage chamber by effectively and rapidly injecting significant volumes of sufficiently heated gaseous and liquid solvents into the reservoir using downhole heater technology.
s The preferred apparatus to perform the method of the present invention is a coiled tubing conveyed downhole heater. This heater can be used to place the desired heat without the usual wellbore heat losses associated with surface injection of hot fluids. In the preferred method the heater is lowered into the well, placed on a pump seating nipple or packer io and the cold fluid is pumped into tubing-coiled tubing annulus. The cold fluid is heated as it passes through the heater and then the hot fluid is squeezed into the formation. Because the heater is deployed on coiled tubing, it can also be displaced to the end of a horizontal well. The most preferred heater has an extremely high output (for example more than about 100 kW), yet it is fits inside 2 718" production tubing. Because the heat is added downhole close to the target formation, it is feasible to heat fluids with relatively low heat capacities (i.e. hydrocarbon gases and liquids) and provide efficient delivery of heat into the formation with minimal heat losses.
Thus according to an aspect of the present invention a heated solvent 2o stimulation is performed to initiate formation of a gravity drainage chamber.
Once the chamber has been established,. there would be a large interfacial area for efficient mixing of the solvent into the oil. Subsequent cold solvent injection would achieve commercial production rates without requiring additional heat. Therefore according to the present invention there is 2s provided: A method for stimulating heavy oil production from an oil bearing formation comprising:
a) placing a downhole heater in the formation adjacent to the oil producing zone, to heat a heat transfer fluid;
b) energizing said downhole heater and passing said heat 3o transfer fluid past said heater to thereby heat said heat transfer fluid;
c) injecting said heated heat transfer fluid into the oil bearing formation to bring said heated fluid into contact with said oil to thereby decrease the effective viscosity of said oil; and d) recovering said reduced viscosity oil to form an oil extraction ss chamber in said oil bearing formation.
According to another aspect of the invention there is provided a method according to the foregoing further including the step of regulating the pressure in said heater to permit tow heat capacity solvents to be heated.
According to a further aspect of the invention there is provided a downhole heater having a pressure regulator at an exit end of said heater s for maintaining pressure in said ;heater sufficiently high to permit efficient heating of low heat capacity fluids.
BRIEF DESCRIPTION~F THE DRAWINGS
Reference will now be made, by way of example only, to preferred embodiments of the invention as illustrated in the accompanying drawings io and in which:
Figure 1 illustrates a schematic of the invention, the. injection of hot fluid into the heavy oi! reservoir to accelerate the creation of a solvent chamber.
Figure 2 illustrates a typical well site deployment for the hot solvent is stimulation Figure 3 illustrates a typical solvent chamber created as a consequence of the injection of hot solvent. ' DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Figure 1 shows a schematic of the apparatus used in the method 2o according to the present invention. A heater 2 is mounted on the end of a length of coiled tubing 4. The heater 2 ~ is deployed from a coiled tubing truck 6 to a target zone 8 by an injector 10. During deployment a pressure seal 12 is formed between a wellhead assembly 14 and the coiled tubing 4 by a stripper 16. Once the heater 2 has reached the target zone 8, a BOP
2s (Blow Out Preventer) 18 is energized and an additional pressure seal around the coiled tubing is formed with the BOP tubing rams in a conventional manner. A power cable 5, carried within the coiled tubing 4 is used to energize the heater 2. As the power cable 5 is contained within the coiled tubing it is protected from damage due to abrasion and pressure 3o cycles.
The heater 2 may be in the form of an electrically powered resistance heater of the flow through type. While other heater designs would also work, the electrical resistance heater provides adequate results. To provide best results it is preferable to have a power output of more than 100 kw .
The heater is most preferably compact i.e. small diameter and of a short length (preferably less than 2 metres) to be easily positioned in the well near the formation to be treated. A packed bed resistance element as disclosed in my prior patent 2,052,202 will provide adequate results.
s A heat transfer fluid 20 is pumped through a valve 22 and into a flow "T" fitting 24. The fluid 20, which is described in more detail below, then travels downhole in the annulus between well tubing 26 and the coiled tubing 4. A seal 27 between the heater 2 and the well tubing 26 forces the fluid 20 through the inside of the heater 2 and thereby provides fluid flow io past the heating elements of the heater 2. The seal 27 is usually achieved via a pump seat or a packer. The fluid 20 passes through the heater 2, and is thereby heated. The fluid 20 then passes through a pressure reducer 28 and is displaced out into the reservoir target zone 8 through perforations 30 in the casing 32.
is Simultaneous withdrawal of the heavy oil up the tubing-casing annulus 34 may or may not take place during hot fluid injection. For instance, it may be advantageous to allow the hot fluid to soak in the well for a short period prior to oil production to allow the heat to penetrate further.
The pressure reducer 28 maintains a high fluid pressure inside the 2o heater. This is very useful for mufti-phase (i.e. combined gas 8~ liquid phases at downhole temperature and pressure) fluids, because high pressure helps to minimize the difference in the volumetric heat capacities between the gas and liquid phases and thus helps avoid the formation of hot spots in the heater.
2s The pressure reducer 28 is most preferably in the form of a flow restriction such as a valve (such as a back pressure regulator) or narrow orifice. For the purpose of this invention it will be understood that pressure reducer 28 is any structure that has the effect of increasing the pressure upstream of the pressure reducer 28 namely in the heater 2. The pressure 3o reducer 28 may be fixed in effect or may be variable in effect. In other words, the pressure reducer 28 may be for example a fixed orifice which does not change with flow through and thus has a variable effect on the upstream pressure (the higher the flow the greater the pressure). Or the pressure reducer may be in the form of a valve which changes orifice size 3s to allow various flows through the pressure reducer as required. The preferred form of the invention is a back pressure regulator which can be _g_ preset to maintain a given pressure over a range of flows, to ensure efficient heat transfer to the fluid from the heater.
It will be appreciated that the higher the temperature, the greater a pressure will be required to keep the heat transfer fluid in a liquid state in the s heater 2. The higher pressure can be achieved by altering the flow rate (i.e.
increasing the flow rate to increase pressure as the temperature increases) or by altering the orifice size, (i.e. decreasing the orifice at the same flow rate as temperature increases).
In the most preferred form of the invention the pressure reducer 28 io is a variable sized flow restricter which can be adjusted during operation of the heater 2 to maintain pressure in the heater 2 at a desired level. A less preferred but adequate pressure reducer 28 is one which is sized and shaped to cause a predetermined pressure at a predetermined flow rate of a particular fluid , having regard to ambient reservoir conditions. It will be is appreciated that the predetermined pressure will be the pressure required to maintain substantially even heat transfer to the heat transfer fluid 20 in the heater to prevent local hot spots from developing in the heater leading to heater burnout.
In addition the pressure reducer 28 is most preferable in the form of 2o an active element which is remotely adjustable as needed to maintain the desired pressure. In such a case the pressure reducer 28 is actively incorporated into a control system to permit the size of the orifice to be remotely adjusted as needed for pressure maintenance. A less preferred form, but one that still provides adequate results, is to use a passive 2s pressure reducer 28, and to monitor the pressure, temperature or flow through the heater 2. In the event that non-optimal conditions exist in the heater 2 then the temperature or flow rates (pumping rates) can be mod~ed to bring the conditions in the heater back into optimal conditions. In this regard, optimal conditions refer to pumping as much fluid 20 through the 3o heater 2 as quickly as possible at a pressure sufficient to keep the heat transfer to the fluid in the heater 2 substantially even to permit optimal heat transfer without the formation of hot spots leading to heater burnout.
In the preferred method, a sufficient volume of hot fluid 20 is injected into the target zone 8 for a sufficient time to allow a large volume of insitu oil 3s to be liquefied and drained. The injection pressure may be above fracture pressure. The injected fluid 20 will be displaced away from the wellbore as more fluid is injected but, depending upon the heat capacity of the fluid 20, as compared to the heat capacity of the formation, the heat will likely be lost fairly quickly to the near wellbore region.
The preferred heat transfer fluid 20 is a solvent for the heavy oil. The s solvent can be either a gas or liquid or a mixture thereof at ambient conditions. Better results are expected if the solvent is slightly below its bubble point pressure at reservoir conditions, so that it is present as a gas in the solvent chamber but has appreciable solubility in the crude oil. The solvent can be either a mixture of compounds (i.e., methane, ethane, io butane, propane, pentane, hexane plus other hydrocarbons, and carbon dioxide) or a relatively pure compound. Because any solvent co-produced with the oil can be extracted and recycled back into the reservoir, the solvent will typically be a blend of compounds. As discussed above the fluid 20 will also be keep sufficiently dense as either a liquid or gas in the heater 2 that is an efficient and even heat exchange takes place with the heater elements.
Pure gas pockets would lead to local hot spots and burnouts which why there is a need for pressure maintenance in the heater as previously discussed. The most preferred solvents are the so called light hydrocarbons, from C1 to C4.
2o White the preferred form of the invention is to use a solvent as the heat transfer fluid, it will be appreciated that present invention also comprehends the use of other fluids such as water or steam or a mixture thereof which are not solvents. For these fluids the change in viscosity of the in situ heavy oil is derived solely from the heat delivered to the formation by 2s the fluid. It will be appreciated that the one of the preferred forms of the present invention is a method of relatively quickly (in the order of hours or days) modifying the viscosity of the in situ oil. As such, for some formation conditions it may be more efficient to deliver a greater amount of heat, via a higher heat capacity fluid such as water, than to provide additional 3o viscosity reducing effects such as a solvent would provide. However, it will be appreciated that the use of solvents is generally preferred due to the relative permeable effects and other negative effects that can occur when introducing water into an oil producing formation. Quite simply, in some reservoirs, introducing water into the oil bearing zone may cause lower 3s production once the short term effect of the heat added dissipates.
Figure 2 shows the typical deployment of equipment used to implement the invention on a well site. There is~a solvent truck 36 (in this case a propane truck), and a rig tank 38 with kill fluid 40: The fluid 20 is pumped from the solvent truck 36 to the wellhead 14 via conventional tubing 42. Fluid pressure may be raised by a charge pump unit 44, if needed. A
s check valve 46 and a relief valve.48 are preferred as safety features to avoid excessive fluid pressure.
In some circumstances, it may be desirable to have a flare stack on site also. Alternatively there may be a (or several) propane tanks) which are periodically refilled by propane trucks 36.
io Also shown is a generator truck 50 which supplies power to the heater 2 via power and ground transmission lines 54 which connect the generator truck 50 to the coiled tubing truck 6. Process control trailer 52, is connected via data acquisition, power and control lines 56 to the coiled tubing truck 6 and the generator truck 50.
is Figure 3 shows more detail of cross section AA of the heater 2 of Figure 1. A chamber 60 is created in a heavy oil reservoir 62 by the withdrawal of mobilized oil 64. The chamber 60 may initially form around a fracture if the fluid injection pressure is above fracture pressure. The fracture will be oriented either vertically or horizontally depending on the 2o depth of the reservoir. Over time, as the oil drains (shown at 64) it will eventually form an inverted teardrop shaped chamber 60 around a point injector (i.e. vertical injection well) and an elongated cylinder with an inverted teardrop cross-section around a horizontal well. Mobilized oil 64 drains down the sides of the chamber 60 and into the casing via perforation tunnels 2s 30, or slots or screens in the casing 32. Fluid 20 (preferably solvent) rises in the center of the chamber 60 and dissolves into the fresh oil at the surface of the chamber. This process is very efficient because the upward flow of solvent fluid 20 is physically separated from the downward flow of the mobilized oil 64. Alternatively the pressure can be cycled to separate 3o solvent injection from oil production. As the oil withdrawal proceeds the chamber 60 will grow in size until it encounters for example a shale barrier 66.
As can now be appreciated according to the invention described herein the heated solvent does not suffer heat losses during flow downhole, 3s because it is pumped downhole at ambient temperature. Furthermore, the present invention is not restricted to using water, as in the prior art to provide sufficient heat capacity to ensure that heat is delivered downhole.
According to the present invention the present method can be used to initiate formation of a gravity drainage chamber of sufficient size that significant production rates can be achieved very quickly. Once the s chamber has been established, there would be a large interfacial area for mixing of the solvent into the oil. Thus, subsequent rewery will occur with cold solvent, at a low cost and with environmental benefits, or possibly with periodic heat stimulations to, for example, spur extra production.
According to the present invention either a gas or hydrocarbon liquid io is heated in the downhole heater and then this hot liquid/gas mixture is injected into the formation to rapidly mobilize the oil within the near well bore area, namely within about 5-10 meters of the well. The present invention has a number of advantages over the prior steam techniques, including the following:
is 1 ) no requirement for water although water may be used;
OIL PRODUCTION
FIELD OF THE INVENTION
This invention relates generally to the extraction of hydrocarbons s such as heavy oil and bitumen from naturally occurring formations such as tar sands or the like. Most particularly this invention relates to a means to accelerate the recovery process thereby increasing the rate of return on capital and decreasing the financial risk of such heavy oil production projects.
io BACKGROUND OF THE INVENTION
Heavy oil and bitumens, such as may be found in deposits known as tar sands, may have viscosities greater than 1000 centipoise or specific gravities greater than .934 at 60°F (i.e. less than 20° API).
Hydrocarbons with such a high specific gravity and viscosity are difficult to efficiently is recover because they do not readily flow.
It has been long known that heat can be used to decrease the viscosity of heavy oils and hence improve the flow . Currently steam is the most common thermal stimulation used for heavy oil extraction. However, steam stimulation is subject to a number of problems, including heat losses 2o during injection, clay swelling problems, thief zones, emulsions, capillary surface tension effects and lack of confinement for shallower zones. In addition to these problems, the heating equipment is expensive to purchase and install and even more expensive to run, because of the large energy consumption required. For these reasons alternate techniques are being 2s sought.
Another thermal extraction technique, known as fireflood, is generally uneconomic due to very severe operating problems including corrosion, scale precipitation and explosion hazards after breakthrough.
One of the factors affecting the recovery of in situ oil, is the well 3o configuration. There are many different well configurations used. Different well configurations are used in different recovery techniques. The two main approaches in the past have been "huff and puff' (i.e., cyclic steaming) and steam floods. Recently, steam assisted gravity drainage (SAGD) has also been proposed and used.
SAGD requires the formation of a steam chamber. The steam chamber is essentially what is left behind in the oil bearing formation after the oil has been recovered from the chamber; as more oil is recovered, the chamber grows. Essentially in SAGD, water is heated above grade to form s steam, and then the steam is injected into the formation into the chamber.
The heated oil flows down the walls of the chamber and drains into the producing well. The advantage of SAGD that the countercurrent flow of steam upwards into the chamber in the reservoir and oil down and out of the reservoir is relatively efficient, thus the fluid flow rates may be high enough io to provide favorable economics.
There are many possible SAGD geometries including single well (injection and production from the same well) and dual or mu~iple well. The wells may be either horizontal or vertical. Generally horizontal wells are favored because they offer a longer exposure to the oil rich pay zone and is thereby facilitate economic production rates for highly viscous oils.
Single well SAGD requires the least capital cost, but heat losses due to countercurrent flow of steam into the well and oil out of the well having passing contact in the wellbore can be quite severe. For example, at an injection pressure of 1000 psig and 285°C, the enthalpy of the steam is 2o btu/lb and the enthalpy of the water is 542 btu/lb. Due to countercurrent heat exchange the temperature of the produced fluids (water and oil) will lower the temperature of the injected steam to some low temperature equilibrium point. Usually, the steam quality is 80% (i.e., 80% vapour and 20% liquid). Thus, the maximum heat delivered to the formation is only the 2s latent heat of vaporization (i.e. about 50% of the total heat input). With additional heat losses through the well casing during injection, the net heat delivery to the formation is quite low and therefore this technique inefficient.
The idea of replacing steam with cold solvent was first proposed by Nenniger' (1979). This technique has shown much promise for production 30 of heavy oil with minimal environmental impact, primarily because oil production would not require the use of significant amounts of water and energy to form the needed steam. Energy requirements for cold solvent extraction are expected to be less than 4% of those required for steam extraction. Insitu recovery with cold solvent has minimal environmental ' Nenniger, E.H., Hydrocarbon Recovery, Canadian Patent 1,059,432 impact compared to surface mining techniques.
The physics of cold solvent stimulation are not fully understood. The measured solvent diffusion rates are typically 100-1000 times higher than predicted by theory~3. A key economic requirement is efficient recovery of s : the solvent, so light gases such as ethane and propane which can be recovered by pressure blowdown are generally preferred. A recent study has reported the ratio of ethane solvent loss to bitumen produced, was low as seven percent (wtlwt).
However, the calculated production rates for solvent extraction are to believed to be too low to justify commercial application and a field test of cold solvent extraction has never been performed. Bench tests4 with warm solvent (propane) have shown that production rates can be increased about 20 fold simply by increasing the temperature from 20°C to 90°C.
However, the heat capacity of heated solvents (i.e. vaporized propane and ethane) is is very low, so it is impractical to heat hydrocarbon gas above grade and pump the same downhoie and achieve any heat delivery at the reservoir.
The Vapex process4 proposes to combine heat with solvent to benefit from possible synergies. However, the heat is provided by steam or hot water which is heated above grade and consequently suffers from the ail 2o problems mentioned above (countercurrent heat exchange, formation damage problems with clays, emulsions; capillary pressure, water treatment, water supply, etc).
Lab tests and modeling have shown that the viscosity reduction of the oil occurs due to dissolution of the solvent into the oil and the upgrading of 2s the oil by de-asphaiting. The de-asphalting appears to occur locally when the oil is initially mobilized by dilution with solvent. Thus, in lab scale tests there has not been evidence of formation damage due to asphaitene accumulation in the near wellbore area.
A key requirement for both steam assisted gravity drainage and Z Dune, S.G.; E.H. Nenniger, V.S.V. Rajah, A Study ofBitumen Recovery by Gravity Drainage Using Low Temperature Soluble Gas In-jectiQn, The Canadian Journal of Chemical Engineering, Vol 67, December 1989.
3 Lim, et al, Three dimensional Scaled Physical Modelling of Solvent Vapour Extraction of Cold Lake Bitumen, JCPT, April 1996, Page 37 4 See Table 1 and Figure 7 of Butler et al, A New Process for Recovering Heavy Oils using Hot Water and Hydrocarbon Vapours, JCPT Jan 1991, pg 100 solvent assisted gravity drainage is the formation of a steam or solvent chamber in the reservoir. The chamber allows efficient countercurrent flow of solvent (or steam) upwards and flow of the heavy crude downwarcls along the walls of the chamber. The predicted oil drainage rate is proportional to s the square root of the height of the chamber (reference 4). Thus the oil production rates are predicted to be small initially and then grow with time until the roof of the chamber encounters a boundary such as an impermeable shale. Lab tests have confirmed the beneficial effect of the formation of the solvent chamber. Lab tests have also shown that the io maximum oil production rates will not occur until a large solvent chamber is formed. Unfortunately, this means that peak oil production rates do not occur until 3-4 years after the well is placed on production.
Thus, for cold solvent extraction the peak oil production rates are not expected to be achieved until perhaps three years after the capital costs of is the well and the production facilities are incurred. The delayed production response decreases the rate of return and increases the risk to the operator.
For example thief zones, etc, may not be identified until substantial costs have been incurred and yet before the recovery has become economic.
Thus, there is potential for a significant economic benefit, if the 2o solvent chamber could be quickly established. For example, the capital cost of drilling and completing a horizontal well might be typically 500,000 dollars.
The minimum internal rate of return for a oil project is typically about 15%.
Thus, the opportunity cost of a one year delay in the peak production rate is 75K$. If peak production is accelerated, so it occurs in the first year rather 2s than the third, then the value added by early development of the solvent chamber would be 150K$ to 250K$ per well.
Thus, while the cold solvent extraction process has great advantages due to energy effrciency and minimal environmental damage, it has never actually been field tested. The primary reason for this is the belief that the 3o cold solvent production rates will be too low to be economic, particularly with the expected 3-4. year delay in achieving peak production rates.
BRIEF SUMMARY OF THE INVENTION
What is desired therefore, is a means to accelerate the initial oil production rate by encouraging the rapid formation of a solvent gravity 3s drainage. According to one aspect of the present invention there is provided a method to accelerate the process of forming a gravity assist drainage chamber by effectively and rapidly injecting significant volumes of sufficiently heated gaseous and liquid solvents into the reservoir using downhole heater technology.
s The preferred apparatus to perform the method of the present invention is a coiled tubing conveyed downhole heater. This heater can be used to place the desired heat without the usual wellbore heat losses associated with surface injection of hot fluids. In the preferred method the heater is lowered into the well, placed on a pump seating nipple or packer io and the cold fluid is pumped into tubing-coiled tubing annulus. The cold fluid is heated as it passes through the heater and then the hot fluid is squeezed into the formation. Because the heater is deployed on coiled tubing, it can also be displaced to the end of a horizontal well. The most preferred heater has an extremely high output (for example more than about 100 kW), yet it is fits inside 2 718" production tubing. Because the heat is added downhole close to the target formation, it is feasible to heat fluids with relatively low heat capacities (i.e. hydrocarbon gases and liquids) and provide efficient delivery of heat into the formation with minimal heat losses.
Thus according to an aspect of the present invention a heated solvent 2o stimulation is performed to initiate formation of a gravity drainage chamber.
Once the chamber has been established,. there would be a large interfacial area for efficient mixing of the solvent into the oil. Subsequent cold solvent injection would achieve commercial production rates without requiring additional heat. Therefore according to the present invention there is 2s provided: A method for stimulating heavy oil production from an oil bearing formation comprising:
a) placing a downhole heater in the formation adjacent to the oil producing zone, to heat a heat transfer fluid;
b) energizing said downhole heater and passing said heat 3o transfer fluid past said heater to thereby heat said heat transfer fluid;
c) injecting said heated heat transfer fluid into the oil bearing formation to bring said heated fluid into contact with said oil to thereby decrease the effective viscosity of said oil; and d) recovering said reduced viscosity oil to form an oil extraction ss chamber in said oil bearing formation.
According to another aspect of the invention there is provided a method according to the foregoing further including the step of regulating the pressure in said heater to permit tow heat capacity solvents to be heated.
According to a further aspect of the invention there is provided a downhole heater having a pressure regulator at an exit end of said heater s for maintaining pressure in said ;heater sufficiently high to permit efficient heating of low heat capacity fluids.
BRIEF DESCRIPTION~F THE DRAWINGS
Reference will now be made, by way of example only, to preferred embodiments of the invention as illustrated in the accompanying drawings io and in which:
Figure 1 illustrates a schematic of the invention, the. injection of hot fluid into the heavy oi! reservoir to accelerate the creation of a solvent chamber.
Figure 2 illustrates a typical well site deployment for the hot solvent is stimulation Figure 3 illustrates a typical solvent chamber created as a consequence of the injection of hot solvent. ' DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Figure 1 shows a schematic of the apparatus used in the method 2o according to the present invention. A heater 2 is mounted on the end of a length of coiled tubing 4. The heater 2 ~ is deployed from a coiled tubing truck 6 to a target zone 8 by an injector 10. During deployment a pressure seal 12 is formed between a wellhead assembly 14 and the coiled tubing 4 by a stripper 16. Once the heater 2 has reached the target zone 8, a BOP
2s (Blow Out Preventer) 18 is energized and an additional pressure seal around the coiled tubing is formed with the BOP tubing rams in a conventional manner. A power cable 5, carried within the coiled tubing 4 is used to energize the heater 2. As the power cable 5 is contained within the coiled tubing it is protected from damage due to abrasion and pressure 3o cycles.
The heater 2 may be in the form of an electrically powered resistance heater of the flow through type. While other heater designs would also work, the electrical resistance heater provides adequate results. To provide best results it is preferable to have a power output of more than 100 kw .
The heater is most preferably compact i.e. small diameter and of a short length (preferably less than 2 metres) to be easily positioned in the well near the formation to be treated. A packed bed resistance element as disclosed in my prior patent 2,052,202 will provide adequate results.
s A heat transfer fluid 20 is pumped through a valve 22 and into a flow "T" fitting 24. The fluid 20, which is described in more detail below, then travels downhole in the annulus between well tubing 26 and the coiled tubing 4. A seal 27 between the heater 2 and the well tubing 26 forces the fluid 20 through the inside of the heater 2 and thereby provides fluid flow io past the heating elements of the heater 2. The seal 27 is usually achieved via a pump seat or a packer. The fluid 20 passes through the heater 2, and is thereby heated. The fluid 20 then passes through a pressure reducer 28 and is displaced out into the reservoir target zone 8 through perforations 30 in the casing 32.
is Simultaneous withdrawal of the heavy oil up the tubing-casing annulus 34 may or may not take place during hot fluid injection. For instance, it may be advantageous to allow the hot fluid to soak in the well for a short period prior to oil production to allow the heat to penetrate further.
The pressure reducer 28 maintains a high fluid pressure inside the 2o heater. This is very useful for mufti-phase (i.e. combined gas 8~ liquid phases at downhole temperature and pressure) fluids, because high pressure helps to minimize the difference in the volumetric heat capacities between the gas and liquid phases and thus helps avoid the formation of hot spots in the heater.
2s The pressure reducer 28 is most preferably in the form of a flow restriction such as a valve (such as a back pressure regulator) or narrow orifice. For the purpose of this invention it will be understood that pressure reducer 28 is any structure that has the effect of increasing the pressure upstream of the pressure reducer 28 namely in the heater 2. The pressure 3o reducer 28 may be fixed in effect or may be variable in effect. In other words, the pressure reducer 28 may be for example a fixed orifice which does not change with flow through and thus has a variable effect on the upstream pressure (the higher the flow the greater the pressure). Or the pressure reducer may be in the form of a valve which changes orifice size 3s to allow various flows through the pressure reducer as required. The preferred form of the invention is a back pressure regulator which can be _g_ preset to maintain a given pressure over a range of flows, to ensure efficient heat transfer to the fluid from the heater.
It will be appreciated that the higher the temperature, the greater a pressure will be required to keep the heat transfer fluid in a liquid state in the s heater 2. The higher pressure can be achieved by altering the flow rate (i.e.
increasing the flow rate to increase pressure as the temperature increases) or by altering the orifice size, (i.e. decreasing the orifice at the same flow rate as temperature increases).
In the most preferred form of the invention the pressure reducer 28 io is a variable sized flow restricter which can be adjusted during operation of the heater 2 to maintain pressure in the heater 2 at a desired level. A less preferred but adequate pressure reducer 28 is one which is sized and shaped to cause a predetermined pressure at a predetermined flow rate of a particular fluid , having regard to ambient reservoir conditions. It will be is appreciated that the predetermined pressure will be the pressure required to maintain substantially even heat transfer to the heat transfer fluid 20 in the heater to prevent local hot spots from developing in the heater leading to heater burnout.
In addition the pressure reducer 28 is most preferable in the form of 2o an active element which is remotely adjustable as needed to maintain the desired pressure. In such a case the pressure reducer 28 is actively incorporated into a control system to permit the size of the orifice to be remotely adjusted as needed for pressure maintenance. A less preferred form, but one that still provides adequate results, is to use a passive 2s pressure reducer 28, and to monitor the pressure, temperature or flow through the heater 2. In the event that non-optimal conditions exist in the heater 2 then the temperature or flow rates (pumping rates) can be mod~ed to bring the conditions in the heater back into optimal conditions. In this regard, optimal conditions refer to pumping as much fluid 20 through the 3o heater 2 as quickly as possible at a pressure sufficient to keep the heat transfer to the fluid in the heater 2 substantially even to permit optimal heat transfer without the formation of hot spots leading to heater burnout.
In the preferred method, a sufficient volume of hot fluid 20 is injected into the target zone 8 for a sufficient time to allow a large volume of insitu oil 3s to be liquefied and drained. The injection pressure may be above fracture pressure. The injected fluid 20 will be displaced away from the wellbore as more fluid is injected but, depending upon the heat capacity of the fluid 20, as compared to the heat capacity of the formation, the heat will likely be lost fairly quickly to the near wellbore region.
The preferred heat transfer fluid 20 is a solvent for the heavy oil. The s solvent can be either a gas or liquid or a mixture thereof at ambient conditions. Better results are expected if the solvent is slightly below its bubble point pressure at reservoir conditions, so that it is present as a gas in the solvent chamber but has appreciable solubility in the crude oil. The solvent can be either a mixture of compounds (i.e., methane, ethane, io butane, propane, pentane, hexane plus other hydrocarbons, and carbon dioxide) or a relatively pure compound. Because any solvent co-produced with the oil can be extracted and recycled back into the reservoir, the solvent will typically be a blend of compounds. As discussed above the fluid 20 will also be keep sufficiently dense as either a liquid or gas in the heater 2 that is an efficient and even heat exchange takes place with the heater elements.
Pure gas pockets would lead to local hot spots and burnouts which why there is a need for pressure maintenance in the heater as previously discussed. The most preferred solvents are the so called light hydrocarbons, from C1 to C4.
2o White the preferred form of the invention is to use a solvent as the heat transfer fluid, it will be appreciated that present invention also comprehends the use of other fluids such as water or steam or a mixture thereof which are not solvents. For these fluids the change in viscosity of the in situ heavy oil is derived solely from the heat delivered to the formation by 2s the fluid. It will be appreciated that the one of the preferred forms of the present invention is a method of relatively quickly (in the order of hours or days) modifying the viscosity of the in situ oil. As such, for some formation conditions it may be more efficient to deliver a greater amount of heat, via a higher heat capacity fluid such as water, than to provide additional 3o viscosity reducing effects such as a solvent would provide. However, it will be appreciated that the use of solvents is generally preferred due to the relative permeable effects and other negative effects that can occur when introducing water into an oil producing formation. Quite simply, in some reservoirs, introducing water into the oil bearing zone may cause lower 3s production once the short term effect of the heat added dissipates.
Figure 2 shows the typical deployment of equipment used to implement the invention on a well site. There is~a solvent truck 36 (in this case a propane truck), and a rig tank 38 with kill fluid 40: The fluid 20 is pumped from the solvent truck 36 to the wellhead 14 via conventional tubing 42. Fluid pressure may be raised by a charge pump unit 44, if needed. A
s check valve 46 and a relief valve.48 are preferred as safety features to avoid excessive fluid pressure.
In some circumstances, it may be desirable to have a flare stack on site also. Alternatively there may be a (or several) propane tanks) which are periodically refilled by propane trucks 36.
io Also shown is a generator truck 50 which supplies power to the heater 2 via power and ground transmission lines 54 which connect the generator truck 50 to the coiled tubing truck 6. Process control trailer 52, is connected via data acquisition, power and control lines 56 to the coiled tubing truck 6 and the generator truck 50.
is Figure 3 shows more detail of cross section AA of the heater 2 of Figure 1. A chamber 60 is created in a heavy oil reservoir 62 by the withdrawal of mobilized oil 64. The chamber 60 may initially form around a fracture if the fluid injection pressure is above fracture pressure. The fracture will be oriented either vertically or horizontally depending on the 2o depth of the reservoir. Over time, as the oil drains (shown at 64) it will eventually form an inverted teardrop shaped chamber 60 around a point injector (i.e. vertical injection well) and an elongated cylinder with an inverted teardrop cross-section around a horizontal well. Mobilized oil 64 drains down the sides of the chamber 60 and into the casing via perforation tunnels 2s 30, or slots or screens in the casing 32. Fluid 20 (preferably solvent) rises in the center of the chamber 60 and dissolves into the fresh oil at the surface of the chamber. This process is very efficient because the upward flow of solvent fluid 20 is physically separated from the downward flow of the mobilized oil 64. Alternatively the pressure can be cycled to separate 3o solvent injection from oil production. As the oil withdrawal proceeds the chamber 60 will grow in size until it encounters for example a shale barrier 66.
As can now be appreciated according to the invention described herein the heated solvent does not suffer heat losses during flow downhole, 3s because it is pumped downhole at ambient temperature. Furthermore, the present invention is not restricted to using water, as in the prior art to provide sufficient heat capacity to ensure that heat is delivered downhole.
According to the present invention the present method can be used to initiate formation of a gravity drainage chamber of sufficient size that significant production rates can be achieved very quickly. Once the s chamber has been established, there would be a large interfacial area for mixing of the solvent into the oil. Thus, subsequent rewery will occur with cold solvent, at a low cost and with environmental benefits, or possibly with periodic heat stimulations to, for example, spur extra production.
According to the present invention either a gas or hydrocarbon liquid io is heated in the downhole heater and then this hot liquid/gas mixture is injected into the formation to rapidly mobilize the oil within the near well bore area, namely within about 5-10 meters of the well. The present invention has a number of advantages over the prior steam techniques, including the following:
is 1 ) no requirement for water although water may be used;
2) no risk of formation damage due to clay swelling if water is not used;
3) no risk of formation damage due to emulsions;
4) no countercurrent heat exchange losses in the tubing because 20 of heating below grade;
5) efficient and inexpensive heat delivery to deeper reservoirs because heat losses during transportation are eliminated;
6) large thermal gradients within the formation will promote solvent reflux ~i.e., vaporization of the solvent from the near wellbore area 2s and condensation of the solvent into the "cold" heavy crude oil).
7) elevated near-wellbore temperatures to increase production rates.
8) reduced capital and operating costs (no water treatment, or steam generation required).
30 9) reduced environmental impact (in situ recovery vs surface mining).
10) quick payout of the stimulation costs because the operator can expense costs directly against increased revenue from the well.
According to the present invention the method described herein will 35 be accomplished in one of two manners. The first way is to provide short stimulation treatment, namely, a short (1-14) day duration stimulation followed by a 1-2 month blowdown or draw down. The second way is to use the method as an ongoing continuous injection process with simultaneous oil production over a time sufficient to establish a viable chamber in the formation. Of course depending upon the well and the flows from the well, s in some cases the increase in production may justify a continuous on site stimulation and draw down over a longer term.
By way of example, according to the present invention a hot solvent stimulation could deliver up to 10,000 kg of ethane to the reservoir at 200°C, or 25,000 kg of ethane at 100°C, within a 24 hour period. With an average io solvent efficiency ratio of 0.3 and 30% porosity, 25,000 kg of ethane at 100°C could produce a chamber of 500m3 volume simply by blowing down the initial hot solvent injection. Initial production rates after a stimulation are much higher than the cold production rates would be without the stimulation because of a number of effects including the lower viscosity of the oil due is to higher temperatures, presence of the dissolved solvent and the upgrading of the oil by de-asphalting. Quick production of the stimulated oil will result in quick formation of a chamber. Thus, production rates can be greatly accelerated as compared to production rates achievable without such a stimulation as set out in more detail below. If the stimulation cost is 54K$, 2o then the net saving to the heavy oil operator is expected to be 100 to 200K$
per well.
The principal advantage of the hot solvent injection as described herein is to rapidly and efficiently form a solvent chamber. The thermal stimulation provided by the present invention is a short term effect, and the 2s formation temperature will tend to cool fairly soon after the treatment is finished. However, during the short interval while the elevated temperature is in effect, much more production can be expected. The method taught in this patent allows a large solvent chamber to form in a matter of several weeks (vs 3-4 years). A sufficiently large solvent chamber would provide 3o economical oil production rates with or without requiring additional heat input. Thus, this process would allow efficient and economic extraction of subsequent oil with cold solvent.
It can now be further appreciated that another advantage of the hot solvent stimulation described herein is that the heat loss from the solvent as 3s it flows out into the reservoir will tend to provide a localized thermal benefit.
This might be useful to accelerate oil extraction and chamber formation at a particular location in a horizontal well. This is useful because it is difficult to control fluid placement in a horizontal well.
The concepts taught in this patent may also have application in enhancing recovery of less viscous oils depending on the circumstances.
s It will be appreciated by those skilled in the art that the foregoing is a discussion of preferred embodiments of the invention and that various modifications or alterations are possible without departing from the broad spirit of the invention as defined by the appended claims. Some of these are discussed above and others will be apparent to those skilled in the art.
io For example, although various heat transfer fluids may be used, the overall concept is to more quickly form a viable oil extraction chamber to improve commercial recovery rates of insitu oil.
30 9) reduced environmental impact (in situ recovery vs surface mining).
10) quick payout of the stimulation costs because the operator can expense costs directly against increased revenue from the well.
According to the present invention the method described herein will 35 be accomplished in one of two manners. The first way is to provide short stimulation treatment, namely, a short (1-14) day duration stimulation followed by a 1-2 month blowdown or draw down. The second way is to use the method as an ongoing continuous injection process with simultaneous oil production over a time sufficient to establish a viable chamber in the formation. Of course depending upon the well and the flows from the well, s in some cases the increase in production may justify a continuous on site stimulation and draw down over a longer term.
By way of example, according to the present invention a hot solvent stimulation could deliver up to 10,000 kg of ethane to the reservoir at 200°C, or 25,000 kg of ethane at 100°C, within a 24 hour period. With an average io solvent efficiency ratio of 0.3 and 30% porosity, 25,000 kg of ethane at 100°C could produce a chamber of 500m3 volume simply by blowing down the initial hot solvent injection. Initial production rates after a stimulation are much higher than the cold production rates would be without the stimulation because of a number of effects including the lower viscosity of the oil due is to higher temperatures, presence of the dissolved solvent and the upgrading of the oil by de-asphalting. Quick production of the stimulated oil will result in quick formation of a chamber. Thus, production rates can be greatly accelerated as compared to production rates achievable without such a stimulation as set out in more detail below. If the stimulation cost is 54K$, 2o then the net saving to the heavy oil operator is expected to be 100 to 200K$
per well.
The principal advantage of the hot solvent injection as described herein is to rapidly and efficiently form a solvent chamber. The thermal stimulation provided by the present invention is a short term effect, and the 2s formation temperature will tend to cool fairly soon after the treatment is finished. However, during the short interval while the elevated temperature is in effect, much more production can be expected. The method taught in this patent allows a large solvent chamber to form in a matter of several weeks (vs 3-4 years). A sufficiently large solvent chamber would provide 3o economical oil production rates with or without requiring additional heat input. Thus, this process would allow efficient and economic extraction of subsequent oil with cold solvent.
It can now be further appreciated that another advantage of the hot solvent stimulation described herein is that the heat loss from the solvent as 3s it flows out into the reservoir will tend to provide a localized thermal benefit.
This might be useful to accelerate oil extraction and chamber formation at a particular location in a horizontal well. This is useful because it is difficult to control fluid placement in a horizontal well.
The concepts taught in this patent may also have application in enhancing recovery of less viscous oils depending on the circumstances.
s It will be appreciated by those skilled in the art that the foregoing is a discussion of preferred embodiments of the invention and that various modifications or alterations are possible without departing from the broad spirit of the invention as defined by the appended claims. Some of these are discussed above and others will be apparent to those skilled in the art.
io For example, although various heat transfer fluids may be used, the overall concept is to more quickly form a viable oil extraction chamber to improve commercial recovery rates of insitu oil.
Claims (13)
1. A method of extracting, through a well, bitumen from an extraction chamber formed in a tar sand formation, said method comprising:
(a) mounting a heater onto an end of a length of coil tubing;
(b) deploying said heater from a coil tubing truck into a target zone;
(c) selecting a solvent fluid for injection into the tar sand formation;
(d) pumping the solvent fluid down hole as a liquid;
(e) heating the solvent liquid down hole to vaporize the solvent liquid so it is a solvent gas by directing the solvent liquid into contact with said down hole heater;
(f) passing the heated solvent gas into the extraction chamber to permit the solvent gas to transfer heat to the bitumen within the extraction chamber to mobilize the bitumen;
(g) co-producing said solvent fluid and mobilized bitumen from the extraction chamber;
(h) separating the solvent fluid from the mobilized bitumen on the surface; and (i) reusing the solvent fluid in the extraction chamber by repeating steps d) to h) above.
(a) mounting a heater onto an end of a length of coil tubing;
(b) deploying said heater from a coil tubing truck into a target zone;
(c) selecting a solvent fluid for injection into the tar sand formation;
(d) pumping the solvent fluid down hole as a liquid;
(e) heating the solvent liquid down hole to vaporize the solvent liquid so it is a solvent gas by directing the solvent liquid into contact with said down hole heater;
(f) passing the heated solvent gas into the extraction chamber to permit the solvent gas to transfer heat to the bitumen within the extraction chamber to mobilize the bitumen;
(g) co-producing said solvent fluid and mobilized bitumen from the extraction chamber;
(h) separating the solvent fluid from the mobilized bitumen on the surface; and (i) reusing the solvent fluid in the extraction chamber by repeating steps d) to h) above.
2. A method as claimed in claim 1 wherein the solvent is one or more of C1 to C4.
3. A method as claimed in claim 2 wherein the solvent is ethane.
4. A method as claimed in claim 2 wherein the solvent is propane.
5. A method as claimed in claim 2 wherein the solvent is butane.
6. A method as claimed in claim 1 wherein the heating step further includes heating a mixture of water and/or steam.
7. A method as claimed in claim 1 wherein the solvent fluid is pumped down hole for a period of time, and then stopped, the extraction chamber is drawn down to remove said solvent and mobilized fluids such as bitumen from said chamber, and the solvent fluid is again pumped down hole for a period of time.
8. A method as claimed in claim 1 wherein said solvent is continuously pumped down hole, heated and vaporized and continuously co-produced with mobilized bitumen and reused.
9. A method as claimed in claim 1 wherein said method includes providing a source of solvent fluid adjacent to said well.
10. A method as claimed in claim 10 wherein said method includes the step of providing said solvent fluid by means of one or more trucks.
11. A method as claimed in claim 10 wherein said method includes the step of providing said solvent fluid by means of one or more tanks adjacent to said well.
12. A method as claimed in claim 1 wherein said well is a vertical well.
13. A method as claimed in claim 1 wherein said well is a horizontal well.
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA 2235085 CA2235085C (en) | 1998-04-17 | 1998-04-17 | Method and apparatus for stimulating heavy oil production |
Related Parent Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA 2235085 Division CA2235085C (en) | 1998-04-17 | 1998-04-17 | Method and apparatus for stimulating heavy oil production |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2567399A1 CA2567399A1 (en) | 1999-10-17 |
| CA2567399C true CA2567399C (en) | 2009-01-27 |
Family
ID=29275564
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| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA002567399A Expired - Lifetime CA2567399C (en) | 1998-04-17 | 1998-04-17 | Method and apparatus for stimulating heavy oil production |
| CA 2235085 Expired - Lifetime CA2235085C (en) | 1998-04-17 | 1998-04-17 | Method and apparatus for stimulating heavy oil production |
Family Applications After (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA 2235085 Expired - Lifetime CA2235085C (en) | 1998-04-17 | 1998-04-17 | Method and apparatus for stimulating heavy oil production |
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| CA (2) | CA2567399C (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US8434551B2 (en) | 2008-09-26 | 2013-05-07 | N-Solv Corporation | Method of controlling growth and heat loss of an in situ gravity draining chamber formed with a condensing solvent process |
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| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CA2351148C (en) | 2001-06-21 | 2008-07-29 | John Nenniger | Method and apparatus for stimulating heavy oil production |
| CA2549614C (en) | 2006-06-07 | 2014-11-25 | N-Solv Corporation | Methods and apparatuses for sagd hydrocarbon production |
| CA2552482C (en) | 2006-07-19 | 2015-02-24 | N-Solv Corporation | Methods and apparatuses for enhanced in situ hydrocarbon production |
| CA2645267C (en) | 2008-11-26 | 2013-04-16 | Imperial Oil Resources Limited | Solvent for extracting bitumen from oil sands |
| CA2644821C (en) | 2008-11-26 | 2013-02-19 | Imperial Oil Resources Limited | A method for using native bitumen markers to improve solvent-assisted bitumen extraction |
| MX2012006949A (en) * | 2009-12-16 | 2012-07-30 | Red Leaf Resources Inc | Method for the removal and condensation of vapors. |
| CA2688937C (en) | 2009-12-21 | 2017-08-15 | N-Solv Corporation | A multi-step solvent extraction process for heavy oil reservoirs |
| CA2691889C (en) | 2010-02-04 | 2016-05-17 | Statoil Asa | Solvent injection recovery process |
| US10094208B2 (en) | 2010-02-04 | 2018-10-09 | Statoil Asa | Solvent and gas injection recovery process |
| CA2693640C (en) | 2010-02-17 | 2013-10-01 | Exxonmobil Upstream Research Company | Solvent separation in a solvent-dominated recovery process |
| CA2696638C (en) | 2010-03-16 | 2012-08-07 | Exxonmobil Upstream Research Company | Use of a solvent-external emulsion for in situ oil recovery |
| CA2705643C (en) | 2010-05-26 | 2016-11-01 | Imperial Oil Resources Limited | Optimization of solvent-dominated recovery |
| CN103147733B (en) * | 2013-03-12 | 2015-08-05 | 中国石油天然气股份有限公司 | The electric ignition of combustion in situ rolling-up type and monitoring system |
| CN103434584B (en) * | 2013-08-23 | 2015-12-30 | 四川宏华石油设备有限公司 | For the exclusive trail car of blowout preventer |
| CN104265255B (en) * | 2014-09-26 | 2017-01-25 | 中国石油天然气股份有限公司 | Two-dimensional microcosmic visual thickened oil replacement simulation experiment system and use method thereof |
| US10550679B2 (en) | 2017-04-27 | 2020-02-04 | Conocophillips Company | Depressurizing oil reservoirs for SAGD |
| US10584569B2 (en) | 2017-05-15 | 2020-03-10 | Conocophillips Company | Electric heat and NGL startup for heavy oil |
| CA2972203C (en) | 2017-06-29 | 2018-07-17 | Exxonmobil Upstream Research Company | Chasing solvent for enhanced recovery processes |
| CA2974712C (en) | 2017-07-27 | 2018-09-25 | Imperial Oil Resources Limited | Enhanced methods for recovering viscous hydrocarbons from a subterranean formation as a follow-up to thermal recovery processes |
| CA2978157C (en) | 2017-08-31 | 2018-10-16 | Exxonmobil Upstream Research Company | Thermal recovery methods for recovering viscous hydrocarbons from a subterranean formation |
| CA2983541C (en) | 2017-10-24 | 2019-01-22 | Exxonmobil Upstream Research Company | Systems and methods for dynamic liquid level monitoring and control |
-
1998
- 1998-04-17 CA CA002567399A patent/CA2567399C/en not_active Expired - Lifetime
- 1998-04-17 CA CA 2235085 patent/CA2235085C/en not_active Expired - Lifetime
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US8434551B2 (en) | 2008-09-26 | 2013-05-07 | N-Solv Corporation | Method of controlling growth and heat loss of an in situ gravity draining chamber formed with a condensing solvent process |
| US9476291B2 (en) | 2008-09-26 | 2016-10-25 | N-Solv Corporation | Method of controlling growth and heat loss of an in situ gravity drainage chamber formed with a condensing solvent process |
Also Published As
| Publication number | Publication date |
|---|---|
| CA2567399A1 (en) | 1999-10-17 |
| CA2235085C (en) | 2007-01-09 |
| CA2235085A1 (en) | 1999-10-17 |
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