The bitumen resources in Alberta, Canada, are one of the world's largest liquid hydrocarbon deposits. The total resource that can potentially be exploited by thermal enhanced oil recovery (“EOR”) is about 1.4 trillion bbls. About 40% of this resource can be exploited using existing developed technology, such as Steam Assisted Gravity Drainage (“SAGD”) or Cyclic Steam Stimulation (“CSS”). But the remaining 60% cannot be exploited using known technology. Table 1 shows two other resources that could potentially be developed and exploited using thermal EOR—carbonate bitumen at 448 billion bbls and thin-pay bitumen at 410 billion bbls.
Steam Assisted Gravity Drainage (“SAGD”) is a commercial thermal enhanced oil recovery (“EOR”) process, using saturated steam injected into a horizontal well, where latent heat is used to heat bitumen and lower its viscosity so it drains, by gravity, to an underlying, parallel, twin horizontal well, completed near the reservoir floor.
Since the process inception in the early 1980's, SAGD has become the dominant, in situ process to recover bitumen from Alberta's bitumen deposits (Butler, R., “Thermal Recovery of Oil & Bitumen”, Prentice-Hall, 1991). Today's SAGD bitumen production in Alberta is about 300 Kbbl/d with installed capacity at about 475 Kbbl/d (Oilsands Review, 2010). SAGD is now the world's leading thermal EOR process.
After conversion to normal SAGD operations, a steam chamber forms, around the injection 2 and production 4 wells, where the void space is occupied by steam 6. Steam condenses at the boundaries of the chamber, releases latent heat (heat of condensation) and heats bitumen, connate water and the reservoir matrix. Heated bitumen and water drain, by gravity, to the lower production well 4. The steam chamber grows upward and outward as bitumen is drained, by gravity, into the lower production well 4.
Produced fluids are near saturated steam temperature, so it is only the latent heat of steam that contributes to the process in the reservoir. But, some of the sensible heat can be captured from surface heat exchangers (a greater fraction at higher temperatures), so a useful rule-of-thumb for net heat contribution of steam is 1000 BTU/lb. for the pressure (“P”) and temperature (“T”) range of most SAGD projects, as best seen in
The operational performance of SAGD may be characterized by measurement of the following parameters: saturated steam pressure (“P”) and temperature (“T”) in the steam chamber, as best seen in
During the SAGD process, the SAGD operator has two choices to make—the sub-cool target T difference and the operating pressure in the reservoir. A typical sub-cool target of about 10 to 30° C. is meant to ensure no live steam breaks through to the production well. Process pressure and temperature are linked (
Despite becoming the dominant thermal EOR process, SAGD has some limitations and detractions. A good SAGD project includes:
If these characteristics are not attained or other limitations are experienced, SAGD may be impaired, as follows:
The simple SAGD control strategy (to inject steam to meet a pressure target and produce liquids to meet a sub-cool target) may be overridden if the system is constrained by hydraulic limits in the horizontal production well 4.
When SAGD is producing fluids near their maximum rates, hydraulic limitations may constrain operations. The steam chamber is well-developed. Pressures within the steam chamber are near constant, even though there can be a significant pressure drop in the steam injection well (Parappilly, R. & Zhao, L., “SAGD with a Longer Wellbore”, JCPT, June 2009). The injector pressure drop is mostly used to distribute steam injection evenly down the well length. Because steam is a gas with low viscosity and the steam chamber has a very high permeability, steam chamber pressures equilibrate rapidly.
The production well is a different story. Steam-trap (sub-cool) control ensures (or is intended to ensure) that liquids (water and bitumen) cover the horizontal production well so that steam breakthrough to the well is prevented. Ideally, the liquid/steam interface 12 would lay between the horizontal producer 4 and the horizontal injector 2. If the wells were shut-in, the steam/liquid interface 12 would form a horizontal plane between the two wells. At steady-state production, even though gas (steam) pressures are equilibrated, the interface 12 is tilted because the liquids are in direct contact with the production well 4, and there is a natural pressure drop in the well due to production flow down the length of the well. This pressure drop is present for each of natural lift, gas lift, or submersible pump. For draw-down at the well heel, the lowest pressure is near the heel, and the tilted interface has its high point at the well toe (
If liquid production rates and pressure drops are too high, the top of the interface 12 can cover (flood) the toe of the steam injector 14 and/or the heel of the production well 16 can be opened to the steam chamber (
Because the expected interface 12 is mostly flat, except near the drawdown site (
The rule-of-thumb for proper SAGD operation, to obviate potential hydraulic limitations, is that the pressure drop in the production well 4, due to liquid flow, should not exceed the hydrostatic head between the injection 2 and production well 4 locations. For a 5 metre well spacing, the hydrostatic head is about 50 KPa or 8 psi. Unfortunately, few SAGD operators can accurately measure these pressure drops.
Well trajectory variations may also affect hydraulic limits. As best seen in
From an operational standpoint the way to ameliorate hydraulic limitations is to reduce production rates (and steam injection) until pressure drops in the production well are within allowed limits. This can also be accomplished by increasing sub-cool targets.
From a design standpoint, increasing injector/producer separation, increasing pipe/tubing size, or decreasing horizontal well lengths may avoid hydraulic limitations. Each of these remedies has an economic penalty. Increased well spacing extends start-up times and reduces early bitumen productivity. Increased pipe/tubing sizes increases capital and drilling costs. Decreased well lengths reduce bitumen productivity.
With about 5 metre spacing between the injector well 2 and the producer well 4, industry has settled on horizontal well lengths of about 500 to 1000 metres. (Parappilly (2009), (Das, S., “Wellbore Hydraulics in a SAGD Well Pair” SPE 97922, November 2005), (Cenovus, “Telephone Lake Project”, website, December 2011), (Komery, D. et al, “Pilot Testing of Post-Steam Bitumen Recovery from Mature SAGD Wells in Canada”, University of Alberta Web, Feb. 14, 1998), (JACOS, “JACOS Hangingstone Expansion Project”, website, April 2010). Standard well lengths are about 500 to 800 m. (Cenovus (2011), JACOS (2010)).
Typical liner sizes for horizontal SAGD producers are about 7 inches in diameter (Smith, M., “SAGD Simplified”, New Tech Mag., Jun. 1, 2012). One study investigated SAGD well length extension feasibility using a well bore flow model (Q Flow) and a SAGD simulator (STARS-Steam, Thermal, and Advanced Process Reservoir Simulator) (Parappilly (2009)). The study concluded that well lengths of 1400 metres were feasible, if production well liner size was increased to 9% inches and if the pressure drop in the producer well was held to less than 50 KPa (Ross, E., “Going the Distance”, New Tech Mag., December 2008 (2012)).
The dominant process today is SAGD, using twin horizontal wells 2,4 to inject steam 6 and produce bitumen and water 8. But, SAGD has a hydraulic limitation that restricts well length to about 1000 metres, due to pressure drops in the production well.
Accordingly, there is a need for a process which overcomes the well length of prior art processes without hitting hydraulic limits, and preferably while maintaining productivity levels.
According to one aspect, a process to recover hydrocarbons from a reservoir is disclosed, where said hydrocarbons have an initial viscosity greater than 100,000 cp, preferably greater than 1,000 cp, said process comprising:
In one embodiment, the process further comprises initial steam injection into the reservoir then terminating said steam injection, where the ratio of oxygen to steam injected is controlled in the range from 0.05 to 1.00 (v/v).
In another aspect, a steam assisted gravity drainage with oxygen system for recovery of hydrocarbons from a reservoir is disclosed, where said hydrocarbons have an initial viscosity greater than 100,000 cp, preferably greater than 1,000 cp, said system comprising:
In one embodiment of the system, the vent gas means is single or multiple vertical wells. In another embodiment of the system, at least one vent gas means is a segregated annulus section in the heel rise section of the substantially horizontal well.
A further aspect is a steam assisted gravity drainage with oxygen system for recovery of hydrocarbons from a reservoir, where said hydrocarbons have an initial viscosity greater than 100,000 cp, preferably greater than 1,000 cp, said system comprising:
In one embodiment of the system, the vent gas means is single or multiple vertical wells.
In a further embodiment of the system, at least one vent gas means is a segregated annulus section in the heel rise section of the substantially horizontal well.
In yet another embodiment of the system, the second well is single or multiple vertical wells used for said injection of oxygen and steam.
In another embodiment of the system, the steam and oxygen are comingled on the surface prior to injection.
In yet another embodiment of the system, the steam and oxygen are segregated using packers and injected separately into said single or multiple vertical wells. Even further, the steam and oxygen are segregated using concentric tubing and packers, with steam in the central tubing surrounded by oxygen in the adjacent annulus, with said oxygen injected at a higher elevation in the reservoir than said steam.
In another aspect, a steam assisted gravity drainage with oxygen system for recovery of hydrocarbons for a reservoir is disclosed, where said hydrocarbons have an initial viscosity greater than 100,000 cp, preferably greater than 1,000 cp, said system comprising:
In one embodiment of the system, the oxygen injection site is a segregated toe section of said substantially horizontal well.
In yet another aspect, a steam assisted gravity drainage with oxygen system for recovery of hydrocarbons for a reservoir is disclosed, where said hydrocarbons have an initial viscosity greater than 100,000 cp, preferably greater than 1,000 cp, said system comprising:
In one embodiment of the system, the oxygen and steam injection site is a segregated toe section of said substantially horizontal well.
SAGDOX is an improved thermal enhanced oil recovery (EOR) process for bitumen recovery. The process can use geometry similar to SAGD (
One objective of SAGDOX is to reduce reservoir energy injection costs, while maintaining good efficiency and productivity. Oxygen combustion produces in situ heat at a rate of about 480 BTU/SCF oxygen independent of fuel combusted (
Table 2 presents thermal properties of steam+oxygen mixtures. Per unit heat delivered to the reservoir, oxygen volumes are ten times less than steam, and oxygen costs including capital charges are one half to one third the cost of steam.
The recovery mechanisms are more complex for SAGDOX than for SAGD. The combustion zone is contained within the steam-swept zone 170. Residual bitumen, in the steam-swept zone 170, is heated, fractionated and pyrolyzed by hot combustion gases to produce coke that is the actual fuel for combustion. A gas chamber is formed containing steam combustion gases, vaporized connate water, and other gases (
Combustion non-condensable gases are collected and removed by vent gas 22 wells or at segregated vent gas sites (
Because SAGDOX delivers both steam and oxygen energy and oxygen gas has 10 times the energy density as steam, pipe/tubing sizes for SAGDOX can be smaller (and less costly) than SAGD or other steam EOR processes. This can also reflect on production well sizes because reduced steam injection (with SAGDOX) results in less water production compared to SAGD.
Table 4 shows calculated pipe diameters for various SAGD and SAGDOX streams. Design criteria are presented in the table. When fluids use concentric pipe systems and annular flow, the total size of the combined pipe is indicated by brackets.
Often pipe costs are proportional to the diameter of the pipe. The total of pipe diameters can also be proportional to total costs. Table 4 shows total pipe diameters can be reduced by using SAGDOX and related processes.
Cumulative SAGDOX pipe diameters are 82% of SAGD for the case studied (35% oxygen in gas mix). THSAGDOX cumulative pipe diameters are 59% of SAGD, and SWSAGDOX cumulative diameter is only 42% of SAGD.
Preferred parameters in SAGDOX geometries include:
(1) Use Oxygen (rather than air) as the oxidant injected
Aside from the above benefits accruing to SAGDOX processes, compared to SAGD extended reach (>800 metre horizontal well length) SAGDOX has the following benefits/motivations:
There are 3 versions of SAGDOX for extended reach wells:
THSAGDOX (Toe-to-Heel SAGDOX) retains the horizontal production well 4, but replaces the horizontal steam injector with vertical steam and oxygen injector(s).
The vertical oxygen and steam injector well is designed to segregate steam 6 and oxygen 26 to minimize corrosion; inject oxygen 26 near the top of the pay zone; and to inject steam 6 lower in the pay zone (
The THSAGDOX process is started by circulating steam in the horizontal production well 4 and by injecting or cycling steam 6 (huff-and-puff) in the vertical well(s) until the wells communicate (i.e. fluids can flow between wells). After communication is established, wells are converted to THSAGDOX operation, with similar operation controls to SAGDOX.
Hydraulic constraints for THSAGDOX are also less restrictive than SAGD. For SAGD, production rates are constrained so that pressure drops in the production well are less than the hydrostatic head between injector and producer (about 8 psi). For the same well size as SAGD, the THSAGDOX well can be much longer because, per unit bitumen produced, there is less water, so total liquid volumes for THSAGDOX are less than SAGD for the same bitumen production. When the well length is extended, THSAGDOX bitumen productivity can exceed SAGD productivity for the same hydraulic constraints.
Table 3 shows why THSAGDOX (or SAGDOX) processes can have longer horizontal wells than SAGD, using the same hydraulic limit criteria in the production well. For the same Energy to Oil Ratio (MMBTU/bbl) (“ETOR”) design and the same bitumen production rates, fluid volume rates in the horizontal production well are reduced by a factor of about three as oxygen levels in the injectant gases (steam+oxygen) are increased (to a limit of 50 (v/v) percent oxygen in the steam+oxygen mix).
But, the typical well length for THSAGDOX can be extended even further if a tubing string is used to move the liquid draw down point to near the toe of the horizontal well (
THSAGDOX also lends itself to extended-reach applications (ER-THSAGDOX) using multiple vertical injector wells (steam+oxygen) and vertical vent gas removal wells (
The second option for extended length wells is the SWSAGDOX process. SWSAGDOX contains all injection and production streams for SAGDOX within a single horizontal well bore (
Portions of the well are segregated for steam 6 and oxygen injection 26 and for bitumen, water 8, and vent gas 22 production using concentric tubing and segregation packers (
The simplest version of SWSAGDOX is shown in
An alternative embodiment to SWSAGDOX, as shown in
Yet another alternative SWSAGDOX embodiment is show in
Another alternative embodiment is to complete the horizontal well using a corrosion resistant material, at least for the toe section of the well.
SWSAGDOX has the following features:
With SWSAGDOX, hydraulic limitations need to be addressed. Such as if the steam+oxygen section is flat and if we operate the process so that liquid covers the production section to obviate steam+oxygen breakthrough, the end of the horizontal well will be flooded. This will inhibit steam+oxygen injection and harm conformance. If we produce liquid at a faster rate to remove this problem, the entire production section will be open to steam and oxygen breakthrough.
The solution shown in
On the other hand, SWSAGDOX(U) doesn't get the double hydraulic limit advantage that THSAGDOX achieves because it is not practical to move the drawdown point for liquid production to near the toe section.
The following provide differences between several geometries.
To summarize, ERSAGDOX characteristics include the following:
As many changes therefore may be made to the embodiments of the invention without departing from the scope thereof. It is considered that all matter contained herein be considered illustrative of the invention and not in a limiting sense.
Number | Date | Country | |
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61734626 | Dec 2012 | US | |
61507196 | Jul 2011 | US | |
61549770 | Oct 2011 | US |
Number | Date | Country | |
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Parent | 13543012 | Jul 2012 | US |
Child | 14099472 | US | |
Parent | 13628164 | Sep 2012 | US |
Child | 13543012 | US |