STEAM ASSISTED GRAVITY DRAINAGE WITH ADDED OXYGEN ("SAGDOX") IN DEEP RESERVOIRS
A process to recover hydrocarbons, from a hydrocarbon reservoir having a bottom, using a substantially horizontal production well, the substantially horizontal production well having a toe and a heel, the process including: (a) injecting oxygen into the hydrocarbon reservoir, the horizontal production well having at least one perforation zone for contact with the reservoir; (b) injecting steam into the hydrocarbon reservoir; the oxygen producing in situ heat and in situ carbon dioxide by combustion and the steam producing in situ heat by conduction and condensation; the in situ carbon dioxide dissolving into the liquid hydrocarbon, lowering its viscosity; (c) recovering the reservoir liquid hydrocarbons of lowered viscosity using the substantially horizontal production well; and (d) optionally conveying the recovered liquid hydrocarbons to the surface; where the process is absent a removal step of any non-condensable gas from the reservoir.
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Steam Assisted Gravity Drainage (SAGD) is a commercial, thermal enhanced oil recovery (“EOR”) process. The SAGD process uses saturated steam injected into a horizontal well, where latent heat is used to heat bitumen in the reservoir. The heating of the bitumen lowers its viscosity, so it drains by gravity to an underlying parallel, twin, horizontal well completed near the reservoir bottom.
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 10 forms around the injection 2 and production wells 4 where the void space is occupied by steam 6. Steam 6 condenses at the boundaries of the chamber 10, releases latent heat (heat of condensation), and heats bitumen, connate water and the reservoir matrix. Heated bitumen and water 8 drain by gravity to the lower production well 4. The steam chamber 10 grows upward and outward as bitumen is drained.
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 P, T range of most SAGD projects (
The operational performance of SAGD can be characterized by measurement of the following parameters: 1) saturated steam P, T in the steam chamber (
During the SAGD process, the SAGD operator has two choices to make: 1) the sub-cool target T difference and 2) the operating pressure in the reservoir. A typical sub-cool 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 (
Bitumen viscosity is a strong function of temperature (
Despite becoming the dominant thermal EOR process, SAGD has some limitations and detractions. The requirements for a good SAGD project are:
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- a horizontal well completed near the bottom of the pay zone to effectively collect and produce hot draining fluids.
- the injected steam, at the sand face, has a high quality (latent heat drives the process).
- the process start up is effective and expedient.
- the steam chamber grows smoothly and is contained.
- the reservoir matrix is good quality (porosity (φ)>0.2);
- Initial Oil Saturation (Sio)>0.6; Vertical permeability (kv)>2D).
- net pay is sufficient (>15 metres).
- proper design and control must achieved to simultaneously; 1) prevent steam breakthrough to the production well and injector flooding; 2) stimulate steam chamber growth to productive zones; and 3) inhibit water inflows to the steam chamber.
- there must be absence of significant reservoir baffles or barriers.
If these conditions are not attained or other limitations are experienced, SAGD can be impaired, as follows:
(1) The preferred dominant production mechanism is gravity drainage, and the lower production well is horizontal. If the reservoir is slanted, a horizontal production well will strand significant resources.
(2) The SAGD steam-swept zone has significant residual bitumen content that is not recovered, particularly for heavier bitumens and low pressure steam (
(3) To contain a SAGD steam chamber, the oil in the reservoir must be relatively immobile. SAGD cannot work on heavy (or light) oils with some mobility at reservoir conditions. Bitumen is the preferred target.
(4) Saturated steam cannot vaporize connate water. By definition, the heat energy in saturated steam is not high enough quality (temperature) to vaporize water. Field experience also shows that heated connate water is not usually mobilized sufficiently to be produced in SAGD. Produced Water-to-Oil Ratio (“PWOR”) is similar to SOR. This makes it difficult for SAGD to breach or utilize lean zone resources.
(5) The existence of an active water zone—either top water, bottom water or an interspersed lean zone within the pay zone—can cause operational difficulties or project failures for SAGD (Nexen Inc., “Second Quarter Results”, Aug. 4, 2011) (Vanderklippe, N., “Long Lake Project Hits Sticky Patch”, CTV News, 2011). Simulation studies concluded that increasing production well standoff distances can optimize SAGD performance with active bottom waters, including good pressure control to minimize water influx (Akram, F., “Reservoir Simulation Optimizes SAGD, American Oil and Gas Reporter, September 2010).
(6) Pressure targets cannot (always) be increased to improve SAGD productivity and SAGD economics. If the reservoir is “leaky”, as pressure is increased beyond native or hydrostatic pressures, the SAGD process can lose water or steam to zones outside the SAGD steam chamber. If fluids are lost, the Water Recycle Ratio (WRR) decreases, and the process requires significant water make-up volumes. If steam is also lost, process efficiency drops and SOR increases. Ultimately, if pressures are too high, if the reservoir is shallow, and if the high pressure is retained for too long, a surface breakthrough of steam, sand, and water can occur (Roche, P., “Beyond Steam”, New Tech. Mag., September 2011).
(7) Steam costs are considerable. If steam “costs” are over-the-fence for a utility including capital charges and some profits, the costs for high-quality steam at the sand face is about $10 to 15/MMBTU. High steam costs can reflect on resource quality limits and on ultimate recovery factors.
(8) Water use is significant. Assuming SOR=3, WRR=1, and a 90% yield of produced water treatment (i.e. recycle), a typical SAGD water use is 0.3 barrels (bbls) of make-up water per barrel (bbl) of bitumen produced.
(9) SAGD process efficiency is poor, and CO2 emissions are significant. If SAGD efficiency is defined as [(bitumen energy)−(surface energy used)]/(bitumen energy), where 1) bitumen energy=6 MMBTU/bbl; 2) energy used at sand face=1 MMBTU/bbl bitumen (SOR ˜3); 3) steam is produced in a gas-fired boiler at 85% efficiency; 4) there are heat losses of 10% each in distribution to the well head and delivery from the well head to the sand face; 5) usable steam energy is 1000 BTU/lb (
(10) Practical steam distribution distance is limited to about 10 to 15 km (6 to 9 miles), due to heat losses, pressure losses, and the cost of insulated distribution steam pipes (Finan, A., “Integration of Nuclear Power . . . ”, MIT thesis, June 2007), (Energy Alberta Corp., “Nuclear Energy . . . ”, Canada Heavy Oil Association, pres., Nov. 2, 2006).
(11) Lastly, there is a natural hydraulic limit that restricts well lengths or well diameters and can override pressure targets for SAGD operations.
In some cases, for deeper bitumen reservoirs, SAGD has the following issues:
(1) Hydrostatic and native reservoir pressures increase. The critical pressure for water/steam is 218 atm (3208 psia, 22 MPa (Table 3)). This corresponds (at 0.5 psi/ft hydrostatic gradient) to a hydrostatic depth of about 6416 feet or 1955 metres. Beyond this depth, a steam EOR process, at hydrostatic pressure, would need to use supercritical steam (
(2) Because SAGD produced fluids, including water, are near saturated steam temperature, the SAGD process operates by delivering (net) latent heat to the reservoir.
(3) Not only is more steam required as depth increases, but as pressure increases, the cost of steam generation and water treatment increases significantly (Smith (2005)).
(4) Heat losses in the vertical well bore section of the wells also increase significantly for two reasons—1) the pipe length and residence time of steam is increased and 2) steam temperature is increased. Vertical well bore heat losses can be a strong function of steam temperature (Radiation losses are proportional to T4).
(5) Capital expense (“Capex”) increases because the wells are longer, unit steam demand is increased, and steam/water capex increases with pressure.
(6) Operating expense (“Opex”) increases because SAGD efficiency drops, heat losses increase, and steam/water opex increases with pressure.
Other steam EOR processes (e.g. ISC SF, CSS . . . ) that don't rely totally on latent heat transfer can still work in reservoirs of increasing depth. But heat transfer via conduction and bitumen flow by flooding is slower and/or less efficient than steam condensation and/or gravity drainage.
For deep (>500 metres) heavy oil or bitumen resources where thermal EOR is the preferred recovery process and steam EOR is the perceived preferred process choice, heat losses from steam injection tubing have been a serious, long-time issue. The issue is complex with the following highlights:
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- (1) The traditional steam injection geometry is the use of centralized tubing to inject steam into the reservoir. Injection down the annulus has significantly higher heat losses. Heat losses from the tubing to the annular fluid to the casing and through the casing to the overburden can be significant. Heat losses can amount to over 20% for steady-state design conditions and much worse for non-design operations such as start-up (Herrera, J. O. et al, “Wellbore Heat Losses in Deep Steam Injection Wells,” The Society of Petroleum Engineers Regional Mtg., Apr. 12, 1978),
- (2) Prior to start-up, for a simple completion without a packer, the annulus contains water. If saturated steam is injected, some steam condenses to provide for heat losses. But, as long as some steam survives at bottom hole, the saturated steam temperature remains constant. Currently there is no down hole instrument that can measure steam quality, so the operator cannot determine heat loss by simple down hole measurements (Satter, A. “Heat Losses during Flow of Steam Down a Wellbore,” The Journal of Petroleum Technology, July 1965). Water in the annulus is vaporized (contributing to slow start-up), so that most of the annulus will be filled with steam.
- (3) Heat transfer for heat loss in this simple system is due to conduction, convection, and radiation from the outside of the steam tubular to the casing wall. Considering these mechanisms, early analysis showed that heat losses were dominated by radiation (Huygen, H. A. et al. “Wellbore Heat Losses and Leasing Temperatures during Steam Injection,” APRI meeting April 1966). Since radiative losses are proportional to surface area, larger sized steam tubing increases heat losses. Also at lower steam flows, fractional heat losses increase because of increased residence times. Radiation is a strong function of temperature (˜T4), so heat losses also increase with increased steam temperature and pressure.
- (4) A simple solution to reduce heat losses was to paint the outside of the steam tubular with a low emissivity paint, such as aluminum paint (Huygen (1966)) (Pacheco, E. F et al. “Wellbore Heat Losses and Pressure Drop in Steam Injection,” The Journal of Petroleum Technology Feb. 12, 1972).
- (5) This can reduce radiative heat losses by about a factor of two, but, unless the paint is applied in situ, it can easily be scraped off during installation and reduce the effectiveness considerably (Huygen (1966)) (Pacheco (1972)).
- (6) Another way to reduce heat losses is to place a thermal packer downhole to isolate the annulus and steam tubulars. The packer can prevent steam from entering the annulus. Packers are best for cyclic steam processes (CSS) where the packer can reduce casing temperature increases and reduce the chance of casing failure. But, thermal packers are expensive and are known to leak (Satter, A. “Heat Losses During Flow of Steam Down a Wellbore,” Journal of Petroleum Technology July 1965) (Willhite, G. P. et al. “Wellbore Refluxing in Steam Injection Wells,” The Journal of Petroleum Technology March 1987).
- (7) The simplest and most direct way to reduce heat losses is to insulate steam tubulars on the outside, reducing conduction losses and radiation heat losses. It has been shown that insulation can reduce heat losses by about ⅔ considering simple conduction, convection, and radiation mechanisms (Huygen (1966)). However, insulation is expensive. It may be difficult to install. Also, it can be ineffective if it is wet.
- (8) So far, heat losses due to steam reflux in the annulus have been ignored, although this mechanism has been shown to be important (Willhite (1987)) (Satter (1964)). If steam is in the annulus, it can condense on casing walls, thus releasing latent heat as well as running downward by gravity until it finds a hot spot where it is re-vaporized. Hot spots can be uninsulated (or poorly insulated) gaps, couplings, and collars (etc.) in contact with the steam tubular. This reflux mechanism can cause heat losses three to six times higher than anticipated if only conduction, convection, and radiation are considered (Willhite (1987)).
- (9) A potential solution to reduce reflux heat losses is to install a packer to isolate steam tubulars from the annulus and to fill the annulus with a (pressurized) gas (e.g. nitrogen) that has low heat conductivity. The purpose of the gas is to have a lower heat transfer than steam and to keep steam out of the annulus. But, packers have some leakage, and field experience shows that the annulus did not dry out for such systems. Water continued to reflux in the annulus (Willhite (1987)).
- (10) A potential further solution is to continuously inject inert gas (e.g. nitrogen) into the annulus, with or without a packer or insulated tubing, to dry out the annulus. This can minimize annular water reflux heat losses and dry out insulation (if used).
Carbon dioxide (“CO2”) is the primary non-condensable gas product of in situ combustion (excluding inert N2 in air). CO2 is partially soluble in reservoir fluids (oil and water). Deep heavy oil reservoirs have higher native pressures than shallow resources. For example, a 2000-metre deep reservoir has a hydrostatic pressure of about 3280 psi (22.5 MPa), while a 200-metre deep reservoir has a hydrostatic pressure of only 328 psi (2.3 MPa).
CO2 solubility in reservoir fluids is not an important issue for shallow resources. But, increased pressure can significantly increase the impact of dissolved gases on thermal EOR processes. Solubility behaviour is not necessarily intuitive for dissolution into water. The normal expectation is that gas solubility in fluids (e.g. water) drops as temperature increase (
CO2 is also soluble in oil and dissolved CO2 can significantly reduce oil viscosity to improve oil mobility.
As discussed above, CO2 dissolved in oil has the added benefit of reducing oil viscosity (
The combination of CO2+steam for thermal EOR has also been evaluated using simulation models for CSS EOR (Balog (1982)). A mixture of 7% (v/v) CO2 in steam was injected in a CSS process using a simulator and a Cold Lake Alberta reservoir. Compared to steam alone, the CO2 increment increased bitumen productivity by 35%, and after 3 cumulative cycles, bitumen production increased by over 50%. Further, reservoir CO2 inventory was established equal to about 2 MSCF/bbl bitumen produced. The inventory could either be blown down at project end or sequestered. (
The current invention involves application and simplification of the SAGDOX process applied to deep, high-pressure bitumen reservoirs. Shallow (<500 metres) average depth reservoirs employing SAGDOX processes require separate removal of non-condensable combustion gases (mostly CO2) using vent gas wells or segregated vent gas sites. But, for deep reservoirs, preferably having a depth average greater than about 500 metres in depth from surface level, the non-condensable vent gas generated by the SAGDOX process may be left to dissolve in the reservoir or production fluids, so that separate (non-condensable) gas removal is not necessary. In addition, CO2 dissolution in bitumen can reduce viscosity and increase bitumen productivity.
According to one aspect, there is provided a process to recover hydrocarbons, from a hydrocarbon reservoir having a bottom, using a substantially horizontal production well, preferably said substantially horizontal production well has a toe and a heel, said process comprising:
- (1) injecting oxygen into said hydrocarbon reservoir, said horizontal production well having at least one perforation zone, for contact with said reservoir;
- (2) injecting steam into said hydrocarbon reservoir;
said oxygen producing in situ heat and in situ carbon dioxide by combustion and said steam producing in situ heat by conduction and condensation; said in situ carbon dioxide dissolving into the liquid hydrocarbon, lowering its viscosity; - (3) recovering said reservoir liquid hydrocarbon using said substantially horizontal production well; and
- (4) optionally conveying said recovered liquid hydrocarbon to the surface; wherein said process is absent a removal step of any non-condensable gas from said reservoir.
In one embodiment, said hydrocarbon reservoir comprises at least one characteristic selected from the group consisting of:
i) an average depth greater than about 500 metres;
ii) an average pressure greater than about 800 psia, and combinations thereof.
According to another aspect, there is provided a process to recover liquid hydrocarbons, from a hydrocarbon reservoir, using a horizontal production well, wherein:
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- (1) the horizontal production well is used to produce water and liquid hydrocarbons and is completed within 2 metres of the reservoir bottom;
- (2) oxygen gas is injected into the hydrocarbon reservoir within 50 metres from the horizontal production well and with a perforation (reservoir contact) zone less than 50 metres in length;
- (3) steam is injected within 20 metres from the horizontal production well;
- (4) the oxygen gas produces in situ heat and in situ carbon dioxide by combustion and steam produces in situ heat by conduction and by condensation;
- (5) carbon dioxide dissolves into the reservoir hydrocarbon, lowering its viscosity;
- (6) in situ heat causes the liquid hydrocarbon to be heated, also lowering its viscosity;
- (7) the lower-viscosity reservoir liquid hydrocarbon drains by gravity to the horizontal production well where it is conveyed (or pumped) to the surface; and
- (8) the process pressure (in the reservoir) is greater than 800 psia.
In one embodiment, the oxygen to steam injected is controlled so that produced water to oil (v/v liquid) has a ratio greater than 0.5, preferably the ratio of produced water to oil (v/v liquid) is between 0.5 and 2.0.
In another embodiment, the hydrocarbon reservoir is positioned at least 500 metres below the ground surface.
In another embodiment, said steam is injected within 10 metres from the horizontal well, preferably said steam is injected using a parallel horizontal well in the same vertical plane as the horizontal production well and located about 3 metres to 8 metres above the well, more preferably said steam is injected into the reservoir using at least one substantially vertical well selected from the group consisting of a single well or a plurality of substantially vertical wells.
In one embodiment, said oxygen is injected into the reservoir using at least one well selected from the group consisting of a single substantially vertical well or a plurality of substantially vertical wells.
In one embodiment, said steam and oxygen are comingled on the surface and injected into the reservoir.
In another embodiment, said steam and oxygen are segregated, preferably using packers, and injected separately into the reservoir, preferably said steam and oxygen are segregated using concentric tubing and packers with steam in a central tubing of said concentric tubing surrounded by oxygen in an adjacent annulus and said oxygen is injected at a higher elevation of said steam injected into the reservoir.
In yet another embodiment, said steam and oxygen are injected into said reservoir using a single substantially vertical well, wherein said single substantially vertical well is completed within 50 metres from the toe of the horizontal production well.
According to one of the embodiments of the invention the pressures of the process are sufficient so that substantially no free CO2 is produced in the liquid production well. More preferably, the operating in situ pressure and the ratio of oxygen/steam (v/v) are adjusted so there is substantially no free CO2 gas found in the horizontal section of the horizontal production well.
These and other benefits of the invention will be apparent from the review of the illustrations, descriptions and the claims of the invention.
FIG. 25A,B,C depicts SWSAGDOX piping schemes using centralized packers.
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 1 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 (Table 1), 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 5 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 5 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
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- If the cost of treating vent gas to remove sulphur components and to recover volatile hydrocarbons is factored in, even at low pressures the all-in cost of oxygen is less than the cost of compressed air, per unit energy delivered to the reservoir.
- Oxygen occupies about one fifth the volume compared to air for the same energy delivery. Well pipes/tubing is smaller and oxygen can be transported further distances from a central plant site.
- In situ combustion (ISC) using oxygen produces mostly non-condensable CO2, undiluted with nitrogen. CO2 can dissolve in bitumen to improve productivity. Dissolution is maximized using oxygen.
- Vent gas, using oxygen, is mostly CO2 and may be used for sequestration.
- There is a minimum oxygen flux to sustain HTO combustion (
FIG. 23 ) - It is easier to attain/sustain this flux using oxygen
(2) Keep oxygen injection at a concentrated site - Because of the minimum O2 flux constraint from in situ combustion (
FIG. 23 ), the oxygen injection well (or a segregated section) should have no more than 50 metres of contact with the reservoir
(3) Segregate Oxygen and steam injectants, as much as possible - Condensed steam (hot water) and oxygen are very corrosive to carbon steel.
- To minimize corrosion, either 1) oxygen 26 and steam 6 are injected separately (
FIGS. 30 , 31, and 32) 25); 2) comingled steam 6 and oxygen 26 have limited exposure to a section of pipe that can be a corrosion resistant alloy; 3) the section integrity is not critical to the process (FIG. 25( a)); or 4) the entire injection string is a corrosion resistant alloy (FIG. 25( a)).
(4) The vent gas well (or site) is near the top of the reservoir, far from the oxygen injection site - Because of steam movement and condensation, non-condensable gas concentrates near the top of the gas chamber.
- The vent gas well should be far from the oxygen injector to allow time/space for combustion.
(5) Vent gas should not be produced with significant oxygen content - To mitigate explosions and to foster good oxygen utilization, any vent gas production with oxygen content greater than 5% (v/v) should be shut in.
(6) Attain/retain a minimum amount of steam in the reservoir - Steam is added/injected with oxygen in SAGDOX because steam helps combustion. It preheats the reservoir so ignition, for HTO, can be spontaneous. It adds OH− and H+ radicals the combustion zone to improve and stabilize combustion (
FIGS. 26 and 27 , Moore (1994)). This is also confirmed by the operation of smokeless flares, where steam is added to improve combustion and reduce smoke (Stone (2012), EPA (2012), Shore (1996)). The process to gasify fuel also adds steam to the partial combustor to minimize soot production (Berkowitz (1997)). - Steam also condenses and produces water that “covers” the horizontal production well and isolates it from gas or steam intrusion.
- Steam condensate adds water to the production well to improve flow performance—water/bitumen emulsions—compared to bitumen alone.
- Steam is also a superior heat transfer agent in the reservoir. When one compares hot combustion gases (mostly CO2) to steam, the heat transfer advantages of steam are evident. For example, if one has a hot gas chamber at about 200° C. at the edges, the heat available from cooling combustion gases from 500° C. to 200° C. is about 16 BTU/SCF. The same volume of saturated steam contains 39 BTU/SCF of latent heat—more than twice the energy content of combustion gases. In addition, when hot combustion gases cool, they become effective insulators impeding further heat transfer. When steam condenses to deliver latent heat, it creates a transient low-pressure that draws in more steam—a heat pump, without the plumbing. The kinetics also favour steam/water. The heat conductivity of combustion gas is about 0.31 (mW/cmK) compared to the heat conductivity of water of about 6.8 (mW/cmK)—a factor of 20 higher. As a result of these factors, combustion (without steam) has issues of slow heat transfer and poor lateral growth. These issues may be mitigated by steam injection.
- Since one can't measure the amount of steam in the reservoir, SAGDOX sets a steam minimum by a maximum oxygen/steam (v/v) ratio of 1.0 or alternately 50% (v/v) oxygen in the steam and oxygen mix.
(7) Attain (or exceed) a minimum oxygen injection - Below about 5% (v/v) oxygen in the steam and oxygen mix, the combustion swept zone is small and the cost advantages of oxygen are minimal. At this level, only about a third of the energy injected is due to combustion.
(8) Maximum oxygen injection - Within the constraints of (6) and (7) above, because per unit energy oxygen is less costly than steam, the lowest-cost option to produce bitumen is to maximize oxygen/steam ratios.
(9) Use preferred SAGDOX geometries - Depending on the individual application, reservoir matrix properties, reservoir fluid properties, depth, net pay, pressure and location factors, there are three preferred geometries for SAGDOX (
FIG. 28 a-c). FIGS. 28 b (THSAGDOX) and 28c (SWSAGDOX) are most preferred for thinner pay resources, with only one horizontal well required. Compared to SAGD, THSAGDOX and SWSAGDOX have a reduced well count and lower drilling costs. Also, internal tubulars and packers should be usable for multiple applications.
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- Sub-cool control on fluid production rates where produced fluid temperature is compared to saturated steam temperature at reservoir pressure. This assumes that gases, immediately above the liquid/gas interface, are predominantly steam.
- Adjust oxygen/steam ratios (v/v) to meet a target ratio, subject to a range limit of 0.05 to 1.00.
- Adjust vent gas removal rates so that the gases are predominantly non-condensable gases, oxygen content is less than 5.0% (v/v), and to attain/maintain pressure targets.
- Adjust steam and oxygen injection rates (subject to (ii) above), along with (iii) above, to attain/maintain pressure targets.
Preferred parameters in SAGDOX for deep reservoirs include the following:
1. Increased PressuresFor shallow reservoirs, because of the risk of fluid losses and the risk of surface blowouts, thermal EOR processes operate close to native reservoir pressures (Roche (2011). As reservoirs become deeper, there is less risk of surface blowouts, but fluid losses can still be an issue.
At a 0.5 psi/ft hydrostatic gradient, shallow reservoirs (200-300 m depth) have hydrostatic pressures of 330 to 490 psia (2.5 to 3.4 MPa). For deep reservoirs (500-2000 metres), hydrostatic pressures are much higher (820 to 3280 psia, 5.6 to 22.5 MPa).
If saturated steam is used (or is a component) and latent heat delivery is important (i.e. SAGD), there is an efficiency loss as pressure is increased (
For SAGDOX, a mixture of steam 6 and oxygen 26 gas is injected (
Carbon dioxide is produced as a result of in situ combustion. If oxygen gas is used, CO2/O2 ratios varying from about 0.85 to 0.96 are expected, depending on the fuel consumed and the reaction stoichiometry (Table 4). Some carbon monoxide may form, but it is likely to be converted to CO2 in the reservoir (
CO2 will dissolve into bitumen to reduce its viscosity and increase bitumen productivity. By itself at high pressures (˜2000 psia), CO2 can reduce bitumen (heavy oil) viscosity by about an order of magnitude (
High operating pressures can drive gases (non-condensable gases) into solution in reservoir fluids (bitumen and water). Let's assume we use 1 MMBTU of combustion energy per bbl bitumen produced. Per MMBTU of combustion energy injected into the reservoir, 2083 SCF of oxygen is injected, and 1910 SCF CO2 (in the worst case assuming a fuel consumed as CH0.5 (Table 4)) is produced. If assume that produced fluids have a WOR=1.5 with some steam injection and some connate water production, CO2 solubility in produced hot water is expected to be about 160 SCF/bbl hot water (
Based on the above example, no free CO2 gas will be produced in the horizontal section of the production well. If free CO2 gas is produced and if it is deemed harmful to the process, gas production can be reduced/eliminated by increasing SAGDOX reservoir pressures or by reducing O2/steam ratios, eliminating the need for infrastructure venting non-condensable gases, in particular for venting CO2 gas.
4. Heat LossesAs depth increases and saturated steam temperatures increase, heat losses from the vertical well sections to the overburden increase. As previously discussed, the optimum design to minimize heat losses, in this section, is to insulate the central steam injector with an annulus of continuously injected gas. For SAGDOX, this gas is oxygen, and the preferred designs are shown in
The combustion of in situ residual hydrocarbons and oxygen can produce a mixture of CO2 and CO non-condensable gases (Table 4). Combustion tests (
Nonetheless, the worst case CO production is about 140 SCF/MMBTU (Table 4). Assume CO solubility in water is similar to N2 (
In any case, undissolved CO should either be controllable or should not build up to levels that inhibit injectivity.
6. Deep SAGDOX GeometryBecause CO2 need not be removed using separate vent wells or a segregated well section, the preferred geometry for deep SAGDOX processes can be simplified to three preferred cases:
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- the basic SAGDOX process with twin horizontal wells 2,4 can be simplified by removing the vent gas 22 annulus in
FIG. 31 . - similarly, the THSAGDOX version is also simplified as shown in
FIG. 33 - the SWSAGDOX version is also simplified as shown in
FIG. 34 .
- the basic SAGDOX process with twin horizontal wells 2,4 can be simplified by removing the vent gas 22 annulus in
Some of the differences between the prior art SAGDOX and the SAGDOX for deep reservoirs include:
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- SAGDOX has at least one vent gas well to remove non-condensable combustion gases; SAGDOX for deep reservoirs does not require same;
- The target is deep, high pressure reservoirs (>500 m average depth or >800 psia average pressure); and
- Non-condensable gas, preferably CO2 is dissolved in bitumen; SAGDOX prefers venting of said gas.
Even further, SAGDOX for deep reservoirs allows for the following:
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- no vent wells required to remove non-condensable combustion gases;
- pressure and oxygen/steam ratios can be adjusted, allowing for CO2 being substantially dissolved in reservoir fluids
- hydrocarbon recovery from deep reservoirs (>500 m average depth from surface)
- hydrocarbon recovery from reservoirs with average pressure (>800 psia)
- use of oxygen gas to insulate steam injector
- two examples of preferred geometries as illustrated in
FIGS. 33 and 34
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.
Claims
1. A process to recover hydrocarbons, from a hydrocarbon reservoir having a bottom, using a substantially horizontal production well, said substantially horizontal production well having a toe and a heel, said process comprising:
- (a) injecting oxygen into said hydrocarbon reservoir, said horizontal production well having at least one perforation zone for contact with said reservoir;
- (b) injecting steam into said hydrocarbon reservoir; said oxygen producing in situ heat and in situ carbon dioxide by combustion and said steam producing in situ heat by conduction and condensation; said in situ carbon dioxide dissolving into the liquid hydrocarbon, lowering its viscosity;
- (c) recovering said reservoir liquid hydrocarbons of lowered viscosity using said substantially horizontal production well; and
- (d) optionally conveying said recovered liquid hydrocarbons to the surface; wherein said process is absent a removal step of any non-condensable gas from said reservoir.
2. The process of claim 2 wherein said hydrocarbon reservoir comprises at least one characteristic selected from the group consisting of:
- (a) an average depth greater than about 500 metres;
- (b) an average pressure greater than about 800 psia, and combinations thereof.
3. A process to recover liquid hydrocarbons, from a hydrocarbon reservoir having a bottom, using a horizontal production well, comprising:
- (a) Completing the horizontal production well within 2 metres of the reservoir bottom;
- (b) injecting oxygen gas into the hydrocarbon reservoir within 50 metres from the horizontal production well and with a perforation (reservoir contact) zone less than 50 metres in length;
- (c) injecting steam within 20 metres from the horizontal production well;
- (d) the oxygen gas producing in situ heat and in situ carbon dioxide by combustion and the steam producing in situ heat by conduction and by condensation;
- (e) said carbon dioxide dissolving into the reservoir hydrocarbon, lowering its viscosity;
- (f) in situ heat causing the liquid hydrocarbon to be heated, also lowering its viscosity;
- (g) the lower-viscosity reservoir liquid hydrocarbon draining by gravity to the horizontal production well where it is conveyed (or pumped) to the surface; and
- (h) the process pressure (in the reservoir) is greater than 800 psia.
4. A process according to claim 1 or 3, wherein oxygen to steam injected is controlled so that produced water to oil (v/v liquid) has a ratio greater than 0.5.
5. A process according to claim 4, wherein the ratio of produced water to oil (v/v liquid) is between 0.5 and 2.0.
6. A process according to claim 3, wherein said hydrocarbon reservoir is positioned at least 500 metres below a ground surface.
7. A process according to claim 3, wherein steam is injected within 10 metres from the horizontal production well.
8. A process according to claim 1 or 7, wherein steam is injected using a substantially parallel horizontal well to the horizontal production well and located about 3 metres to 8 metres above the horizontal production well.
9. A process according to claim 1 or 7, wherein steam is injected into the reservoir using at least one well selected from the group consisting of a single substantially vertical well or a plurality of substantially vertical wells.
10. A process according to claim 1, wherein the oxygen is injected into the reservoir using at least one well selected from the group consisting of a single substantially vertical well or a plurality of substantially vertical wells.
11. A process according to claim 9, wherein steam and oxygen are comingled on the surface and injected into the reservoir.
12. A process according to claim 10, wherein steam and oxygen are segregated and injected separately into the reservoir.
13. A process according to claim 12 wherein said steam and oxygen are segregated using concentric tubing and packers with steam in a central tubing of said concentric tubing surrounded by oxygen in an adjacent annulus and said oxygen is injected at a higher elevation of said steam injected into the reservoir.
14. A process according to claim 13, wherein said steam and oxygen are injected into said reservoir using a single substantially vertical well, wherein said single substantially vertical well is completed within 50 metres from the toe of the horizontal production well.
15. A process according to claim 1 or 3 wherein said reservoir has a pressure such that substantially no free CO2 is produced in the production well.
16. A process according to claim 1 or 3 wherein said process has an operating in situ pressure and an oxygen/steam (v/v) ratio such that the substantially horizontal production well is substantially free of free CO2.
Type: Application
Filed: Dec 12, 2013
Publication Date: Apr 10, 2014
Applicant: NEXEN ENERGY ULC (Calgary)
Inventor: Richard Kelso Kerr (Calgary)
Application Number: 14/104,711
International Classification: E21B 43/24 (20060101);