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:
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:
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:
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:
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
Preferred parameters in SAGDOX for deep reservoirs include the following:
For 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.
As 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.
Because 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:
Some of the differences between the prior art SAGDOX and the SAGDOX for deep reservoirs include:
Even further, SAGDOX for deep reservoirs allows for 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.
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61737327 | Dec 2012 | US | |
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61549770 | Oct 2011 | US | |
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Parent | 13543012 | Jul 2012 | US |
Child | 14104711 | US | |
Parent | 13628164 | Sep 2012 | US |
Child | 13543012 | US | |
Parent | 14083106 | Nov 2013 | US |
Child | 13628164 | US |