US20140000876A1 - Sagd control in leaky reservoirs - Google Patents

Sagd control in leaky reservoirs Download PDF

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Publication number
US20140000876A1
US20140000876A1 US13/928,895 US201313928895A US2014000876A1 US 20140000876 A1 US20140000876 A1 US 20140000876A1 US 201313928895 A US201313928895 A US 201313928895A US 2014000876 A1 US2014000876 A1 US 2014000876A1
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sagd
reservoir
leaky
water
pressure
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Peter Yang
Richard Kelso Kerr
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CNOOC Petroleum North America ULC
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Nexen Inc
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B43/2406—Steam assisted gravity drainage [SAGD]
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B43/2406—Steam assisted gravity drainage [SAGD]
    • E21B43/2408—SAGD in combination with other methods
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E21B47/117—Detecting leaks, e.g. from tubing, by pressure testing

Definitions

  • SAGD Steam assisted gravity drainage
  • EOR thermal enhanced oil recovery
  • the oilsands are one of the world's largest hydrocarbon deposits.
  • SAGD has two parallel horizontal wells up to about 1000 m long, in a vertical plane, separated by about 5 m.
  • the upper steam injector is controlled by injection steam rate to attain a target pressure set by the operator (i.e. “pressure control”).
  • the lower bitumen and water producer is controlled by pumping rate (or other methods) to maintain a fluid temperature lower than saturated steam (sub-cool or steam-trap control) to ensure no live steam breaks through to the well.
  • the Athabasca bitumen resource in Alberta, Canada is one of the world's largest deposits of hydrocarbons. As describe above, a significant portion of the resource can be impaired by a water zone—causing the reservoir to be “leaky.” Also, The Athabasce bitumen resource in Alberta, Canada is unique for the following reasons:
  • SAGD is a delicate process. Temperatures and pressures are limited by saturated steam properties. Gravity drainage is driven by a pressure differential as low as 25 psia. Low temperatures (in a saturated steam process) and low pressure gradients make the SAGD process susceptible to impairments from reservoir inhomogeneities, as above.
  • This invention describes an alternate volume control method for SAGD steam injection in leaky reservoirs.
  • the technique involves using WRR (the water recycle ratio) as the key measurement and control parameter.
  • WRR is volume ratio (measured as water) of water produced to steam injected.
  • a use of water recycle ratio for controlling at least one SAGD parameter in a leaky bitumen reservoir is provided.
  • said parameter is selected from volume rate, pressure, temperature, and combinations thereof.
  • a process to control SAGD steam injection rate for an individual SAGD well pair in a leaky bitumen reservoir comprising replacing pressure control of said SAGD steam injection rate with volume control.
  • said leaky bitumen reservoir is determined by geological knowledge of an interspersed WLZ, top water or bottom water in a SAGD pattern volume, more preferably said leaky bitumen reservoir is determined by a cold water injection test prior to SAGD initiation, most preferably the reservoir is deemed leaky when WRR is measured and after 200 days of more of SAGD operation using pressure control for steam injection, and the WRR varies from 1.0 by more than 10 percent.
  • said process further comprises sub-cool control (steam-trap control) for liquids production (bitumen+water).
  • sub-cool control steam-trap control
  • liquids production bitumen+water
  • said volume rate control is instituted by injecting a pre-set target volume rate of steam into the SAGD injector well.
  • said volume rate control is instituted by
  • the target WRR is between 0.9 and 1.0
  • said process is applied to a leaky reservoir with a high-water-saturation zone in or adjacent to the bitumen pay zone, where the target WRR is set at between 1.0 and 1.5.
  • said leaky reservoir is caused by an interspersed water lean zone (WLZ) within the net pay zone.
  • WLZ interspersed water lean zone
  • said leaky reservoir is caused by a top water zone. And in yet another embodiment, said leaky reservoir is caused by a bottom water zone. In yet another embodiment, said leaky reservoir is caused by multiple factors comprising WLZ, top water and/or bottom water.
  • said bitumen is a hydrocarbon with ⁇ 10 API density and >100,000 cp viscosity, at native reservoir conditions.
  • SAGD pressure in the reservoir does not exceed the reservoir parting pressure, for unconsolidated reservoirs, or the reservoir fracturing pressure, for consolidated reservoirs.
  • the maximum SAGD pressure allowed is about 80 percent of the parting pressure and/or the fracturing pressure.
  • the minimum SAGD operating pressure is equal to the native reservoir pressure.
  • the bitumen reservoir is located in the Athabasca region of Alberta, Canada.
  • FIG. 1 depicts a typical SAGD Well Configuration
  • FIG. 2 depicts SAGD stages
  • FIG. 3 depicts Saturated Steam Properties
  • FIG. 4 depicts Bitumen and Heavy Oil Viscosities
  • FIG. 5 depicts SAGD Productivity per Well
  • FIG. 6 depicts SAGD Hydraulic Limits
  • FIG. 7 depicts Interspersed Bitumen Lean Zones
  • FIG. 8 depicts Top/Bottom Water: Oilsands
  • FIG. 9 depicts SAGD Simulation
  • FIG. 10 depicts WRR Performance for a Homogeneous Reservoir with Contained SAGD GD Chamber (Single well pair)
  • FIG. 11 depicts Bitumen Voidage and Steam Volumes
  • FIG. 12 depicts Well Pair Cross-Flow Model
  • FIG. 13 depicts SAGD performance Case 1
  • FIG. 14 depicts SAGD performance Case 2
  • FIG. 15 depicts SAGD performance Case 2(a)
  • FIG. 16 depicts SAGD performance Case 3
  • FIG. 17 depicts SAGD performance Case 4
  • FIG. 18 depicts SAGD performance Case 5
  • FIG. 19 depicts SAGD cumulative well pair performance of Cases 1-3
  • FIG. 20 depicts SAGD cumulative well pair performance of Cases 1, 4 and 5
  • FIG. 21 depicts SAGD dual well pair production/performance of Base Case and Case 2
  • FIG. 22 depicts SAGD pressure control performance of connected well pairs
  • FIG. 23 depicts SAGD WRR performance of connected well pairs Case 3
  • FIG. 24 depicts SAGD WRR performance of connected well pairs Case 1 and 3
  • FIG. 25 depicts bitumen production of individual well pair Case 3
  • FIG. 26 depicts bitumen production rates of two well pair of Base Case and Case 3
  • FIG. 27 depicts SOR Performance of Base Case and Case 3
  • FIG. 1 shows the basic SAGD geometry, using twin, parallel horizontal wells ( 2 , 4 ) (up to about 1000 m long) separated by about 2 to 8 m above the bottom of the bitumen zone (floor 8 ).
  • the upper well ( 2 ) is in the same vertical plane and injects saturated steam into the reservoir. The steam heats the bitumen and the reservoir matrix. As the interface between steam and cold bitumen moves outward and upward it creates a gas, gravity-drainage chamber ( FIG. 2 ).
  • the heated bitumen and condensed steam drain, by gravity, to the lower horizontal well ( 4 ) that produces the liquids.
  • the heated liquids (bitumen+water) are pumped (or conveyed) to the surface using ESP pumps or a gas-lift system.
  • FIG. 2 shows how SAGD matures.
  • a young steam chamber ( 1 ) has bitumen drainage from steep sides and from the chamber ceiling When the chamber grows ( 2 ) and hits the top of the net pay zone, drainage from the chamber ceiling stops and the slope of the side walls decreases as the chamber continues to grow outward. Bitumen productivity peaks at about 1000 bbls/d, when the chamber hits the top of the net pay zone and falls as the chamber grows outward ( 3 ), until eventually (10-20 years) the economic limit is reached.
  • the produced fluids are at/near saturated steam temperatures, it is only the latent heat of the steam that contributes to the process in the reservoir. It is important to ensure that steam is high quality as it is injected into the reservoir.
  • WRR water recycle ratio
  • SAGD operation in a good-quality reservoir, is straightforward.
  • Steam injection rate into the upper horizontal well and steam pressure are controlled by pressure targets chosen by the operator. If the pressure is below the target, steam pressure and injection rates are increased. The opposite is done if pressure is above the target.
  • Production rates from the lower horizontal well are controlled to achieve sub-cool targets in the average temperature of the production fluids.
  • the sub-cool is the difference in temperature of saturated steam and the actual temperature of produced liquids (bitumen+water).
  • Produced fluids are kept at a lower T than saturated steam to ensure that live steam doesn't get produced. 20° C. is a typical sub-cool target. This is also called steam-trap control.
  • the SAGD operator has two choices to make—the sub-cool target and the operating pressure of the process.
  • Sub-cool is safety issue, but operating pressure is more subtle and usually more important.
  • the higher the pressure the higher the temperature—linked by the properties of saturated steam ( FIG. 3 ).
  • Bitumen viscosity is a strong function of temperature ( FIG. 4 ).
  • the productivity of a SAGD well pair is proportional to the square root of the inverse bitumen viscosity (Butler (1991)). So the higher the pressure, the faster bitumen can be recovered—a key economic performance factor.
  • the SAGD operator usually opts to maximize economic returns, so the operator increases P and T as much as possible. Pressures are usually much greater than native reservoir P. A few operators have gone too far and exceeded parting pressure (fracture pressure) and caused a surface breakthrough of steam and sand (Roche, P., “Beyond Steam”, New Tech. Mag., September 2011). Bitumen productivity peaks at about 1000 bbl/d for the best reservoirs, but it can be significantly impaired for the poorer reservoirs ( FIG. 27 ).
  • SAGD SAGD
  • the hydrostatic head between the two SAGD wells ( 2 , 4 ) is about 8 psia (56 kPa).
  • the steam/liquid interface may be “tilted” and intersect the producer or injector well ( 2 , 4 ). If the producer ( 4 ) is intersected, steam can break through. If the injector ( 2 ) is intersected, it may be flooded and the effective injector length may be shortened. For current standard pipe sizes and a 5 m spacing between wells ( 2 , 4 ), SAGD well lengths are limited to about 1000 m.
  • the oil sands have a significant portion of the resource that is impaired by water lean zones (top water, bottom water, interspersed lean zones). These may cause the reservoir to be “leaky” with significant water influx or egress. Under these conditions, SAGD pressure control for steam injection does not work well. Pressure gradients need only be modest to transport large volumes of water and disrupt SAGD. It is hard to choose an appropriate pressure target or to accurately measure an appropriate pressure to minimize the harmful effects of a leaky reservoir.
  • Water Lean Zones (WLZ) with high water saturation may be at the top of the bitumen reservoir (top water), at the bottom (bottom water), or interspersed within the pay zone.
  • FIG. 7 depicts an interspersed WLZ 18 . When confronted with this situation, the following is observed:
  • bottom water zones 20 As best seen in FIG. 8 , the issues are similar to interspersed WLZ except that 1) bottom water underlies the bitumen and 2) the usual expectation is that bottom water is more active.
  • SAGD can operate at pressures greater than reservoir pressure as long as the following occurs: 1) pressure drops in the production well (due to flow/pumping) do not reduce local pressures below reservoir P and 2) the bottom of the reservoir, underneath the production well, is “sealed” by high-viscosity immobile bitumen (basement bitumen). As the process matures, basement bitumen will become heated by conduction from the production well. After a few years, this bitumen will become partially mobile and SAGD pressure will need to be reduced to match reservoir pressure.
  • SAGD pressures cannot be too high or a channel may form, (reverse cone) allowing communication with the bottom water.
  • SAGD steam pressures cannot be too low either or water will be drawn from the bottom water (cresting). If this occurs, water production will exceed steam injection. The higher the pressure drops in the production well, the more delicate the balance and the more difficult it is to achieve a balance.
  • the channel or crests can be partial and the onset of the problem is accelerated.
  • top water 22 (as best seen in FIG. 8 ), again, the issues are similar to interspersed WLZ and bottom water, with the expectation that top water is also an active water supply.
  • the problems are similar to bottom water, as above, except that SAGD wells are further away from top water. So, the initial period—when the process can be operated at higher pressures than reservoir pressure—can be extended compared to bottom water. The pressure drop in the production well is less of a concern because it is far away from the ceiling.
  • the first problem is likely to be steam breaching the top water interface. If the top water is active, water will flood the chamber and may shut the SAGD process down.
  • a cold water injectivity test is a way to potentially detect connections between SAGD wells and WLZ, top water and/or bottom water (Aherne, A. L. et al., “Fluid Movement in the SAGD Process: A Review of the Dover Project”, Can. Int'l Pet. Conf., Jun. 13, 2006).
  • the usual method of SAGD operations control for a homogeneous reservoir is to first choose an operating pressure, in excess of the native reservoir pressure P, to try to maximize bitumen productivity. Then, with the chosen P as a target, the steam injection rate and pressure is adjusted to attain the pressure target (pressure control). For reason discussed in the previous section, if a WLZ is breached, the normal operating procedure becomes difficult.
  • This invention comprises a method to improve, preferably optimize SAGD performance in WLZ reservoirs (including top water and bottom water cases) or where the reservoir is a “leaky” reservoir.
  • a “leaky” reservoir loses injection fluids if operating P>native reservoir P or has encroachment of fluids if operating P ⁇ native reservoir P.
  • the invention further comprises measurement of the water recycle ratio (WRR) for reservoirs containing WLZ zones.
  • WRR is the volume ratio of produced water/injected steam, where steam injection is measured as a liquid-water equivalent. Rather than pressure control on steam injection rates, steam injection should be adjusted to attain a WRR target for each SAGD well.
  • FIG. 9 shows the predicted performance. As can be seen, the predicted steam injection rate peaks at 2936 bbls/day and bitumen production rate peaks at 1002 bbls/day.
  • FIG. 10 shows the predicted WRR performance. The WRR started around 0.9 and increased gradually to greater than 0.99 after 1200 days (31 ⁇ 4 years).
  • FIG. 10 shows how a WRR-control strategy would work for SAGD in a homogeneous, sealed reservoir.
  • Case 3 Shame as Case 2, but after 1 year stop SAGD pressure control and shift to constant volume control (steam injection is constant);
  • Case 4 Shame as Case 2, but with 3 m thick WLZ (WLZ is 5% of pay zone volume);
  • Case 5 Shame as Case 3, but with 3 m thick WLZ;
  • FIGS. 13 , 14 , 15 , 16 , 17 and 18 show the predicted performance for each well pair, for Cases 1, 2, 2(a), 3, 4 and 5 respectively.
  • FIGS. 19 and 20 show the cumulative performance of both well pairs for the above cases.
  • FIGS. 21 and 22 show cumulative bitumen productivity for Case 1 (Base Case) and Case 2.
  • FIG. 23 shows WRR performance for Case 3 for each well pair.
  • FIG. 24 shows cumulative WRR performance for Case 1 vs. Case 3.
  • FIG. 25 shows individual well pair bitumen performance for Case 3.
  • a “leaky” SAGD pattern is one that produces an unusual amount of water.
  • the “leaky” SAGD pattern may have water leaks in/out of the pattern volume to other portions of the reservoir; it may have water leaks to/from an adjacent reservoir SAGD pattern; or, it may produce unusual water volumes from WLZ within the reservoir.
  • the WRR will be used as an indicator (the volume ratio of produced water to steam injected, where steam is measured as a water-volume equivalent).
  • FIG. 10 shows the expected WRR behaviour.
  • WRR is between 0.90-0.95.
  • the GD steam chamber is forming, and the GD area is heating up. An inventory of liquid water is created in the reservoir.
  • WRR increases gradually from about 0.96 to 0.99. If the bitumen voidage is occupied by steam only, one would expect WRR to be greater than 0.99 ( FIG. 11 ).
  • bitumen production is small and the WRR approaches the 0.99 value ( FIG. 10 ).
  • a reasonable target for WRR—for a perfectly contained SAGD GD chamber and a homogeneous reservoir—during the peak period of SAGD (500-1500 days) is about 0.97.
  • FIG. 23 shows WRR in a leaky reservoir and how a leaky reservoir is defined. If WRR deviates from 1.0 by more than ⁇ 0.10 after 200 or more days of continuous SAGD using normal pressure control, the reservoir is deemed as “leaky”. Using this definition, the Case 3 simulation WRR performance in FIG. 23 would result in both well pair patterns deemed as “leaky”. Well pair 1 has a higher WRR, and well pair 2 has a lower WRR than the 1.0 control.
  • the SAGD pattern may be designated as “leaky” or potentially “leaky”.
  • Another alternative is to use a cold water injectivity test to quantify SAGD well connectivity to WLZ, top water, or bottom water zones (Aherne (2006)). This may also be used to designate a SAGD pattern as “leaky” or potentially “leaky”.
  • FIGS. 14 and 25 show what can happen for a leaky reservoir.
  • Well pair 1 (the low P pattern) is flooded with 1 ) water from the WLZ and 2 ) from water condensed from steam injected into the adjacent well pair 2 .
  • bitumen production is very small, and SOR is very high.
  • SAGD pressure control shuts off steam injection into well pair 1 after about 450 days.
  • Well pair 2 (the adjacent, high-P pattern) produces bitumen, but SOR is high.
  • steam from well pair 2 breaks through to well pair 1 ( FIG. 15 ), and production from well pair 1 resumes as a pseudo steam flood.
  • An alternative control mechanism is to control steam injection rates, independent of reservoir pressure.
  • FIGS. 16 and 18 show that setting steam injection rates at fixed volumes, even after 1 year of pressure control, can restore bitumen productivity and improve other performance factors. But, a somewhat arbitrary and equal setting of volume rate targets may work partially because both well-pair patterns are homogeneous and identical expect for the WLZ connecting the patterns for the Cases studied.

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US20140102700A1 (en) * 2012-10-16 2014-04-17 Conocophillips Company Mitigating thief zone losses by thief zone pressure maintenance through downhole radio frequency radiation heating
CN105756625A (zh) * 2014-12-17 2016-07-13 中国石油天然气股份有限公司 双水平井采油方法
US20180197940A1 (en) * 2017-01-11 2018-07-12 International Business Machines Corporation Resistors with controlled resistivity
CN112943194A (zh) * 2021-03-03 2021-06-11 中国石油天然气股份有限公司 一种预防sagd开发过程中边水下内侵的方法
CN112963128A (zh) * 2021-03-03 2021-06-15 中国石油天然气股份有限公司 降低蒸汽腔外溢预防sagd开发过程中顶水下窜的方法

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CN108952693B (zh) * 2018-04-19 2022-02-01 中国石油天然气股份有限公司 一种注气井吸气剖面的吸气比例的确定方法
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US7740062B2 (en) * 2008-01-30 2010-06-22 Alberta Research Council Inc. System and method for the recovery of hydrocarbons by in-situ combustion
CN101592028B (zh) * 2008-05-28 2012-01-11 中国石油天然气股份有限公司 一种气体辅助sagd开采超稠油的方法
US8756019B2 (en) * 2008-11-28 2014-06-17 Schlumberger Technology Corporation Method for estimation of SAGD process characteristics
WO2012037176A1 (fr) * 2010-09-14 2012-03-22 Conocophillips Company Fracturation par rf pour améliorer la performance du dgmv
CN102278103B (zh) * 2011-08-25 2014-04-02 中国石油天然气股份有限公司 一种重力泄水辅助蒸汽驱提高深层超稠油油藏采收率方法

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US20140102700A1 (en) * 2012-10-16 2014-04-17 Conocophillips Company Mitigating thief zone losses by thief zone pressure maintenance through downhole radio frequency radiation heating
CN105756625A (zh) * 2014-12-17 2016-07-13 中国石油天然气股份有限公司 双水平井采油方法
US20180197940A1 (en) * 2017-01-11 2018-07-12 International Business Machines Corporation Resistors with controlled resistivity
CN112943194A (zh) * 2021-03-03 2021-06-11 中国石油天然气股份有限公司 一种预防sagd开发过程中边水下内侵的方法
CN112963128A (zh) * 2021-03-03 2021-06-15 中国石油天然气股份有限公司 降低蒸汽腔外溢预防sagd开发过程中顶水下窜的方法

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