WO2011156907A1 - Procédé et appareil d'extraction préférentielle de fluides à partir de puits horizontaux - Google Patents

Procédé et appareil d'extraction préférentielle de fluides à partir de puits horizontaux Download PDF

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Publication number
WO2011156907A1
WO2011156907A1 PCT/CA2011/000708 CA2011000708W WO2011156907A1 WO 2011156907 A1 WO2011156907 A1 WO 2011156907A1 CA 2011000708 W CA2011000708 W CA 2011000708W WO 2011156907 A1 WO2011156907 A1 WO 2011156907A1
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Prior art keywords
pressure
fluid
horizontal
production
chamber
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PCT/CA2011/000708
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English (en)
Inventor
John Nenniger
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John Nenniger
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Publication of WO2011156907A1 publication Critical patent/WO2011156907A1/fr

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Classifications

    • 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
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells

Definitions

  • This invention relates to the field of in situ hydrocarbon extraction and more particularly to the extraction of conventional oil, heavy oil and bitumen from underground formations using extraction processes which use generally horizontal production wells. Most particularly this invention relates to methods, controls and equipment to improve the overall efficiency of the production of hydrocarbons from such horizontal wells.
  • Horizontal wells are being used more extensively in the production of hydrocarbons from underground formations or reservoirs. Gravity drainage is an emerging technique that uses horizontal wells and it promises to greatly increase the recoverable reserves of oil. Historically most oil recovery has been achieved through primary recovery which uses generally vertical wells and the native reservoir pressure to push fluids to the production well or through secondary recovery whereby a fluid such as water or gas or the like is injected to maintain reservoir pressure and provide a drive mechanism to push oil towards the production wellbore.
  • a typical well configuration involves paired horizontal wells: one for vapour injection; and a second one for liquid production.
  • An extraction chamber is formed around the injection well generally above the production well. Fluids, mobilized by the recovery process drain down the sides of the extraction chamber and into a liquid sump around the production well.
  • the vapour chamber expands outwardly as more fluids drain towards the bottom of the chamber.
  • the production well is divided into two main sections - a generally horizontal inflow section that contains perforations or the like to permit fluid to flow into the wellbore, and a riser section that has no perforations and acts as a fluid conduit to bring fluids to surface.
  • the riser section may be generally vertical or may be sloped depending upon the reservoir depth and drilling pattern used.
  • a key feature of a gravity drainage process is that the liquid withdrawal from the chamber through the production should be restricted to ensure that the production well and thus the inlet perforations are always submerged under liquid.
  • This liquid submergence prevents vapour, being injected at pressure into the chamber above to encourage recovery, from passing directly into the production well without any beneficial extraction or oil mobilization effect.
  • Any vapour that short circuits into the production well represents a loss of efficiency for the extraction process because it is unable to deliver its latent heat or its solvent content to the oil to be recovered.
  • gas assisted gravity drainage where an inert gas is injected into the vapour chamber without any intention of mobilizing the oil and simply to help fill the void volume in the extraction chamber, the loss of gas into the production well is undesirable.
  • steam assisted gravity drainage this technique of limiting the fluid production from the extraction chamber to liquids (i.e. hot water and hot bitumen) is called steam trap control.
  • the steam trap control up to now has been achieved by measuring a temperature at some downhole location within the production wellbore, such as the suction side of a pump or the entry to a tubing string, and then this temperature is compared to the temperature in the steam vapour chamber. If this measured wellbore temperature (also referred to as the bottom hole temperature (BHT)) is 5 degrees cooler than the saturation temperature for water at chamber pressure conditions, it is called a 5C sub-cool. The detection of a sub-cool temperature difference is then used to determine the allowable pressure in the horizontal wellbore. For example if the chamber is at 225C and the subcool is 5 degrees centigrade, this means that the temperature at the measuring point in the horizontal wellbore is 220C.
  • BHT bottom hole temperature
  • Water at 220C should remain as a liquid as long as its pressure is kept at or above 2320kPa based on the pressure curve for water. Consequently, in the steam trap sub-cool temperature control method it is assumed that the wellbore pressure can drop as low as 2320kPa without risk of vapour breakthrough or the water in the horizontal inlet wellbore flashing back into steam.
  • sub-cool temperature control is used to determine the allowable amount of pressure drawdown (or difference) between the vapour chamber and the horizontal wellbore.
  • the allowable drawdown is 230kPa which is the difference in the saturation pressures at 225 and 220C (i.e. 2550-2320 kPa respectively). This is understood to mean that the friction flow into the horizontal wellbore and friction pressure drop along the length of the horizontal wellbore must be less than 230kPa in order to prevent water, which is being co-produced with the oil, from flashing into vapour in the production well.
  • the horizontal wellbore should be at or above chamber pressure of 2550 but below 2600kPa. If the pressure in the horizontal wellbore is not equal to or greater than the chamber pressure then there can be no assurance that the horizontal wellbore is actually submerged in liquid or that vapour is prevented from entering into the inlet portion of the production well.
  • the pressure at the surface or wellhead is typically fairly steady because it is largely set and controlled by the inlet conditions at the downstream plant where, for example, many SAGD wells will empty into a separation vessel or a common flowline.
  • the pressure in the vapour chamber in the reservoir is also fairly steady, due to its large volume and because it contains saturated steam and water. Consequently, any geysering activity that changes the pressure drop across the riser or vertical portion of the wellbore, due to unloading of liquids, will also tend to produce an uncontrolled and large transient pressure differential between the inlet portion of the production wellbore and the chamber.
  • the measured temperature control method and the hydraulic (liquid submergence) method teach different and incompatible requirements for establishing steam trap control in SAGD.
  • SAGD sub-cool temperature control method
  • large and erratic pressure surges between the chamber and the horizontal wellbore are presumed acceptable if the sub-cool temperature is adequate.
  • 1800kPa would correspond to a chamber temperature of 207C.
  • 1400kPa the minimum pressure, corresponds to a steam flashing (boiling) temperature of 195C.
  • the minimum adequate sub-cool temperature would then be 12C (207-195).
  • the temperature of the produced fluids was measured at 180C, so the actual sub-cool temperature was 27C (207-180).
  • the 27C sub-cool temperature in Edmunds Figure 5 should have been adequate to tolerate the 400kPa pressure cycles without allowing any steam to vent into the horizontal wellbore, i.e. flashing conditions between the chamber and the production well do not exist.
  • the hydraulic (submergence) criteria are much more restrictive than the measured temperature control method would suggest is necessary or appropriate.
  • the hydraulic criteria suggests that large quantities of vapour can short circuit directly into the horizontal wellbore at same conditions when the temperature criteria suggests that there is no such venting.
  • US patent 6,371 ,210 relates to a device that includes an inner tubular body portion having apertures in the wall thereof for passing oil, an outer tubular body and a pathway therebetween permitting oil from the formation to migrate into the inner body. Disposed around the outer body is an axially moveable member to selectively cover and expose the apertures of the inner body, thereby permitting fluid to flow therethrough.
  • the axially moveable body is provided with a piston surface on an upstream side of the body and a spring on a downstream side of the body.
  • the patent teaches that mass flow rates will cause the spring to deflect aligning the apertures and permitting the oil to flow to the inside.
  • pressure is measured between the inside of the valve and the outside and the pressure difference is used to move the annular member, either through an electronic actuator, or through a hydraulic line in fluid contact with the piston surface on the upstream side.
  • this prior patent fails to adequately solve the problem of vapour short circuiting. More specifically, the use of a spring means that the back pressure resisting the force on the piston surface cannot be varied with changing conditions in the reservoir, such as the change in the size of the extraction chamber over time.
  • active control either hydraulically or electromechanically, to directly open or close the apertures is of no practical use when the actual flow rates are unknown.
  • the device as depicted in the patent cannot achieve flow control except at one arbitrary point as defined by the spring properties, which may bear no relation to what is required to optimize hydrocarbon production at any given time in the life of the extraction process.
  • What is desired therefore is a method and apparatus to control the production from the horizontal portions of hydrocarbon production wells, such as SAGD wells to ensure liquid submergence of the inlet portion to thereby limit vapour loss into the horizontal production well. More generally what is required is a method and apparatus to control liquid submergence levels of specific fluids in the underground formation to permit the preferential production of desired fluids from the reservoir. What is desired is to be able to implement flow regulation based on hydraulic criteria rather than based on indirect subcool temperature measurement as is presently the case in SAGD extractions.
  • the present invention is based on the belief that the subcool temperature method for SAGD does not provide accurate control of vapour short circuiting into and through the horizontal production well, which leads to lost heat energy and efficiency. This manifests itself in high steam/oil ratios, high energy consumption per barrel of oil produced, high greenhouse gas emissions, high capital expenses and unnecessarily large amounts of contaminated hot water to cool and process at the surface production facility among other things.
  • the present invention is further based on the need to provide methods and apparatuses for better controlling the preferential production of hydrocarbon fluids from underground formations through horizontal wells generally through hydraulic control.
  • the present invention teaches a method and device for controlling the pressure differential existing between the reservoir and the inlet portion of a generally horizontal production well to better control the degree of liquid submergence of the inlet portion to limit the amount of undesirable fluids that may be coproduced and to preferentially produce any desired fluids such as hydrocarbons.
  • the present invention is compatible with the slots, screens, orifices or other openings that may be provided on inlet portion of the production well and provides pressure related flow control regardless of the temperatures, fluid composition or flowrates.
  • Another aspect of the present invention is a method and apparatus to control the pressure difference between the vertical riser and the horizontal leg of the production well to isolate the inlet or horizontal portion of the wellbore from the erratic and violent geysering, and associated pressure oscillations, that can originate in the vertical or riser portion of the wellbore.
  • both aspects of pressure isolation and controlled pressure regulation between the production well and the reservoir can be achieved through a single mechanism referred to as a pressure regulating means.
  • the pressure regulating means is provided in the production well between the riser and the inlet portion to pressure isolate the inlet portion from the riser.
  • the present invention measures and controls the pressure at a location where the pressure control is needed to control fluid passage through the inlet into production well from the reservoir or extraction chamber.
  • the present invention can detect the actual fluid levels above the production well, for example, to provide a liquid seal to prevent vapour breakthrough or flashing in a SAGD environment.
  • a measure of liquid level control can be achieved and vapour breakthrough reduced and controlled and, if desired, substantially eliminated.
  • the present invention provides a means to reduce, and therefore improve, the steam oil ratio required in, for example, a SAGD production process by ensuring that the steam heat is not wasted through short circuiting from the extraction chamber directly into the production well.
  • the present invention provides the desired liquid seal through the use of a measured differential pressure (i.e. caused by the liquid head) in the chamber to control the production rate. To do this typically requires at least two pressure measurements, both of which are upstream of the inlet into the production well. In a long horizontal wellbore, the differential pressure control can be located at multiple locations along the horizontal well.
  • a pressure control device which provides the desired degree of pressure isolation from the potential geysering in the vertical well bore and thereby avoids excessive drawdown and vapour loss while still permitting production flow.
  • the present invention further comprehends that such a device can be placed at several locations along a production tubing to enable the horizontal length of the well to be greatly extended without losing inflow pressure control.
  • Such inflow pressure control in turn allows the preferential production of hydrocarbon fluids from amongst other fluids that might be present in the formation by ensuring at any given inflow location an appropriate degree of submergence of the inlet portion of the horizontal production well with the hydrocarbon fluids to be preferentially extracted.
  • the present invention provides a pressure responsive inlet flow control device comprising:
  • At least one aperture in fluid communication between a reservoir and a riser portion of a horizontal production well
  • a moveable valve element for controlling fluid flow through said aperture, said moveable valve element having an upstream piston surface exposed to said fluid in an inlet portion of a production well and a rear piston surface exposed to a pressure controlled piston reservoir, and
  • said moveable valve element balances pressures between said pressure controlled piston reservoir and said upstream piston surface and moves to expose or cover said at least one aperture.
  • Figure 1 shows that the steam to oil ratio for a number of commercial SAGD projects compared to ratios estimated based on heat balance calculations
  • Figure 2 shows a cross section of a SAGD gravity drainage chamber with pressure sensors in an observation well and in the production well according to the present invention
  • Figure 3 shows a cross section of the SAGD gravity drainage chamber of Figure 2, along the length of the horizontal wells
  • Figure 4 shows a preferred embodiment of a pressure control valve according to the present invention
  • Figure 5 shows a second embodiment of a pressure control valve
  • Figure 6 shows the pressure control system schematic according to the present invention
  • Figure 7 shows the control algorithm used to determine the appropriate setpoint for the pressure control valve of the present invention
  • Figure 8 shows a plot of the estimated pressure at various locations from the extraction chamber through to the wellhead of the production well of a sample well.
  • Figure 9 shows the estimated relationship between drawdown and oil production rate and steam oil ratio according to the present invention.
  • the fluids will also contain mixtures of two different fluids, such as water and oil.
  • the term preferentially in terms of preferentially produced hydrocarbon fluids shall means that more of the hydrocarbon fluid is produced with the use of the present invention than is possible without using the methods and apparatuses of the present invention. Preferential production of the desirable hydrocarbon fluid improves the economics of the extraction process and thus is preferred.
  • Figure 1 shows the steam oil ratio for a number of commercial SAGD projects by plotting the steam oil ratio on the vertical axis on a log scale, and the pay thickness of the hydrocarbon resource on the horizontal scale.
  • the solid line 10 in Figure 1 shows the expected steam to oil ratio accounting for heating the pay zone and heat losses to the overburden and underburden assuming an extraction temperature of 230C and oil saturation and porosity characteristics typical of commercial SAGD projects.
  • the dashed line 12 shows the theoretical steam oil ratio in the case where there is no heat losses to the overburden and underburden and is understandably lower.
  • the data points 14 show the actual steam oil ratios of operating projects.
  • the individual data points 14 are sourced from In Situ Progress Reports posted on the Alberta Energy Resources Conservation Board website and Jaremco.D., How SAGD Projects are really performing, Oilsands Review Magazine, August 2009.
  • the data points 14 are all above the theoretical operating level 10, and in many cases well above, considering the use of the log scale on the graph.
  • This Figure 1 indicates that the steam consumption of commercial SAGD projects is generally two to three times higher than can be justified by a heat balance calculation or estimate.
  • Figure 1 shows that most of the steam energy is wasted in commercial SAGD projects. Since commercial SAGD projects can generally account for most of the mass of injected steam, a heat balance calculation suggests that most of the injected steam is short circuiting directly out of the SAGD production wells.
  • Figure 2 shows a cross section through a gravity drainage chamber 18 such as might be formed with a SAGD extraction process and which is used to illustrate the features of the present invention.
  • 20 is a top of the extraction or vapour chamber 18.
  • 24 is the overburden layer and 26 is the underburden.
  • 28 is an observation well which preferably contains one or more pressure sensors 30 which are in pressure communication with the chamber 18 and able to transmit their readings 31 up the observation well 28 to a data acquisition and pressure controller unit 32 located at surface.
  • the pressure sensors 30 will preferably include multiple pressure sensors at different elevations in observation well 28 to allow the local position of a liquid interface (meaning a liquid to liquid or liquid to gas interface as the case may be) in the lower part of the chamber 18 to be detected.
  • one pressure sensor is located in the observation well at the level of the horizontal production well to provide a pressure differential between that point and a point above, in the vapour chamber, to determine a liquid level above the inlet portion of the horizontal well.
  • Figure 2 also shows an injection well 34 which injects a vapour, for example steam 36 (large arrows).
  • This steam 36 travels to any location in the chamber 18 which is cooler than the saturation temperature of the steam and condenses thereby delivering its latent heat of condensation.
  • the heat reduces the viscosity of the bitumen and mobilizes it 37 (smaller arrows) so the bitumen drains by gravity towards the bottom of the chamber 18 together with the condensed steam.
  • Towards the bottom of the chamber is a generally horizontal production well 38 into which the bitumen and condensed water flow from where they are then transported to surface for example by natural lift through a generally vertical or riser section.
  • the production well 38 preferably also contains a pressure sensor 40 to measure a pressure within the generally horizontal portion of the well 38.
  • a pressure sensor 40 to measure a pressure within the generally horizontal portion of the well 38.
  • a direct measurement of skin damage can be made.
  • skin damage can also be inferred by changes over time to the production rates.
  • gravity drainage production it is desirable to maintain the vapour liquid interface 35 at a position intermediate between injection well 34 and production well 38, so the inlet portion of the production well 38 is submerged in liquid. This requires achieving a certain degree of pressure control between an inlet of the production well and the chamber regardless of the local temperatures or pressure surges according to the present invention.
  • Figure 3 is a cross section of the same gravity drainage chamber 18 of Figure 2 shown along its length. Again 24 is the overburden, 26 is the underburden and 20 represents the top of the vapour chamber.
  • the cross section view of Figure 3 shows that the production well 38 has several distinct sections, including a generally horizontal inlet section 39 into which the reservoir fluids drain and a generally vertical removal section or riser 46 which provides a fluid conduit to bring production fluids to surface.
  • the horizontal section 39 and the riser 46 are separated by transition zone usually called a heel 41.
  • the generally horizontal section 39 includes perforations, slots or screens or the like to enable fluid flow from the reservoir into the wellbore, while the generally vertical riser section 46, typically has no such openings through casing 52 into the adjacent reservoir.
  • the riser 46 portion of the production well 38 is frequently somewhat slanted to allow a number of wellheads to be located close together and thereby reduce the surface footprint.
  • Figure 3 also shows the observation well 28 with the at least one pressure sensor 30 and transmission means 31 to relay pressure sensor measurements to the above ground data acquisition and pressure control unit 32.
  • the observation well can be spread apart laterally from the production well, it is preferred if it is placed close to or adjacent to the production well, so as to be able to detect a pressure and hence a liquid level directly above the inlet portion. If the observation well is more offset from the production well, it becomes more challenging to relate the liquid level in the observation well to an amount of submergence for the production well.
  • the present invention also comprehends using multiple observation wells along a length of the tubing to detect liquid levels along a length of the inlet portion of the production well. In the case where there is no observation well, it may be necessary to obtain pressure measurements from the injection well, perhaps by shutting steam flow off for a short period of 10 to 15 minutes so that friction pressure drops can be eliminated and the chamber pressure measured with some precision.
  • a pressure control means is provided between the inlet portion and the riser in the heel 41.
  • it takes the form of a pressure responsive inlet flow control device, such as a valve 42, which opens and closes to maintain a controlled pressure difference or drawdown between the horizontal section 39 of the production well 38 and the chamber 18 as measured by a first pressure sensor 30 in the observation well and a second pressure sensor 40 within the horizontal portion of the wellbore 39.
  • valve 42 helps to assure that the liquid vapour interface 35 is located at a position intermediate between the injection well 34 and the horizontal section of the production well 39.
  • Produced fluid that passes through pressure control valve 42 travels in the tubing 51 up the generally vertical portion of the production well 46 and may geyser 48 at some elevation as the pressure drops.
  • a mixture of steam vapour, hot water and hot bitumen at the wellhead 50 is then sent to the SAGD processing facility.
  • FIG. 4 shows the main functional elements of the pressure responsive inlet flow control valve 42 according to one aspect of the present invention, which is suitable for a natural lift process such as SAGD.
  • the valve assembly 42 of Figure 4 is located near the end of a tubing string 51 which is deployed down a casing 52.
  • a hydraulic line 54 provides a control pressure established through a data acquisition and pressure control unit 32 located above grade at surface.
  • the control pressure is provided as a fluid pressure that a fluid medium, such as hydraulic oil, to a pressure isolated piston chamber 56 exposed to a backside pressure surface 58b on a moveable valve member, or piston 58, where the front side 58f is exposed to the fluid 43 in the inlet portion of the horizontal production well.
  • the annular piston 58 has seals 60 on an outer diameter of a flow mandrel 62 and seals 59 which seal against the inner diameter of the tubing 51.
  • the annular piston 58 responds to a pressure difference between the pressure control delivered via the hydraulic line 54 to pressure isolated piston chamber 56 and the actual pressure in the horizontal section of the wellbore at location 43 which is acting on the opposite surface of the piston 58.
  • the piston 58 is free to travel along the flow mandrel 62 in one direction or the other in response to the pressure difference between the backside pressure controlled piston chamber 56, which is controlled from the surface, and the production wellbore 43.
  • the flow mandrel 62 includes one or more slots 64. These slots 64 provide a variable cross sectional area open to the fluid flow which depends on the position of the annular piston 58.
  • a triangular slot 64 is shown in this embodiment but the present invention comprehends various shapes of slots with various cross- sectional areas depending upon the specific reservoir. In general it is most preferred if the area of the slots, when fully open or exposed, are at least as large as the cross sectional area of the riser pipe, to avoid the slot openings from becoming a limitation on inflow.
  • the present invention comprehends that it may be desirable to increase the inflow area when fully open a bit more even to minimize hydraulic losses that will occur as the produced fluids flows through the slots.
  • the piston 58 is preferably provided with stops 68 to limit its travel to an appropriate functional distance, which will be a range of movement, having regard to the change in slot area to provide adequate flow control from the extraction chamber. As well it is preferred to limit the travel of the piston 58 to prevent damage to the seals 60 and 59.
  • the pressure control action of the pressure control means 42 of the present invention can now be understood. If the local pressure in the horizontal wellbore at position 43 is lower than the pressure setpoint in chamber 56 delivered by the hydraulic line 54 from controller 32, the piston 58 will travel away from the hydraulic line 54 as shown by arrow 70 and this travel will partially cover up slot 64. This piston movement shown by arrow 70 reduces the fluid flow through the pressure control valve 42. The fluid flow rate will continue to decrease until the pressures at 56 and 43 are balanced. In this way the travel of the piston 58 is responsive to the pressure setpoint 56, provided at the backside of the piston, in a manner that automatically forces the upstream pressure 43, i.e. the pressure in the horizontal portion of the production wellbore, to match with the desired pressure setpoint 56. As can now be appreciated this is because the pressure in the piston chamber 56 is only determined by the pressure delivered by the hydraulic line as a pressure set point, and there is no direct fluid connection between the pressure controlled piston chamber 56 and the production well or reservoir.
  • the absolute pressure at 43 will be determined by a combination of fluid or hydraulic head and the chamber pressure and the pressure in the inlet portion of the horizontal wellbore is protected from pressure surges due to geysering. Because the pressure of the chamber 18 is being independently measured, the relative pressure between the chamber 18 and the entrance 43 to the pressure control means 42 can be determined. A specific pressure difference will correspond to a certain hydraulic or fluid head above the inlet portion of the production well. If the fluid drains through the pressure control means 42 faster than it is draining into the sump above the inlet portion of the production well, then the hydraulic level (submergence) 35 in the chamber will lower, and the pressure will also lower. This will cause the piston 58 to move in direction of arrow 70 closing the openings 64 and slowing the flow rate.
  • the desired pressure set point for the piston chamber 56 will be determined by various factors such as pressure in the extraction chamber and depth of liquid submergence and pressure drop due to inflow into the horizontal wellbore.
  • the seals 59, 60 on the annular piston 58 are designed to slide without excessive friction to reduce any time lag in responding to pressure changes and to reduce wear.
  • the present invention comprehends the use of appropriate seal wipers and the like to reduce the risk of grit and sand becoming trapped and damaging the seals 59, 60 or other surfaces.
  • An inflow screen can also be provided to prevent grit sand or the like from getting into the seals.
  • the operative elements of the pressure control means 42 are preferably made from special hard and non-corrosive materials to minimize the rate of erosion and perhaps corrosion due to hot aggressive fluids. Preferred materials include high hardness steel, titanium or the like.
  • the valve 42 is only responsive to pressure differentials around any given pressure setpoint established in the piston chamber 56.
  • the pressure at 43 and pressure sensor 40 do not correspond to exactly the same location, they are preferably in close proximity, so the pressure at both locations is substantially identical.
  • the pressure sensor 40 is located beyond stop 68 to avoid risk of mechanical interference from the piston 58 as it travels to the end of its range.
  • Pressure sensor 40 has a means 31 which could be a bubble tube or the like to transmit its pressure measurement to surface.
  • the piston 58 is completely free to seek any position that balances the pressures, there is no a priori requirement to specify a certain orifice opening at a certain pressure for a certain target flowrate.
  • the present invention also comprehends more than one pressure control valve in an inlet portion of a horizontal wellbore.
  • These multiple drains could be on a single tubing string or on several parallel strings. If there are multiple pressure control valves on a single tubing string, the pressure control valve action would regulate the pressure in the annulus between the tubing and the casing, and the each pressure regulating valve would exhaust fluid into the tubing to allow produced fluids to be conveyed to surface.
  • Figure 5 shows a further embodiment of a pressure regulating valve 42' for placing "in-line” along the length of the horizontal portion of the production tubing.
  • the valve allows pressure regulated flow from the tubing-casing annulus into the production tubing.
  • the piston is cylindrical rather than annular.
  • the valve has a port 55' to allow produced fluid 37' to enter, and shaped orifice(s) 64' which are partially blocked by piston 58', to achieve pressure regulation at location 43'.
  • This embodiment is particularly helpful as it can allow the length of the horizontal well to be greatly extended yet maintain relatively flat pressure gradients in the horizontal portion of the production casing annulus.
  • valves in the case of separate hydraulic control lines, placement of several pressure control valves as shown in Figure 5 along the horizontal wellbore, these valves could be used to selectively encourage more drainage or higher drawdown from certain sections of the horizontal wellbore. In some situations, it may also be desirable to also employ packers between adjacent pressure control valves. As will be now appreciated these in line pressure regulating valves need not be placed near the end of the production tubing 51 but can be positioned a multiple locations along the horizontal portion of the production well to maintain inflow pressure control along the entire length of the inlet portion of the horizontal well. An example of a pressure control system schematic according to the present invention is illustrated in Figure 6.
  • the data acquisition and control unit 32 monitors the pressure in chamber 18 with the at least one sensor 30 and monitors pressure in the horizontal section 39 of the production well 38 with at least one sensor 40. Multiple sensors may also be used for redundancy or improved sensing. Control unit 32 will adjust the pressure setpoint in valve 42 from time to time via hydraulic line 54. These setpoint adjustments would typically be made in response to a change in chamber pressure or in liquid vapour interface level as measured by sensor 30 or as a result of a change in pressure differential with sensors 40. The desired pressure or the pressure difference or drawdown setpoint is specified by the operator via input 16.
  • downstream pressure in the vertical portion of the wellbore 46 has no influence on the pressure upstream of the valve at 43 as the present invention isolates the pressure in the horizontal leg 39 from the pressure in the vertical leg 46.
  • geysering in the vertical portion of the wellbore will increase the pressure difference across pressure control valve 42 between an upstream side 43 of the valve means 42 and a downstream side 72 of the valve means 42, but the valve maintains the desired pressure on the upstream side 43 by dynamically responding to the downstream pressure changes.
  • the present invention provides effective pressure isolation in the horizontal inlet portion of the production wellbore from the intermittent geysers in the vertical portion of the production wellbore.
  • the piston 58 will seek a position that automatically maintains the upstream pressure at the desired setpoint over a very large broad range of flowrates and pressures, ranging from full open to completely closed and independently of whatever temperature or subcool occurs.
  • the fluid flow rate through the pressure control valve 42 is fully variable and is not set to achieve any particular target flowrate unlike Edmunds patent previously discussed.
  • the desired flowrate will vary substantially as the chamber grows and production rates improve due to an ever increasing extraction surface area within the chamber and it is not at all straightforward to predict what an appropriate flowrate setpoint should be at any point in the life of a SAGD production well.
  • Edmunds tries to address this uncertainty by using temperature measurement, or subcool as a guide to ensuring a liquid level over the horizontal part of the production well. But, as previously described a target temperature measurement is not and cannot be reliably used to control fluid flows because of the rapid pressure surges that occur.
  • a pressure setpoint for the valve means can be determined. Delivering that pressure setpoint via a hydraulic line from the surface presents certain challenges because the pressure signal at surface must be added to the hydrostatic head of the hydraulic line 54 to provide the downhole pressure setpoint at piston chamber 56.
  • the hydrostatic head depends on the wellbore temperature profile because the density of the hydraulic fluid will vary somewhat with temperature. The present invention therefore contemplates the use of different fluids, including gases to provide the required back pressure for the piston, depending upon the depth of the formation and the like.
  • the present invention also provides one or more pressure sensors 40 on the tubing at a downhole position in the horizontal wellbore to obtain a direct reading of the pressure in the horizontal portion of the wellbore to confirm that the inlet side of the valve means 42 is at or near its target setpoint value.
  • pressure sensors 40 At SAGD temperatures there are commercial pressure sensors which are accurate to 0.2%, such as those manufactured by Paine Electronics (paineelectronics.com). Consequently for a 2 MPa transducer, the pressure error should only be 4 kPa, which corresponds to uncertainty in controlling fluid submergence of about 40 cm.
  • the present invention is not limited to such a degree of accuracy though, and as more precise pressure sensor become available, more sensitive liquid level sensing control can likely be achieved.
  • This invention also comprehends the use of less sensitive pressure detection means such as bubble tubes or the like if reliability of sensor operation at high temperature is a problem. However, given the desire to maintain an adequate liquid level in the sump to prevent vapour breakthrough, the degree of control offered by present sensors is believed adequate.
  • the piston 58 must be responsive to changes in pressure determined by hydraulic head in the sump, or the liquid head in the chamber.
  • the most preferred form of the invention is able to detect and respond to at least 3 metres of fluid head, more preferably 1.5 metres and most preferably 0.5 metres at chamber conditions.
  • the responsiveness of the valve is a function of the friction and momentum of the piston 58 moving in the piston housing.
  • the piston movement should be possible at relatively low pressure differentially as noted above.
  • the present invention is robust enough to respond quickly and withstand large and sudden pressure changes.
  • Formation damage can occur in SAGD wells due to scale precipitation or other materials, such as sand or clay or fines which accumulate in the near wellbore or on the wellbore. Such material can plug the sand pack around the wellbore or the slots or perforations of the inlet portion of the production well.
  • the sand immediately surrounding the wellbore should initially have very high permeability due to local high porosity from the drill hole being oversized relative to the outer diameter of the slotted liner.
  • pressure surging can also mobilize fines and eventually these fines can form a less permeable barrier around the inlet portion of the wellbore which is called skin damage.
  • one of the benefits of the invention is that by avoiding pressure surges in the inlet portion of the production well originating from any geysering in the vertical portion of the wellbore, the potential for formation damage is reduced, the potential for excess pressure drop across the liner is reduced and higher oil production rates may be achieved for longer and more reliably than in the prior art.
  • valve shown in Figure 4 could also be designed with a cylindrical piston with the piston located in the center of the production tubing, and the flow being directed outwards into an annular cavity still inside the tubing.
  • This geometry would have similar functionality and would likely only need one sliding seal instead of two.
  • Such a design would be more tolerant of sand and grit since there are no dead spots or recirculation zones that could trap and therefore accumulate sand.
  • the present invention further comprehends providing means to help flush grit, sand, fines or like material away from sliding surfaces.
  • the present invention further comprehends incorporating a flapper type access valve (not shown) at the rounded nose 26 so that the full production wellbore is accessible in case coiled tubing or the like must be temporarily deployed to a position along the horizontal well through the valve means 42.
  • a flapper type access valve (not shown) at the rounded nose 26 so that the full production wellbore is accessible in case coiled tubing or the like must be temporarily deployed to a position along the horizontal well through the valve means 42.
  • the present invention provides a control action or response that is both rapid and accurate. It is anticipated that the present invention will tend to experience flashing on the downstream (outlet) side and may therefore be vulnerable to erosion and cavitation due to high fluid velocities and thus the present invention comprehends measures to protect this portion of the device.
  • Figure 7 shows the control logic for a method of controlling production flow in the present invention.
  • a first step the pressure of the chamber and the pressure in horizontal portion of the wellbore are measured.
  • step two these two pressure measurements are compared to determine a measured pressure difference and this is compared to a desired drawdown pressure difference specified by the SAGD operator. For example, does the pressure difference confirm that there is sufficient liquid submergence covering the inlet portion of the production wellbore to prevent excessive vapour production?
  • the pressure setpoint delivered to the regulating valve by the hydraulic line is adjusted to achieve a new piston position consistent with the desired pressure difference. In other words, if the pressure in the horizontal portion of the wellbore is too great, the valve opens and if it is too small the valve closes.
  • the control device is preferably located downhole to isolate the pressure in a generally vertical portion of the wellbore from the pressure in the generally horizontal portion.
  • the present invention provides a pressure control means that can operate reliably at downhole temperatures and pressures. The cost and difficulty of doing this is believed to be more than offset by the advantages in terms of energy savings in production.
  • the pressure regulating valve of the preferred aspect of the present invention is intended to be very robust and simple.
  • the piston automatically seeks a position somewhere along the flow spool that balances the pressure on both upstream and rear sides of the piston. This position provides the exact orifice opening that is necessary to achieve the desired pressure differential. In turn, this ability to control the drawdown pressure differential between the reservoir and the horizontal wellbore will allow the pressure differential to be optimized from an oil production and cost point of view.
  • This valve design is tolerant to some types of damage. For example, if cavitation and erosion enlarge the physical dimensions of the orifice, then the piston will seek a new position that still balances the pressures.
  • the piston will automatically seek a new and appropriate position to balance the pressures.
  • the control action of the pressure control valve is tolerant to changes and/or uncertainties in the fluid characteristics.
  • the valve is tolerant to changes in temperature. If the fluid temperature changes due to inflow of warmer or cooler fluids, then the valve will continue to seek a position that balances the pressures. For example, if cool (i.e. viscous) bitumen was passing through the valve driving up the pressure differential across the valve itself, then the piston will automatically seek a more open position exposing more of the orifice to try to reduce the pressure difference. Similarly the piston will automatically seek a new position that reduces the exposed portion of the orifice, if the bitumen temperature rises and it flows to such an extent that the pressure difference drops.
  • cool i.e. viscous
  • Figure 8 shows the expected relationship between the pressures at various locations as a function of time for sample SAGD process.
  • the chamber 18 pressure is steady at 1.8 MPa.
  • the pressure at location 43 immediately upstream of regulating valve 42 is steady at 1.83MPa, which is 30kPa above the pressure in the chamber 18 due to the horizontal portion of the wellbore 39 being submerged under several meters of liquid.
  • Figure 8 shows the pressure at the wellhead at surface 50 is fairly steady at 1.1 MPa. However the bottomhole pressure at location 72, immediately downstream of valve 42 cycles between 1400kPa and 1800kPa due to geysering in the vertical portion of the well.
  • the dashed arrow 100 in Figure 8 shows the pressure difference between the wellhead and the outlet of the pressure control valve is 300kPa.
  • the solid arrow at t1 shows a pressure drop of 430kPa across the valve 42 (i.e. between the valve inlet 43 and the valve outlet 72), These pressure differences are constantly changing as a result of the geysering process. This is illustrated by the arrows 100' and 1 10' at t2 several minutes later.
  • the pressure drop in the vertical portion of the wellbore has increased to 500kPa as liquid holdup accumulates in the vertical portion of the wellbore prior to the next geysering event.
  • This increased pressure drop in the vertical portion of the well is exactly offset by the pressure control means 42 to maintain a constant pressure differential between the chamber and the inlet portion of the horizontal wellbore.
  • the pressure difference in this example across the control valve 42 has shrunk to 230 kPa at time t2, and will eventually be reduced to 30kPa just before the next geyser event.
  • the pressure drop across valve 42 will briefly return to 430KPa when the geyser has unloaded the maximum amount of liquid from the vertical wellbore and the cycle will start over again.
  • the upstream pressure in the inlet portion of the horizontal production well is maintained at the desired value through the entire geyser cycle.
  • Figure 9 shows the expected relationship between drawdown and oil rate and steam oil ratio.
  • Drawdown being defined as the pressure difference between the chamber 18 as measured by sensor 30 and the inlet to valve 42 as measured by pressure sensor 40, or in other words the drawdown being chamber pressure minus horizontal well inlet pressure.
  • drawdown is too negative (i.e. the pressure in the horizontal section is too high) there will be no flow into the horizontal wellbore.
  • the maximum oil production rate is achieved, and additional increases in drawdown do not produce oil more rapidly. This is because the oil production rate is limited by heat delivery and oil mobilization within the SAGD chamber so excess drawdown at the production well does not increase the oil production rate.
  • Figure 9 also shows that the steam oil ratio is a minimum at low drawdown. However as the drawdown increases, the amount of steam vapour short circuiting from the chamber will increase. In the example of Figure 9 a drawdown of 200kPa will increase the steam oil ratio from about 1.5 to 3.
  • the pressure responsive inlet flow control device of the present invention can be set to prevent steam or vapour production or venting or could be set to allow some venting. In this way the vapour composition of the chamber could be varied or controlled to a certain extent.
  • a preferred maximum drawdown pressure is 100kPa, a more preferred drawdown is 50 kPa and the most preferred drawdown is within 25 kPA of no drawdown.
  • a 400 kPa geyser cycle as shown in Figure 8 corresponds to an average drawdown of 200kPa.
  • the average drawdown would be 200kPa and the steam consumption would be 3 m3/m3 or twice as high as the 1.5 m3/m3 economic optimum.
  • the economic optimum is shown as the region between the arrows 120, 130 in Figure 9. This region has sufficient drawdown to ensure maximum oil production rate so there is no risk of liquid accumulation and flooding in the chamber, but minimum steam leakage rate so the steam energy is used most efficiently.
  • the present invention permits the relationship illustrated in Figure 9 to be determined individually for each production well in a controlled and systematic manner so the economic optimum drawdown can be correctly identified and reliably achieved.
  • Geysering and uncontrolled drawdown can also lead to excessive water production by way of water coning into the horizontal well.
  • the present invention teaches preventing large and uncontrolled drawdowns that encourage undesired fluids such as steam, gas or water to leak into the production well by controlling the pressure within the production well between the inlet horizontal portion and the upward vertical leg. At modest drawdown, the steam leakage or water or gas coning can be minimized, while still achieving the maximum oil production that the SAGD chamber can deliver.
  • Another means according to the present invention to limit pressure oscillations due to geysering is by the use of a pressure controlled pump to raise and maintain the pressure in the vertical portion of the wellbore above the saturation pressure for steam at the wellbore temperatures.
  • a pressure controlled pump to raise and maintain the pressure in the vertical portion of the wellbore above the saturation pressure for steam at the wellbore temperatures.
  • Such a raised pressure prevents flashing in the vertical portion of the wellbore and consequently limits erratic backpressure arising in the horizontal portion of the production well.
  • This is a less preferred embodiment because a very slight mismatch between the pump rate and the oil drainage rate from the chamber can lead to either a very large pressure differential or flooding in the chamber. If the suction pressure gets too high, fluid withdrawal rate from the chamber will be insufficient and liquid will accumulate in the chamber instead of being drained.
  • the pump has a pumping rate controlled by a pressure difference measured between the horizontal section of the wellbore and the chamber (instead of a sub-cool temperature).
  • Another embodiment includes a pressure control valve followed by a downhole pump, which would be appropriate if the natural lift was insufficient to properly produce the reservoir and pump control based on suction pressure was not precise enough to be able to regulate the drawdown pressure.
  • a submersible pump in combination with a flow control valve located at the wellhead to prevent flashing in the vertical wellbore, the control valve being used to provide more precise flow regulation by raising and lowering the pressure head across the pump to maintain a desired pressure difference between the pump inlet and the chamber.
  • Another embodiment includes an oversized pump with a flow bypass valve at the wellhead which returns a portion of the liquid production back into the well via the casing tubing annulus in order to maintain a desired pressure setpoint i.e. the desired pressure of the pump inlet in the horizontal section of the wellbore.
  • the present invention also comprehends that one pump may not be adequate for the entire production cycle (startup through full production).
  • the invention is intended to comprehend many different completion arrangements, for example, there may be multiple tubing strings, or there may be a packer to seal off the annulus from flow similarly, the completion may use artificial lift or natural lift.
  • the key feature is a precise and accurate control of the pressure within the horizontal leg of the production well and/or control of the pressure drawdown between the horizontal leg and the chamber or reservoir.
  • the pressure in chamber 18 may be substantially invariant. This might allow the control system logic to be simplified with an emphasis on controlling the pressure in the horizontal leg of the production well rather than controlling the pressure difference.
  • This invention is applicable to many horizontal well applications where gravity drainage is employed to encourage oil recovery and discourage the production of other unwanted fluids.
  • gravity drainage is employed to encourage oil recovery and discourage the production of other unwanted fluids.
  • it is very desirable to prevent water coning. This phenomenon arises due to excessive drawdown, which lifts the higher density bottom water upwards into the oil saturated portion of the reservoir. The problem is exacerbated because the mobility of water is high relative to most native oils.
  • This invention further comprehends using the data collected to determine changes over time in the underground formation. For example, if pressure measurements 30 are available at several elevations in the observation well 28 then the liquid level in the vicinity of that well can be detected with great accuracy and precision.
  • This liquid level data in combination with a measured production flowrate and wellbore pressure in the horizontal wellbore can be used to measure and characterize the severity of skin damage. Skin damage, perhaps arising from fines movement and or from scale deposition or some other phenomena that obstructs the flow path into the wellbore can be detected and tracked over time and corrective steps taken to mitigate the problem when economically opportune to do so.
  • the present invention also comprehends continuous monitoring of the pressure difference between transducer 30 and transducer 40 and using the fluid production rates as measured at the SAGD facility to monitor skin damage in the horizontal leg of the production well. If the pressure difference was invariant because it was specified by the operator, then increasing formation damage will be evident as either reduced fluid production rates or increasing submergence in the chamber.
  • the present invention will limit vapour escaping the underground formation. In gravity drainage processes this may result in the accumulation in the chamber of noncondensable gases.
  • the present invention also comprehends being able to vent, in a controlled manner, any such accumulations of noncondensable gases or other vapours which can accumulate within the formation and which can impair the effectiveness of the extraction process. For example, venting could be achieved through observation wells, through controlled circulation of the gases within the chamber or through selective operation of the inlet flow control devices as required.

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Abstract

Cette invention concerne un procédé d'extraction d'hydrocarbures fluides à partir d'un réservoir souterrain par l'intermédiaire d'un puits généralement horizontal comprenant une partie d'admission en communication avec une zone productive de ladite formation, ainsi qu'une partie formant tube prolongateur qui s'étend à partir de la partie d'admission dans ledit réservoir souterrain, vers la surface. La formation souterraine comprend au moins un autre fluide en dehors desdits hydrocarbures fluides. Le procédé de l'invention comprend l'utilisation d'au moins un dispositif de régulation de débit d'entrée réagissant à la pression, dans le puits d'extraction horizontal entre ladite partie d'admission et ladite partie formant tube prolongateur. Ledit procédé comprend en outre l'étape consistant à réguler une différence de pression entre un côté amont du dispositif de régulation de débit d'entrée réagissant à la pression et le réservoir souterrain au moyen du dispositif de régulation de débit d'entrée réagissant à la pression. Le procédé comprend enfin l'étape consistant à permettre l'extraction préférentielle desdits hydrocarbures fluides par rapport audit autre fluide. L'invention concerne en outre un appareil formant dispositif de régulation de débit d'entrée réagissant à la pression.
PCT/CA2011/000708 2010-06-16 2011-06-16 Procédé et appareil d'extraction préférentielle de fluides à partir de puits horizontaux WO2011156907A1 (fr)

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CA2639851C (fr) 2008-09-26 2016-01-05 Nsolv Corporation Methode de regulation de l'augmentation et de la perte de chaleur d'une chambre de drainage par gravite in situ grace a un procede de condensation par solvant
CA2972203C (fr) 2017-06-29 2018-07-17 Exxonmobil Upstream Research Company Solvant de chasse destine aux procedes ameliores de recuperation
CA2974712C (fr) 2017-07-27 2018-09-25 Imperial Oil Resources Limited Methodes ameliorees de recuperation d'hydrocarbures visqueux d'une formation souterraine comme etape qui suit des procedes de recuperation thermique
CA2978157C (fr) 2017-08-31 2018-10-16 Exxonmobil Upstream Research Company Methodes de recuperation thermique servant a recuperer des hydrocarbures visqueux d'une formation souterraine
CA2983541C (fr) 2017-10-24 2019-01-22 Exxonmobil Upstream Research Company Systemes et methodes de surveillance et controle dynamiques de niveau de liquide

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US6257334B1 (en) * 1999-07-22 2001-07-10 Alberta Oil Sands Technology And Research Authority Steam-assisted gravity drainage heavy oil recovery process

Patent Citations (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6257334B1 (en) * 1999-07-22 2001-07-10 Alberta Oil Sands Technology And Research Authority Steam-assisted gravity drainage heavy oil recovery process

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