METHODOLOGY AND SYSTEM FOR PRODUCING FLUIDS FROM A CONDENSATE GAS RESERVOIR

FIELD

This case relates to wells that produce gas and condensate.

BACKGROUND

Condensate blocking is a common problem in gas wells. The techniques used to cope with this problem can include fracturing, drilling new wells, injecting solvents, etc. It is well known that the pressure and temperature play an important role in the phase behavior of a compound; variation of these parameters can cause the compound to transition between gas phase, liquid phase, and solid phase.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

According to one aspect, a method of producing reservoir fluids from a condensate gas reservoir traversed by a production well includes forming at least one protrusion into natural gas bearing rock along a producing interval of the production well. The protrusion extends in a radial direction away from the central axis of the production well into the natural gas bearing rock, and the protrusion is configured to receive a heater element. The heater element is placed into the protrusion and configured for operation by surface located equipment. While producing reservoir fluids from the producing interval of the production well, the respective heater element is operated to heat the natural gas bearing rock that is proximate the heater element. The heat supplied by the heater element reduces buildup of condensate in the natural gas bearing rock adjacent the producing interval of the production well during the production of reservoir fluids from the producing interval.

In one embodiment, the heater element is configured to heat the natural gas bearing rock that is proximate the heater element to a temperature that is sufficient to vaporize and/or reduce the viscosity of condensate that is proximate the heater element. The protrusion can be formed by a device selected from the group consisting of a perforation gun, a high power laser, a casing drilling instrument, and a directional drilling tool. The protrusion may also be formed by any other desirable means.

In one embodiment, the reservoir fluids are produced through at least one perforation in a casing. The at least one perforation can extend into the natural gas bearing rock along the producing interval of the production well. The at least one perforation provides fluid communication between the natural gas bearing rock and the producing interval of the production well.

In one embodiment, a perforation in a casing is located above and proximate to an associated protrusion for a respective heater element. The heat supplied by the respective heater element can vaporize condensate to form a gas that flows to the associated perforation for production of the gas therethrough. The heat supplied by the respective heater element can also reduce the viscosity of liquid phase condensate that is proximate the heater element to promote the flow of the liquid phase condensate to the associated perforation for production of the liquid phase condensate gas therethrough.

The at least one perforation can be formed by a device selected from the group consisting of a perforation gun, a high power laser, a casing drilling instrument, and a direction drilling tool. The at least one perforation can be formed or enhanced by hydraulic fracturing.

In another method embodiment, the heater element is supplied with heat from an external heat source and transfers the heat into the gas bearing rock matrix that is proximate to the heater element.

The method can further include injecting metal nanoparticles into the gas bearing rock in the vicinity of the heater element to promote localized heating of such gas bearing rock. The metal nanoparticles are injected into the gas bearing rock in an area where condensate forms or is likely to form during production.

The method can also include monitoring operations, such as monitoring the flow rate of produced reservoir fluids, monitoring temperature and/or pressure of the condensate reservoir as a function of location along the producing interval, and monitoring temperature and/or pressure of the condensate reservoir in the vicinity of the heater element as a function of radial offset away from the producing interval.

In another aspect of the present application, a system for producing reservoir fluids from a condensate gas reservoir traversed by a production well includes at least one heater element that is configured for disposition inside a respective protrusion into natural gas bearing rock along a producing interval of the production well. The protrusion and corresponding heater element extend in a radial direction away from the central axis of the production well into the natural gas bearing rock. Equipment, surface located, is configured to operate the at least one heater element. The heater element is configured to heat the natural gas bearing rock that is proximate the heater element. Heat supplied by the heater element reduces the buildup of condensate in the natural gas bearing rock adjacent the producing interval of the production well during the production of reservoir fluids from the producing interval. In one embodiment, the heater element is configured to heat the natural gas bearing rock that is proximate the heater element to a temperature that is sufficient to vaporize and/or reduce the viscosity of condensate that is proximate the heater element.

The protrusion for a respective heater element can be located below and proximate to at least one perforation in a casing that can extend into the natural gas bearing rock along the producing interval of the production well. The perforation provides fluid communication between the natural gas bearing rock and the producing interval of the production well. The heat supplied by the respective heater element can vaporize condensate to form a gas that flows to the perforation for production of the gas therethrough. The heat supplied by the respective heater element can also reduce the viscosity of liquid phase condensate that is proximate the heater element to promote the flow of the liquid phase condensate to the perforation for production of the liquid phase condensate gas therethrough.

In one embodiment, the heater element is realized by a resistive heater element.

In another embodiment, the heater element is realized by an antenna that directs electromagnetic radiation into the natural gas bearing rock. A downhole source of electromagnetic radiation can be provided (in the producing interval of the production well) together with cables or a waveguide that supplies the electromagnetic radiation generated by the source to the antenna.

In yet another embodiment, the heater element is supplied with heat from an external heat source and transfers the heat into the gas bearing rock matrix that is proximate to the heater element.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a phase diagram of a typical gas condensate.

FIG. 2 is a cross sectional view of a gas condensate reservoir traversed by a vertical gas producing well.

FIG. 3 shows the pressure measurements of a production well for a sequence of first draw down cycle (labeled “1DD”) followed by a first build up cycle (labeled “2BU”) followed by a second drawn down cycle (labeled “3DD”) followed by a second build up cycle (labeled “4BU”).

FIGS. 4A and 4B are graphs of condensate saturation (the percent of formation porosity filled with condensate) for gas condensate reservoirs, where the condensate saturation is plotted against radius into the respective formation.

FIG. 5 is a flow chart outlining a methodology for producing reservoir fluids from a condensate gas reservoir.

FIG. 6 is a schematic diagram of a condensate gas production well that employs the condensate heating methodology of FIG. 5.

FIG. 7 is a schematic diagram that illustrates the heating profile of the heater element of FIG. 6.

FIG. 8 is a schematic diagram of a condensate gas production well that carries out monitoring operations in conjunction with the condensate heating methodology of FIG. 5.

DETAILED DESCRIPTION

FIG. 1 shows the phase diagram of a typical gas condensate (also called retrograde gas). This diagram shows how gas condensate can transition back and forth between gas phase and liquid phase. Point 1 in FIG. 1 corresponds to a gas phase. The line from point 1 to 3 is an isotherm wherein the temperature is kept constant while the pressure is reduced. When the pressure becomes equal to that of point 2 (on the saturation line), liquid starts to form and coexist with the gas phase. Continuing to reduce the pressure, as indicated by point 3, further liquid is formed. Point 2 is referred to as the dew point or condensation point if it is located above the critical point, and is referred to as the bubble point if it is located below the critical point.

Reservoir hydrocarbons are a mixture of different hydrocarbon species that are present as either a liquid phase or gaseous phase depending on location from the critical point at the saturation line. For natural gas reservoirs, the industry distinguishes between two different types, dry gas reservoirs and condensate gas reservoirs (also referred to wet gas reservoirs). Dry gas reservoirs contain more than 90% methane and traces of C₂-C₅which will remain in the gas phase for all practical cases. The dry gas reservoirs do not produce condensates. Condensate gas reservoirs are composed of C₁to C₁₂hydrocarbon species (where Ci is a hydrocarbon with i carbon atoms and the corresponding hydrogen atoms). Since the hydrocarbon species with carbon numbers greater than 4 have the potential of liquefying, the gas components with Cn (n>4) from these reservoirs can condense into liquid under the appropriate temperature and pressure; thus, the name condensate gas (or wet gas). Condensate gas reservoirs normally have high enough temperature and pressure that, before the production starts, all components are in the single (gas) phase. Once production starts, it causes the pressure to decline, causing the temperature and pressure to touch the saturation line, as shown in point 2 of FIG. 1. As a result, the gas begins to condense and liquid begins to form. At this point, the heaviest component of fluid mixture constitutes the liquid phase. At point 2, vapor and liquid coexist within the two phase region of the phase envelope. Further pressure reduction causes the next heavier component to liquefy, and this is followed by the next heavy component, etc. The majority of the produced fluid is typically gas; generally a gas condensate reservoir produces less than 25% liquid condensate. The liquid dropout (condensate) does not flow as fast as the gas and falls behind. As this trend continues the volume of condensate increases and can interfere with gas production.

FIG. 2 is a cross sectional view of a gas condensate reservoir traversed by a vertical gas producing well, where production from the well has resulted in build-up of condensate at the bottom of the reservoir. The condensate is expected to build up from the bottom because as a liquid it has higher density than the gas phase. It is common to divide part of the reservoir close to the production well into three cylindrical zones (zone 1, zone 2 and zone 3) as shown in FIG. 2. Zone 3, which is far away from the well, is the unperturbed reservoir and is characterized by a single (gas) phase. In this zone the gas pressure and temperature are above the dew point preventing any phase change. Unless any liquid has been present initially, there will not be any condensate or liquid formed as a result of production (yet). This is in contrast with zones 2 and 1 wherein the temperature and pressure are such that the system is already below the dew point and two phases (liquid and gas) coexist. As more and more gas is produced, the pressure drops and the boundaries between the zones shift. In the intermediate zone 2, only the gas flows while the condensate remains low but stagnant. In zone 1, which is adjacent to the borehole wall, both condensate and the gas flow, although the condensate flows at a slower rate, and accumulates as a function of time. The condensate volume in zone 1 reduces the flow rate of the gas and eventually can completely block the flow of the gas into the well.

Details about these zones and the reservoir can be obtained from pressure measurements on the well. FIG. 3 shows the pressure measurements for a sequence of a first draw down cycle (labeled “1DD”) followed by a first build up cycle (labeled “2BU”) followed by a second drawn down cycle (labeled “3DD”) followed by a second build up cycle (labeled “4BU”). During the first and second build up cycles, the production is stopped (usually completely) leading to a pressure increase. The well is kept at that condition for a period of time to allow all zones to come to an equilibrium state. During the first and second drawn down cycles, production occurs from the well, which causes the pressure to drop. The pressure variation over time can be analyzed to determine the reservoir properties.

For example, it is common to analyze the pressure measurements obtained from a sequence of draw down cycles and build up cycles (such as the sequence of FIG. 3) to characterize the size of the reservoir, the pressure at different zones, the size of different zones, etc. Two such results are shown in FIGS. 4A and 4B where the condensate saturation (the percent of formation porosity filled with condensate) is plotted against radius into the formation. In these figures, far enough away from the borehole (about 40 ft in FIG. 4A, and about 100 ft in FIG. 4B—note the logarithmic x axis) the liquid saturation goes to zero marking the boundary for Zone 3. The boundary between zones 1 and 2 is assigned based on an abrupt change of slope in saturation which is at about 5 ft for FIG. 4A and at about 20 ft for FIG. 4B. The different saturation behavior for the draw-down and build up cycles are also seen to happen mostly at depth closer to the borehole (Zone 1). As expected, during draw-down, gas is produced and more condensate is formed. In FIG. 4A there is an increase in liquid saturation from 0 to 1 foot into the borehole (compared draw-down DD5 to buildup BU6) while the remainder of zone 1 stays unchanged. Similarly, in FIG. 4B there is an increase in liquid saturation in Zone 1 and to a lesser extent in Zone 2 for the draw-down as compared to the buildup. In both Figures the liquid saturation is larger at radial distances closer to the borehole. These observations are consistent with more condensate being formed closer to the borehole wall. The measurements of FIGS. 4A and 4B also imply that to the extent that condensate is formed in zone 3, it will be produced closest to the well. This is expected since the pressure drop between the reservoir and the borehole is greatest in that region. However, with time, the condensate redistributes along this zone causing the average level to go up along the entire length of zone 3 (see FIG. 4B). Turning to FIG. 5, there is shown a method for producing reservoir fluids from a condensate gas reservoir. The method begins in step 101 by drilling a borehole that traverses the condensate gas reservoir. The borehole can be vertical, multi-lateral or horizontal. The condensate gas of the reservoir is a single-phase fluid at original reservoir conditions. It consists predominantly of methane and other short chain hydrocarbons, but it also contains long chain hydrocarbons, termed heavy ends. Under certain conditions of temperature and pressure, this fluid will separate into two phases, a gas and liquid that is called a retrograde condensate. As a reservoir produces, pressure decreases. The largest pressure drops occur near the producing well. When the pressure in the condensate gas reservoir decreases to a certain point, called the saturation pressure or dewpoint, a liquid phase rich in heavy ends drops out of solution and the gas phase is slightly depleted of heavy ends. A continued decrease in pressure increases the volume of the liquid phase up to a maximum amount. Pressure decreases beyond this point decrease liquid volume.

In step 103, the borehole is cased. Typically, the casing includes multiple intervals of casing successively placed within the previous casing run. Cement can fill the annulus between the casing and the borehole for stability and sealing the rock formations containing liquids or gases. The casing includes production casing that extends to a producing interval of the borehole that traverses the condensate gas reservoir.

In step 105, the producing interval of the borehole is completed to allow for inflow of condensate gas at one or more locations along the producing interval. The completion of step 105 can be an open hole completion (where no casing or liner is cemented in place across the producing interval), a cased hole completion (where a casing or a liner extends through the producing interval and is cemented in place) or other suitable well completion.

The common options for open hole completions for condensate gas wells are pre-holed liners (also often called pre-drilled liners) or slotted liners. The pre-holed liner is prepared with multiple small drilled holes, and set across the producing interval to provide wellbore stability and an intervention conduit. The slotted liner is machined with multiple longitudinal slots, for example 2 mm×50 mm, spread across the length and circumference of each joint. The open hole completions can be combined with open hole packers, such as swelling elastomers, mechanical packers or external casing packers, to provide zonal segregation and isolation. Multiple sliding sleeves can also be used in conjunction with open hole packers to provide considerable flexibility in zonal flow control for the life of the well.

For cased hole completions, connection between the annulus of the production casing and the formation is made by perforating. Because the perforations can be precisely positioned, this type of completion affords good control of fluid flow, although it relies on the quality of the cement to prevent fluid flow behind the casing/liner. The perforating can be accomplished by a perforating gun that is positioned as desired in the annulus of the production casing. The gun carries shape charges that are detonated to punch a pattern of perforations through the production casing and surrounding cement into the gas-bearing rock matrix that surrounds the casing. Typical perforating guns can form perforations that extend radially into the rock matrix, typically in a range of 6 inches to 20 inches in length relative to the outer wall of the production casing. It is also contemplated that the perforating can be accomplished by other means, such as with high power laser energy (possibly in conjunction with liquid jet pulses). The cased hole completions can be combined with cased hole packers to provide zonal segregation and isolation.

As part of step 105, the perforation into the rock matrix adjacent the producing interval can be formed (or enhanced) utilizing hydraulic fracturing where the fracturing fluid is supplied to the rock matrix at pressures that exceed that of the fracture gradient of the rock matrix. The fracture gradient is defined as the pressure required to induce fractures in rock matrix at a given depth and is usually measured in pounds per square inch per foot or bars per meter. The pressurized fracturing fluid flows through holes or voids in the production casing causing the rock to crack, and the fracture fluid continues farther into the rock matrix, extending the crack still farther, and so on. Operators typically try to maintain “fracture width,” or slow its decline. A proppant (such as grains of sand, ceramic, or other particulates) can be introduced into the fracture. The proppant is intended to prevent the fracture from closing when the injection is stopped and the pressure of the fracturing fluid is reduced. The fracturing fluid can include an acid (typically hydrochloric acid). The acid tends to etch the fracture faces in a non-uniform pattern, forming conductive channels that remain open without a propping agent after the fracture closes.

In an alternate embodiment, as part of step 105, the perforation into the rock matrix adjacent the producing interval can be formed by other suitable methods. For example, a casing drilling instrument (such as the Cased Hole Dynamics Tester offered commercially by Schlumberger) can be used to form a perforation into the rock matrix adjacent the producing interval. The Cased Hole Dynamics Tester can be delivered to the location of interest, anchored, and a drill bit from the tool body is used to drill into the casing (if presented) and formation. In another example, a direction drilling tool (such as the Extreme tool offered commercially by Schlumberger) can be used to form a perforation (lateral branch) into the rock matrix adjacent the producing interval of the borehole. The directional drilling can also be done by coiled-tubing as is well known in the industry. These techniques offer flexibility in the diameter and depth of the perforation.

The perforation of step 105 extends into the rock matrix in a radial direction away from the central axis of the borehole of the well and promotes migration of natural gas from the rock matrix into the well annulus for production. It is also contemplated that such perforation can be treated with an acid. For carbonate rock matrix, the acid can dissolve the matrix to extend the length of the perforation.

The perforation operations of step 105 can be performed at different radial directions for a given producing location adjacent the natural gas bearing rock matrix. The perforation operations of step 105 can also be carried out at multiple locations that are separated from one another along the central axis of the borehole of the well.

In step 107, at a location proximate the production location(s) of step 105, a heater protrusion is formed into the rock matrix. The heater protrusion can be formed by a perforating gun that is positioned as desired in the annulus of the well. The gun carries a shape charge that is detonated to punch a perforation (through production casing and surrounding cement, if present) into the adjacent gas-bearing rock matrix. Typical perforating guns can form perforations that extend radially into the rock matrix in a range of 6 inches to 20 inches in length relative to the outer wall of the production casing, although this application is not limited thereto. In the event that the section of interest is not cased by steel casing and cement, the shape charge does not have to penetrate through the steel casing and cement, and the energy of the shape charge will penetrate even deeper into the rock matrix beyond 20 inches. It is also contemplated that the heater protrusion can be formed by other means, such as: a high power laser energy (possibly in conjunction with liquid jet pulses); a casing drilling instrument (such as the Cased Hole Dynamics Tester offered commercially by Schlumberger), where the Cased Hole Dynamics Tester can be delivered to the location of interest, anchored, and a drill bit from the tool body can be used to drill into the casing (if presented) and formation; and a direction drilling tool (such as the Extreme tool offered commercially by Schlumberger) that can be used to form the heater protrusion (lateral branch) into the rock matrix (the directional drilling can also be done by coiled-tubing as is well known in the industry.) These techniques offer flexibility in the diameter and depth of the heater protrusion.

The heater protrusion of step 107 extends into the rock matrix in a radial direction away from the central axis of the borehole of the well. The heater protrusion 107 is sized to receive a heater element as described below with respect to step 109. In one embodiment, the heater protrusion extends from the borehole in a direction parallel to that of the proximate production perforation of step 107.

The operations of step 107 can be performed at different radial directions for corresponding perforations that extend into the matrix as a result of step 105. The operations of step 107 can also be carried out at multiple locations in or adjacent the producing interval that is separated from one another along the central axis of the borehole of the well for corresponding production perforations that result from step 105.

In step 109, a heater element is placed into the heater protrusion formed in step 107, and the heater element (or support equipment for the heater element) is coupled to surface control equipment. In one embodiment the heater element operates under control of the surface control equipment to heat the adjacent rock matrix to a temperature that mobilizes (and/or vaporizes) condensate near the producing interval of the well in order to limit the buildup of condensate near the producing interval of the well. The operations of step 109 can be repeated for multiple heater elements to place and configure the multiple heater elements in the heater protrusion formed in step 107.

The heater element of step 109 can be realized by a ruggedized resistance heating element suitable for the downhole environment. The resistance heating element can be energized by electrical energy generated by the surface control equipment and supplied to the heater element by conductors that extend therebetween. The conductors can pass down through completion pipe or through a dedicated completion pipe. It is also possible to place the conductors in a small metal tube on the outside of the casing inside the surrounding cement zone.

In an alternate embodiment, the heater element of step 109 can employ electromagnetic radiation to heat the adjacent rock matrix. This technology employs a downhole source of electromagnetic radiation (for example, a magnetron), a waveguide or cable (depending on the frequency) to deliver the electromagnetic radiation to an antenna (such as horn or dipole antenna) that is positioned in the heater protrusion. The antenna radiates the energy into the adjacent rock matrix to heat the adjacent rock matrix. The downhole source can be placed inside the annulus of the well (in the producing interval in close proximity to the antenna) and controlled by surface control equipment via conductors that extend therebetween. The conductors can pass down through completion pipe or through a dedicated completion pipe. It is also possible to place the conductors in a small metal tube on the outside of the casing inside the surrounding cement zone.

Electromagnetic heating has the advantage that with proper design of the antenna, the energy can be directed to the direction of interest. For example, the energy can be directed to the end of the heater protrusion such that it penetrates beyond the physical size of the heating protrusion. Alternatively, it can be directed above or below the heater protrusion if desired. The frequency of the electromagnetic energy is another parameter that can be advantageously used. When the electromagnetic radiation enters a medium such as a rock, its intensity decreases exponentially as a function of travel distance into the rock matrix. Thus, the depth of penetration is defined as the depth into the medium wherein the intensity has reduced to 1/e of the initial intensity, where e=2.7 is the base of natural logarithm. This depth of penetration (δ) is known as the skin depth and is given by the following equation:

$\begin{matrix} δ = \sqrt{\frac{2}{2 π f σ μ}} & Eqn . (1) \end{matrix}$

where f is the frequency, σ is the conductivity of the medium, and μ is the magnetic permeability (which for normal rocks is equal to that of free space).

As the equation shows, lowering the frequency increases the skin depth and one can use the electromagnetic radiation to heat the rock matrix at a greater distance from the heater protrusion.

Metal particles have a large cross section for absorbing the electromagnetic radiation produced by the antenna. This causes a metal particle that is in the field of the antenna to preferentially absorb the radiation such that is gets hotter than its environment. Use of metal particles is one way of concentrating the heat and creating locally higher temperatures compared to the surrounding medium. Note that the amount of energy is not changed, but it is distributed differently.

In one embodiment, metal particles are injected into the rock matrix in an area where condensate forms (or is likely to form) during production. Metal particles have a large cross section for absorbing the electromagnetic radiation produced by the antenna. This causes a metal particle that is in the field of the antenna to preferentially absorb the radiation such that is gets hotter than its environment

Where metal particles are injected into the rock matrix, the metal particles are distributed over the area of condensate formulation in a uniform manner and operate to absorb the electromagnetic energy emitted by the antenna and raise the temperature locally, thus serving as the local hot points with higher temperature than the surroundings. The high temperature of the metal particles induced by the electromagnetic energy emitted by the antenna can aid in vaporizing condensate. The gas can form gas pockets that can push the remaining condensate to the producing interval of the well. This process is specifically effective in positions far enough away from the antenna that the average heating temperature is below the temperature that vaporizes the condensate.

The metal particles should be small enough to pass through the rock pore size. In one embodiment metal particles having sizes in the nano-meter range (so called nanoparticles) are utilized. There are well-known methods of generating these particles. The particles can be made in a distribution of sizes so that they penetrate different throat sizes. The metal nanoparticles can be treated with one or more bonding agents that help them to attach to the pore walls of the rock matrix. For pore walls that are oil wet, such bonding agents can include an organic group that preferentially bonds to the oil wet pore walls. For pore walls that are water wet, such bonding agents can include polar groups (such as carboxylates, for example) that preferentially attach to the water wet pore walls. In operation, the wettability of the pore walls of the rock matrix is measured and based on this measurement one or a combination of these particles are introduced into the rock matrix. By way of example only, the interval of interest can be isolated by two packers and a solution containing these solubilized metal particles can be introduced in the isolated interval at a pressure that is higher than the formation pressure. The excess pressure pushes the particles into the rock matrix where they bond to the pore wall. The pressure is then removed allowing the formation fluid to flow normally.

The metal particles can also concentrate heat from other heating methods. For example if a resistive heating element is used to generate the heat, the dispersed metal particles can concentrate heat and aid with condensate vaporization. Thus, the metal particles are not limited to electromagnetic heating although they can be more efficient when used in conjunction with electromagnetic heating.

The heater element of step 109 can also be a heat exchanger or other suitable heat conducting element that distributes heat generated by other means, such as steam generated at the surface and supplied to the heat exchanger, steam generated by a downhole steam generator, or heat generated by a downhole combustor (for example, oxygen gas can be delivered downhole to the combustor and used to burn some of the gas or condensate that is produced by the well).

In step 111, production tubing is installed that extends from the producing interval to the wellhead.

In step 113, the production tubing is used to produce natural gas (and possibly condensate) from the completed producing interval of the well while concurrently using the surface control equipment to operate the heater element(s) to heat the adjacent rock matrix to a temperature that mobilizes (and/or vaporizes) condensate near the completed producing interval of the well in order to limit buildup of condensate near the completed producing interval of the well. The heater element can be controlled by a device located in the vicinity of the production zone. In this case one of the production parameters, such as the rate of gas or condensate production is monitored and is compared with a target value. This can be done by having a microprocessor or a similar device located downhole. Based on the comparison, the device may increase or decrease the current into the heater element(s). For example if the gas production rate is the parameter of interest and the measurement shows a decreased rate compared to the target value, it implies that the extent of heating is not sufficient and more current needs to be supplied to the heater element. This adjustment can be done by the downhole device (not shown).

In one embodiment, the heater element is adapted to heat the adjacent rock matrix to a temperature that vaporizes condensate near the producing interval of the well. This effect is shown graphically in FIG. 1 where the liquid phase condensate of point 3 is heated to cause a horizontal shift. Heating to point 4 causes the condensate to vaporize into a gas phase all the way to the dew-point line where there is almost zero liquid drop-out. Heating to a lesser temperature (such as point 5 along this line) causes the liquid condensate to vaporize to the gas phase while allowing some remaining liquid phase condensate (about 6%). Once gas is generated, it will flow in the direction of low pressure, which in this case, is the completed producing interval of the well. In addition to vaporization, the temperature increase can also reduce the viscosity of the liquid phase condensate, thus improving the mobility of the liquid phase condensate and causing it to flow into the completed producing interval of the well. Both these mechanisms reduce the amount of condensate and help increase the gas flow rate.

FIG. 6 shows a condensate gas production well with a production casing 201 that lines a production interval 203 of a borehole that traverses a gas-bearing rock matrix 205. The production casing 201 includes a protrusion 207 into the gas-bearing rock matrix 205 adjacent the producing interval 203 as described above with respect to step 105. The protrusion 207 extends into the rock matrix 205 in a generally radial direction away from the central axis of the borehole and promotes migration of natural gas and possibly condensate from the rock matrix 205 into the well annulus for production. The production casing 201 also includes a heater protrusion 209 that is located proximate to the protrusion 207. The heater protrusion 209 extends into the rock matrix 205 in a radial direction away from the central axis of the borehole (e.g., in a direction substantially parallel to that of the proximate production protrusion 207). The heater protrusion 209 is sized to receive a resistive heater element 211 as described above with respect to step 109. The resistive heater element 211 is operated under control of the surface (or downhole) control equipment 213 to heat the adjacent rock matrix 205 to a temperature that mobilizes (and/or vaporizes) condensate near the producing interval of the well in order to limit the buildup of condensate near the producing interval of the well. Production tubing (not shown) extends from the producing interval to the wellhead (not shown). The production tubing is used to produce natural gas (and possibly condensate) from the producing interval of the well while concurrently using the surface control equipment 213 to operate the heater element 211 to heat the adjacent rock matrix 205 to a temperature that mobilizes (and/or vaporizes) condensate near the completed producing interval 203 of the well.

FIG. 6 also shows a graph that depicts the level of condensate as a function of position in the rock matrix 205 relative to the heater protrusion 209 for the case where the heater element 211 is not used to heat the rock matrix 205 as well as the case where the heater element 211 is used to heat the rock matrix 205. The heating of the rock matrix 205 is sufficient to cause condensate to vaporize into gas. Once gas is generated, it will flow in the direction of low pressure, which in this case, is the producing interval 203 of the well. In addition to vaporization, the temperature increase can also reduce the viscosity of the liquid phase condensate, thus improving the mobility of the liquid phase condensate and causing it to flow into the completed producing interval 203 of the well. Both these mechanisms reduce the amount of condensate and help increase the gas flow rate.

The protrusion 207 of FIG. 6 cooperates with the heating of the rock matrix 205 by the proximate heater element 211 to facilitate production of the condensate. For the case where the liquid phase condensate in the rock matrix 205 is heated to a temperature that is sufficient to cause the condensate to vaporize into gas, the gas moves in the direction of the completed producing interval 203 and up at the same time. Once the gas reaches the protrusion 207, the gas can easily travel to the producing interval and be produced. In this case, the liquid phase condensate in the rock matrix 205 can be heated to sufficient temperature that will lower the viscosity and density of the liquid phase condensate and thus improve its mobility. These factors work together to move the liquid phase condensate in the direction of the completed producing interval 203 as well as up. Once this liquid phase condensate reaches the perforation 207, it can easily travel to the completed producing interval and be produced.

The rock matrix 205 conducts the heat generated by the heater element 211 within its own body and transfers it to condensate by means of convection. In one embodiment, the heat transferred to the condensate is sufficient to vaporize the condensate (i.e., overcome its phase boundary for its vapor pressure). Depending on the thermal diffusivity (a) of the formation material, heat can be transferred either quickly or slowly to the condensate. As shown from the following equation 2, in a substance with high thermal diffusivity, heat moves rapidly through because the substance conducts heat quickly relative to its volumetric heat capacity:

$\begin{matrix} α = \frac{k}{ρ c_{p}} & Eqn . (2) \end{matrix}$

where κ is the thermal conductivity (W/(m·K)) of the rock matrix, ρ is density (kg/m³) of the rock matrix, c_pis the specific heat capacity (J/(kg·K)) of the rock matrix, and thus ρ c_pis the volumetric heat capacity (J/(m³·K)) of the rock matrix.

Sandstone formation has a thermal diffusivity of 1.81×10⁻⁶m²/s⁻¹while limestone formation has thermal diffusivity of 1.14×10⁻⁶m²/s; therefore, it is expected sandstone to transfer heat much quicker than limestone. Once the heat source is switched on, one would expect heat flux in all directions from the protrusion which will generate temperature gradients in all directions. To calculate such temperature distributions within the reservoir and wellbore, thermal exchanges due to conduction and convection need to be considered as well the effects of heating the condensate. The expected temperature profile close to the wellbore compared to the energy source is shown in FIG. 7.

Approximately 2.2 kJ is required to raise a unit mass of condensate by 1° C. at constant pressure. Assuming the heat is being transferred from the rock surface to the condensate, the amount of heat transferred into the condensate during a period of time equals the increase in the energy of the condensate during the time period according to:

hA
_s(T_s−T_∞)=mc_p(T_∞−T_i) Eqn. (3)

where T_iis condensate initial temperature, T_sis rock surface temperature, T_∞ is finite/equilibrium temperature, m is condensate mass in kg, c_pis the specific heat capacity (J/(kg·K)) of the rock matrix, h is the heat transfer coefficient between rock and condensate in W/m²° C., and A_sis the surface cross-section area in m². If the dew point temperature is known at reservoir pressure, then the energy requirements can be calculated using equation 2. Then from equation 3, the surface rock temperature is calculated and can be related to energy required to be transferred within the rock body itself. More particularly, via geometrical modeling of the formation and identifying the boundary conditions, either analytical or numerical solutions for the targeted zone can be applied and temperature profiles can be calculated within this zone.

According to one embodiment, a monitoring method to measure the flow rate of produced fluids is disclosed. The flow rate of produced fluids without heating can be measured, and the flow rate of produced fluids with heating can be measured. The enhancement of the flow rate with heating relative to the flow rate without heating can be attributed to the heating treatment. The flow rates can be measured downhole or uphole. The uphole measurement will generally integrate the flow rate from different parts of the reservoir and can lead to loss of depth information while the downhole measurement can usually be more resolved. Standard flow meters such as a venturi or a spinner can be used for this purpose. Commercial tools exist that can perform these measurements. If the flow rate is measured downhole by a flow meter 251 as shown in FIG. 8, it is possible to place the flow meter 251 (or multiple flow meters) at different depths relative to the condensate reservoir and record the flow measurements at the data recording and analysis system 253 with more information content. For example, the flow meter 251 and data recording and analysis system 253 can cooperate to record flow rate measurements at different points ranging from below the heating element 211 to the top of the reservoir, which should provide a good indication of where the gas is coming from and at what rate.

Another monitoring method measures the pressure and temperature in the condensate reservoir as a function of depth from below the heating element to the top of the reservoir. This can be done by placing temperature sensors and pressure sensors (such as a fiber optic distributed temperature and pressure sensor 255) behind the production casing 201 at the time of completion as shown in FIG. 8. The sensors cooperate with a system 257 to measure the pressure and temperature in the condensate reservoir as a function of depth from below the heating element to the top of reservoir. The measurements can be recorded by system 253. The temperature and pressure of the condensate reservoir in the vicinity of the heater element 211 can be measured as a function of lateral distance (offset) into the formation by placing temperature sensors and pressure sensors (such as a fiber optic distributed temperature and pressure sensor 259) into the formation in the vicinity of the heater element 211 as shown.

It should be appreciated that FIG. 8 shows one embodiment wherein a hole has been drilled in the radial direction and a temperature sensor has been inserted into the hole. A cased hole dynamics tester CHDT tool of the assignee can be used to drill the hole. As previously suggested, the temperature sensor is a distributed temperature sensor that can sense the temperature variation as a function of depth into the formation. In another embodiment, the measurements from a plurality of temperature sensors distributed along the axis of the well can be used to determine a radial dependence of temperature. In embodiments, the sensors cooperate with the system 257 to measure the pressure and temperature in the condensate reservoir in the vicinity of the heater element 211 as a function of lateral distance (offset) into the formation. The measurements are recorded by system 253. The temperature and pressure measurements recorded by system 253 can be analyzed to characterize the temperature and pressure of the condensate reservoir as needed. Such analysis can involve continuous monitoring. In alternate embodiments, the temperature and pressure measures can be measured and transmitted to the surface; this may include wireless telemetry, or a cable. Alternatively, the measurements can be made by a recording unit that is positioned in the well as desired.

It is contemplated that the methodology and system as described herein can be utilized in a new production well for a condensate gas reservoir. It is also contemplated that the methodology and system can be used to add condensate heating capability to an existing production well for a condensate gas reservoir in which case some of the steps in FIG. 5, such as drilling the well and completion, do not need to be performed at the time of this treatment.

The amount of thermal energy injected into the formation can be adjusted based on preset objectives. At one extreme, the objective may be to evaporate most of the condensate by injecting a relatively large thermal energy into the formation for a relatively short time. At another extreme, the objective may be to use a minimum amount of thermal energy. In this case the condensate will increase as a function of time, although at a slower rate compared to the case where there is no heating. Between these extremes there are many scenarios where thermal energy is adjusted to increase (or keep constant) the level of gas production and then kept at that level. These scenarios can be implemented by adjusting the electrical current into the heating elements using an uphole control or a control device located downhole.

There have been described and illustrated herein several embodiments of a methodology and apparatus for producing fluids from a condensate gas reservoir. While particular embodiments of the invention have been described, it is not intended that the invention be limited thereto, as it is intended that the invention be as broad in scope as the art will allow and that the specification be read likewise. Thus, while particular configurations for a vertical production well have been disclosed, it will be appreciated that other similar configurations for horizontal production wells and multilateral production wells as well. In addition, while particular types of completion equipment of the production well have been disclosed, it will be understood that other suitable completion equipment can be used. It will therefore be appreciated by those skilled in the art that yet other modifications could be made. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses, if any, are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

METHODOLOGY AND SYSTEM FOR PRODUCING FLUIDS FROM A CONDENSATE GAS RESERVOIR

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