FIG . 5 A shows a lateral, cross-sectional view of a well arrangement in an enhanced oil recovery system according to an embodiment of the present invention.

FIG. 5B shows a vertical, cross-sectional view of a well arrangement in an enhanced oil recovery system according to an embodiment of the present invention.

FIGS. 6A-6C show an example of a volumetric sweep over time of a treated volumetric reservoir using heat delivery wells in accordance with an embodiment of the present invention.

FIG. 7 shows an example of an enhanced oil recovery model space in accordance with an embodiment of the present invention.

FIG. 8 shows an approach to heated zone definition in an embodiment of the modeling system of the present invention.

FIG. 9 shows an example of a heated reservoir temperature profile used in an embodiment of the modeling system of the present invention. FIG. 10 shows an example of an exit temperature calculation incorporating a non- homogeneous temperature and velocity profile in the heated zone used in an embodiment of the modeling system of the present invention.

FIG. 1 1 shows an example of a heated zone growth away from the thermal well toward the midpoint between thermal wells according to the modeling system of the present invention.

Detailed Description of the Figures

The present invention will now be described with reference made to FIGS. 1-11.

The EOR (enhanced oil recovery) modeling system, according to the invention is a complex, preferably spreadsheet-based, modeling system that estimates the in-ground thermal effects (temperature and flow) and the above-ground thermal and power requirements to create and sustain the targeted reservoir conditions for a particular EOR system.

FIG. 1 shows an example of an EOR system that receives the production well flows, creates the injection flows, and feeds the heat input requirements of the thermal wells.

The system comprises injection wells 140, heat delivery wells 141, monitor wells 142 and producer wells 143. Although only one of each well is shown in FIG. 1, in a preferred embodiment, several injection wells 140, heat delivery wells 141 and production wells 143 can be provided in a system, including for example five injection wells 140, ten delivery wells 131 and five production wells 143.

The production well 143 pumps oil, gas, brine and/or water 112. The production well 143 may be equipped with an oscillator 170a and a jet pump, which aid in generating the pressure waves 145 that are used to increase oil recovery in the reservoir. A manifold may also be provided between the production well and a separator 113. The separator 1 13 separates the brine 111, gas 1 14 and the oil 1 15.

A boiler 120 and steam turbine or generator 122 is provided with oxygen from an oxygen/nitrogen separator 118, and is provided with the separated oil 115 and with methane/carbon dioxide (CH₄/CQ₂) 117 from a carbon dioxide/methane separator 116 receiving the separated gas 114. Prior to delivery to the boiler 120 or steam turbine/generator 122, the separated oil 115 may be supplied to a distiller separator 160, which separates the oil 115 into natural gas 161 and/or diesei fuel 163 that are supplied to the boiler 120 and/or steam turbine/generator 122, and into market oil 162. Using these components, the steam turbine 122 generates electricity 128, which can be provided in the form of electricity for operations 124, electricity for sale on the energy market 144, and electricity 125 for an electric heating cable 126 in the production well 143. Carbon dioxide from the

oxygen/nitrogen separator 118 can also be added to the inlet flow to the boiler 120 as needed to control flame temperature without adding unwanted N₂ to the exhaust stream.

The exhaust 123 of the boiler 120 and steam turbine or generator 122 is provided to one or more heat exchangers 150 configured to heat water and/or brine. Separated brine 11 1 is mixed with water and additives 153 and pumped by one or more pumps 171a, 171b to a heat exchanger 150, w hich heats the brine and outputs heated brine 130 to the injection well 140. Alternatively, the brine 111 may be provided to the boiler 120 for heating, which provides the heated and pressurized brine 134 to a heat exchanger 150. Partially cooled exhaust 154 from, the heat exchangers .150 ca be compressed by a POC compressor .152, and mixed with carbon dioxide 119, separated by the separator 1 16. The mixture can be compressed by a compressor 151, which incl udes a carbon dioxide bypass 155. The compressed and heated carbon dioxide and exhaust gases 127 are pumped into the injection well 140, which also incorporates an oscillator 170b to aid in creating pulsing pressure waves 145.

The heat delivery well 141 may be provided with a manifold. The heat delivery well 141 pumps cooled water 132 to a heat exchanger 150, which outputs heated water 131. The heated water 131 is provided to the heat deliver ' well 141 to transfer heat into the well. As the heated water 131 transfers heat to the well, the water cools and the cooled water 132 is provided back to the heat exchanger 150 in a cyclical manner.

As shown in FIG. 1, the enhanced oil recovery system may further include a plurality of pressure regulators 1 72a, 172b and a plurality of valves 173a, 173b, 173c, 173d, 173e, placed throughout the system.

Another exemplary system is shown in detail in FIG. 2. Though shown vertically, all wells depicted are horizontal . It should be realized that the wells do not need to be horizontal. For the case where horizontal wells are used, the heat deliver}' wells may be at right angles relative to the injector and the producer wells or may be implemented in a parallel or angular formation. The system works as follows.

One or more producer wells 203 deliver oil, gases and brine (water) on a line 205 (which may contain other elements) to at least one separator 206. The at least one separator 206 separates the oil and provides separated oil on a line 207, provides separated gas on a gas line 204, and provides separated brine on a brine line 208. The separated brine may include optional additives and/or optional oil. The separated brine with or without the optional additives and/or crude oil is sent on the line 208 to an inlet of at least one heat exchanger/mixer 214. If additives have been used, they are separated from the brine. The oil 207 (less any oil used for fluid injection 208 and any oil that may be used for thermal generation 204) is sent on the line 207 to a pipeline or a storage tank as recovered crude oil. The gas 204 and/or any oil used for thermal generation is sent on the line 204 to one or more boilers 221 for generation of thermal energy and may also be sent on the line 204 to one or more heat engines connected to an electric generator, such as one or more turbine generators 220 for generation of electricity on a line 209. A further gas or crude oil source 222 may provide gas and/or crude oil into the line 204. The turbines of the one or more turbine generators 220 may be gas turbines. A gas turbine derives its power from burning fuel such as the gas or crude oil on the line 204 in a combustion chamber and using the fast flowing combustion gases to drive a turbine in a manner similar to the way high pressure steam drives a steam turbine. The difference is that the gas turbine has a second turbine acting as an air compressor mounted on the same shaft. The air turbine (compressor) draws in air, compresses it and feeds it at high pressure into the combustion chamber to increase the intensity of the burning flame. The pressure ratio between the air inlet and the exhaust outlet is maximized to maximize air flow through the turbine. High pressure hot gases are sent into the gas turbine to spin the turbine shaft at a high speed connected via a reduction gear to the generator shaft. In the alternative, the one or more turbine generators 220 may include one or more steam turbines. In that case, the one or more boilers 221 may include one or more steam boilers. Or, exhaust gases from a gas turbine may be supplied to a heat exchanger that produces steam, fed to a steam turbine connected to another electric generator (electricity co- generation).

Exhaust 211 from the boiler(s) 221 and turbine(s) of the turbine generator 220 (or other heat engine) is also sent on a line 21 1 e.g., to an inlet of the heat exchanger/mixer 214, which may be the same inlet as used by the separated brine on the line 208,

The hot water on the line 212 from the closed loop boiler 221 and the cooled water on the line 213 from the heat exchanger/mixer 214 are cycled. The hot water on the line 212 from the boiler 221 is provided to another inlet of the heat exchanger/mixer 214. The heat exchanger/mixer 214 uses the heat from the hot water 212 to heat the brine or brine/oil mixture on the line 208 before, during, or after mixing the brine or brine-oil mixture with the exhaust 211. Thus, the mixer 214 may mix the exhaust into the brine or brme-oil mixture before, during, or after the heat transfer. Once the heat exchange has occurred the cooled water on the line 213 is sent back from the heat exchanger 214 to the boiler 221 for reheating. The heated brine/oil mixture 217 may be mixed with the heated exhaust 216 and then optionally mixed with additional additives 215 and sent to one or more injection pumps 218.

The injection pumps 218 inject the combined mixture into one or more injection wells 201, and may include one or more oscillating devices that create pressure waves for the enhanced oil extraction system. In other words, any of the methods shown herein may include stimulating the underground reservoir with pressure waves propagated into the underground reservoir by stimulating the heated brine during injection in an injection well 201.

The one or more injection wells 201 inject heated brine and/or oil, hot exhaust gases such as carbon dioxide_, nitrogen and other gases, and optionally additives into the oil and gas reservoir. Electricity 209 for the injection pump or pumps may be provided by the electric generator of the turbine generator 220.

The heat delivery well 202 radiates heat into the reservoir using either electricity generated from the generator of the turbine generator 220 (as shown) and/or water heated by the boiler 221 and circulated in a closed loop (see, e.g., FIG. 3 into and out of a heat delivery well 302b).

One or more producer well pumps pulsing oscillators 219, and electric heating cables 210 may be powered by the generator of the turbine generator 220. The one or more pulsing oscillators 219 are used to stimulate the underground reservoir with additional pressure waves 203a that are propagated into the underground reservoir. The oil, gas, and brine mixture in a given production well 203 is stimulated during extraction from underground. The additional pressure waves 203a are controlled such that the additional pressure waves 203a are at the same frequency and are synchronized to propagate "in phase" with the pressure waves 201a that are separately propagated into the underground reservoir by stimulation of the heated brine during injection into the well 201. When the "in phase" pressure waves 203a meet the pressure waves 2 1a in the reservoir between the two wells, they interfere constructively. The amplitude of vibrator}' stimulation of the reservoir by pressure waves is thus increased in order to increase vibration in the pores of the reservoir, increase mobility of the crude oil, and enhance flow rate.

One or more monitor wells 223 may be employed to provide control information to a control system that controls the operations of the system.

FIG. 3 shows another embodiment where the fluid heated in a boiler 321 is circulated in a closed loop above ground to and from a heat exchanger/mixer 314, and also below ground in a heat delivery well 302b in an underground oil/gas/brine reservoir 301. It should be realized that the heat delivery well 302b may be fed circulating hot fluid 312b by the boiler 321, by a separate boiler, or by another type of heat source. Wavy arrows 302 are shown emanating from the heat delivery well 302b in the reservoir 301 to signify the transfer of heat to the oil/gas/brine reservoir 301 , Oil, gas, and brine produced from one or more production wells 303 is provided on a line 305b to at least a separator 306 that provides separated gas on a line 304 to the boiler 321, separated oil on a line 307 for storage, and separated brine on a line 308 to the heat exchanger/mixer 314. The separated gas is not flared, but rather, is put to use to increase hydrocarbon recovery flow rate. Hot exhaust 31 1 from the boiler 321 is provided to a mixer part of the heat exchanger/mixer 314 for mixing with the separated brine 308. The hot brine/exhaust mixture is injected into an injection well 317, where hot brine flooding takes place to heat the reservoir, displace the trapped hydrocarbons, and push or move the hydrocarbons toward the one or more production wells 303. Wavy arrows 320, 330 are shown emanating from the hot brine flooding well 317 into the reservoir 301 to signify the delivery of hot brme/CO_?. to heat the oil/gas/brine reservoir 301 and to push and displace gas and oil toward the one or more production wells 303. Hot water from the boiler 321 is provided on a line 312a to the heat exchanger 314 where it transfers heat to the separated brine 308. The cooled fluid emerging from the heat exchanger on a Sine 313a may be joined with cooled fluid 313b emerging from, the heat delivery well 302b before the joined fluids 313c are together returned to the boiler 321 for re-heating. The re-heated fluid emerges from the boiler 321 on line 312a for connection to the heat exchanger 314 and on line 312b for connection to the heat delivery well 302b in a repeating cycle of heating, cooling, and re-heating.

Also shown in FIG. 3, pressure waves 303a may be generated in both die one or more production wells 303 and additional pressure waves 317a in the at least one injection well 317. The underground placement of the production and injection wells with respect to each other may be advantageously set up such that constructive interference is facilitated and controlled with the production and injection waves controlled so as to be stimulating the reservoir simultaneously , continuously and synchronized in phase so as to meet in the reservoir and add constructively, thereby increasing the amplitude of the stimulating force imparted to the reservoir. The spatial relationship should be such that at least part of the production wave 303a is propagated in a direction toward the injection well 317 and the injection wave 317a is propagated in the opposite direction toward the production well 303 so that the waves meet in a space in between the wells and interfere constructively.

A further embodiment for circulating fluid in a reservoir is shown in FIG. 4. In the embodiment shown in FIG. 4, five pairs of injection wells 254 and production wells 255 are provided, and ten heating wells 256 are provided. Each of the production wells 255 and heating wells 256 can be supplied with a pump, and each of the injection wells 254 can be supplied with a pump and an oscillator. The injection w ells 254 and production wells 255 are arranged as vertical wells in the embodiment shown in FIG. 4, and the heating wells are 256 are shown as horizontal wells. The array of heating wells 256 spans a distance of 5,280 feet, with 528 feet in between each well 256 (and 264 feet on each end). The array of injection wells 254 and production wells 255 also spans a distance of 5,280 feet, with 528 feet in between each well 254, 255 (and 264 feet on each end). The production wells 255 can have a length of 4,224 feet. The injection wells 254 may comprise two separate pipes, one for gas and one for water, each having a length of 4,224 feet.

The system shown in FIG. 4 further includes a "Green Boiler" system 250, similar to those described previously, which is connected to the injection wells 254, production wells 255 and heating wells 256. The boiler system 250 can supply heated water and gas to the injection wells 254 and heating wells 256. The boiler system 250 can also supply pumped and separated oil, gas and water to an oil tank 251, a gas tank 252 and a water tank 253a. A second water tank 253b can also be provided to store cooled water pumped out of the heating.

The thermal input w ells actually run perpendicular to the production and injection wells. FIGS. 5A and 5B depict this arrangement from two different perspectives. This cross hatched pattern of heat deliver}' wells 420 creates low viscosity paths for the flooding with water, CO?, and/or N₂. In this arrangement, low viscosity paths are quickly created by the thermal wells 420. As the heat expands radially from the thermal input well 420 over time, the entire net pay zone is addressed.

According to one exemplary embodiment shown in FIGS. 5A-5B, an arrangement in a reservoir is provided with the production wells 405, injection wells 410, a monitoring well 415 and heat deliver}' wells 420, which are oriented perpendicularly to the production wells 405, injection wells 410, and monitoring well 415. The wells 405, 410, 415, 420 are oriented in between a seal 401 and trap 402 in the reservoir. In the arrangement shown in the Figures, the distance between the seal 401 and trap 402 is approximately 480 feet, and the production wells 405, injection wells 410, a monitoring well 415 and heat delivery wells 420 are located approximately in the middle of this distance, 240 feet from the seal 401 and trap 402. In one embodiment of the system shown in FIGS. 5A-5B, each of the production wells 405, injection wells 410, and heat delivery wells 420 can have a length of 6,000 feet. The distance between the parallel production wells 405 and injection wells 410 can be approximately 750 feet and the distance between the parallel heat delivery wells 420 can also be approximately 750 feet. The injection wells 410 and production well 405 can incorporate high powered pumps that can be configured for created pressure wave pulses. The monitoring well 415 may sense characteristics of the well such as pressure, heat and flow, and is in

communication with a control system to adjust the well dynamics to achieve an idealized system.

niis cross hatched pattern of heat delivery wells create low viscosity paths for the flooding (steam, water and C0₂). In this arrangement the heat does not need to expand radially from the source to achieve this as low viscosity paths are immediately created. As the heat does expand radially from the heat deliver}' well over time, the entire net pay zone is addressed. FIGS. 5 A and 5B depict this arrangement.

In the matrix arrangement shown in FIGS . 5A-5B and 6A-6C, technically controlled pressure gradients for the injection wells 410 and the production wells 405 avoid creating disruptive channeling paths. The further the oil is away from the flow paths the higher the pressure gradient will be. This herds the oil di rectional i to the flow paths. Pressure oscillation creates standing waves in the reservoir that constructively add to increase the amplitude and oil mobility . Directional standing waves break the interfacial tension of the capillaries eliminating flow restrictions and moving the fluids to the producer wells 405. Pressure gradients create imbalances in the reservoir pressures and allows for a large sweep area. Because the heating wells 420 produce a viscosity pattern that can be accurately modeled, specific designs can be implemented to quantitatively set the pressure gradient fields to best match the viscosity patterns.

FIG. 6A shows the reservoir heated region in the earlier stages of evolution depicting where the flow rate is high in the low viscosity areas and the colder regions where the flow rate will be much lower. The heated region expands laterally from the thermal wells from both conductive heat transfer and convective heat transfer - created by the upward flow of the heated reservoir fluid near the thermal well due to buoyancy effects relative to the colder bulk reservoir fluid. In addition the heated injection flow deposits heat along tins path as it cools due to contact with the cooler reservoir material found at the thermal edges of the heated flow path. This advective method of heat addition becomes the dominant process by which the heated region expands as the heated flow path cross-sectional area increases. Hie limit on thermal input to the reservoir then becomes a function of the level of thermal input and circulatory power that can be supplied to the injection flow from the above-ground equipment. FIGS. 6B and 6C show this expanding heated zone over time. These figures show the inclusion of optional apparatus that shift the active regions on the injection and production wells. These would reduce above-ground pump and compressor sizing, but are not yet included in the modeling system.

FIGS. 6A-6C show the growth of the heated region 450 over time (on one plane) and how the flow pattern is manipulated by having pressure gradients along the injection and production wells. In the arrangement shown in FIGS. 6A-6C, the horizontal heat pulsing waves 440 and 445 will travel in many directions and bounce off of tlie seal 401, tlie trap 402 and the higher viscosity oil, but will always travel in the direction of the production well 405. For example, FIG. 6A may show the matrix arrangement after 10 days of implementation, FIG. 6B may show the matrix arrangement after 50 days of implementation and FIG. 6C may show the matrix arrangement once the oil flow has been maximized.

The system shown in FIGS. 6A-6C includes injector wells 410, heat delivery wells 420 and a producer well 405. The injector wells 410 and heat delivery well 405 are preferably ported, meaning that the pipes of the wells have ports spaced apart along the length of the pipe. For example, the ports can be separated by forty-two feet on each pipe. The size of the ports along the length of the pipes may vary in order to adjust the pressure of the waves created by the fluid exiting or entering the port, depending on whether the ports are in the injector well 410 or producer well 405. Ports having a smaller size or diameter create lower pressure waves 440, while ports having a larger size or diameter create higher pressure waves 445, as the amount of fluid that can exit the port of injector well 410 or enter the producer well 405 increases. As used in the Figures, a thinner wavy arrow 440 corresponds to a low pressure wave and lower corresponding flow rate, and a thicker wavy arrow 445 corresponds to a higher pressure wave and higher corresponding flow rate.

The combination of the injector wells 410, heat delivery wells 420 and producer well 405 as shown in the FIGS. 6A-6C reduces the viscosity of the oil or gas in the reservoir, creating low viscosity areas 450 and low viscosity flow paths. The low viscosity flow paths push and pull oil and gas towards the producer well 405 with greater efficiency. Over time, tlie size of tlie low viscosity areas 450 and low viscosity flow paths increases. The pressure gradients 430 blocking the radial flow ingress and egress on the productions wells 405 and injector wells 410 can be changed in specific locations over time.

Tlie modeling system addresses one "segment" of this grid in a model space defined by the following: I) One thermal well length extending from an injection well to a production well, and 2) A parallel length of injection and production well extending between the midline distance between adjacent thermal wells. FIG. 7 is a sketch of a model space 500 of a reservoir. The various performance results for this model space 500 or "segment'¹ are multiplied by the number of segments along the length of an injection well 410 and production well 405 pair and the number of production and injection pairs required for the field being addressed. In the modeling system, the user can set the field size and the number of production and injection well pairs, and the number of thermal wells 420 in the field 405, 410 and 420. The modeling system is configured to then determine the appropriate spacing of the wells.

The modeling system is configured to determine the thermal input to a section of the reservoir based on the conductive heat flow (Q_∞nd) and convective heat flow (Q_COnv) from a thermal well 420 to the reservoir and the fluid flow through the reservoir moving from an injection well 405 towards a production well 410 through both the heated (low viscosity) regions and the unheated (high viscosity) regions of a reservoir, given a selected injection pressure. Flows through the heated and unheated regions of the reservoir can be determined separately by the modeling system. The assumed thermal profile of the heated region of the reservoir is described in the model assumptions below. The reservoir conditions, including for example temperature, oil, water, gas composition and through flow rate, are assumed constant over the defined period, for example, one day.

The reservoir flows can be determined and modeled by treating the reservoir as a homogenous porous material represented by a single average permeability. The thermal input to the reservoir is calculated for the defined period and the increase in the heated volume is determined by assuming the added heat raises a specific volume to the average reservoir temperature as described fuither below. This sets the cross-sectional flow area of the heated zone for the next calculation step. This approach maintains the thermal accounting and is a reasonable representation of the reservoir thermal condition.

FIG. 8 shows this approach visually. FIG. 8 shows an estimated actual temperature profile 501 and a square T_ave temperature profile 502 that has the equivalent thermal content.

The water, oil, gas composition of the heated region and the cold region at the beginning of the time step determines the composition of the fluid leaving each of these regions and entering the production well during the period. The volume of fluid leaving defines the volume of water and gas that will be injected at the selected temperature into the reservoir during that same period. As illustrated in the examples of FIGS. 1-4, the composition of the injected flow is determined by the water and gas "recycled" from the production flow and the products of combustion from the gas turbine and boiler that supply the thermal input to the injected flow and the electric power to the compressors and pumps. If the volumes of the water and carbon dioxide components of the products of combustion (at reservoir conditions) are not sufficient to replace the volume of oil extracted over the period, nitrogen (N₂) can also be injected. Alternative process selection by the user can allow additional water to be added in lieu of nitrogen or carbon dioxide in the early period of the process. This will accelerate the thermal input to the reservoir, particularly in the case of shallow reservoirs.

All water and carbon dioxide from, the production stream is recycled and reinjected into die reservoir, and all of the carbon dioxide and water from the products of combustion are injected except early in the process if additional water injection in lieu of carbon dioxide is allowed. Later in the process when the volume of water and carbon dioxide exceeds the oil replacement volume, the excess heated flow is allowed to leak out and its thermal content is lost to the process. Some fluid is also lost to the process as the lost flow composition is based on the reservoir composition (including oil) at the beginning of the time step. In most cases, this leakage is less than 1% of the injected flow. This lost oil is subtracted from the projected yield. In addition, the modeling system allows a limit to be set on the allowable leakage (default is 1%). If the recy cled and produced fluids exceed the set limit, the excess fluid is tagged as either vented or sequestered elsewhere.

The composition of the fluids in the heated region of the reservoir at the end of the time step is recalculated based on the fluid flows into and out of the reservoir, and the newly heated volume of reservoir fluid '^"joining" the heated region from the cold region. The cold region composition is also recalculated each time step to account for the oil extracted from this region. Reservoir temperature carbon dioxide is assumed to replace the cold region extracted oil, and plays no thermal role in the calculations.

The energy required to heat the recycled and new injection fluids is calculated. The energy available from burning any combustible gas byproduct in the production well stream is subtracted from that value. The amount of oil required to supply the remaining heat input is calculated. This oil is subtracted from the oil harvested to yield a net value. As the reservoir heating process progresses the heat required to the injection flow based on the specified injection pressure will increase significantly. The user specifies a limit on this thermal input, which in effect sets the approximate size of the above-ground green boiler system. The fluid flow from injection to production well is reduced if the pressure driven flow thermal need exceeds this limit. A reduced injection pressure is specified for that time step. The electrical energy required to circulate the reservoir fluids is also determined. For the recycled flows (gas and water) this includes the pressure drop through the reservoir, and the pressure loss down the injection well bore and up the production well bore. The static head in each well is incorporated into the calculation. Pumping of the recycled water is handled separately from the recycled carbon dioxide since the water from the production well separator is maintained as a separate stream at a temperature above the vaporization pressure and remains in its liquid phase. The product of combustion fluids (carbon dioxide, water vapor, and trace N₂) are compressed from the near ambient exhaust pressure to the pressure of the recycled carbon dioxide stream (which also contains water vapor).

The modeling system incorporates several assumptions that are used in predictively modeling various components of an enhanced oil recovery system. The following sections describe the various assumptions and the determination and estimation approaches used in an embodiment of the EOR modeling system.

In the heated region temperature profile, the following assumptions are incorporated. The injected flow enters the reservoir at a constant, user-selected, temperature at the reservoir locations that have increased temperature, therefore the edge of the heated reservoir region at the injection well location has a constant temperature. The far radial (or lateral) edge of the heated region has a linear temperature profile that is at the injection flow temperature (¾) at the injection wells and is at the initial reservoir temperature (T_res) at the production well. The near edge (i.e., by the thermal wells) has a linear temperature gradient that is the injection flow temperature (Tmj) by the injection wells and the thermal well temperature (TTW) by the production wells. The fluid exiting the reservoir and entering the production well has a linear temperature gradient starting with the thermal well temperature by the thermal well and the initial reservoir temperature at the far edge of the heated region. The remainder of the reservoir volume is at the initial reservoir temperature. The average temperature (T_ave) of the heated part of the reservoir is the volumetric average using the above listed temperatures. This is shown, for example, in FIG. 9. The near field volume around the production well is actually significantly warmer due to the hot fluid flow within the well. This significantly lowers the fluid viscosity in this region and reinforces the validity of the assumption that there is not a large pressure drop in this flow constricted region.

For heat transfer to the reservoir from the thermal wells, the following assumptions are incorporated. The thermal wells have a constant temperature (TTW) along their length. The conductive heat transfer (Q_∞u_d) and convective heat transfer (Q_COHV) from the thermal wells to the reservoir is based on the temperature difference between the thermal well (TTW) and the average temperature (Τ_3νε) of the heated reservoir volume. Hie average temperature (I^'avs) of the heated region is a volumetric average based on the thermal profiles listed above. The heat transfer rate s calculated based on finite element modelling performed that simulated heat transfer from or to a heated or cooled horizontal cylinder in a porous media, taking into account the circulation cells set up in the surrounding fluid due to thermally induced buoyancy differences between fluid near the hot thermal well and the cooler fluid farther from the thermal well.

For heat transfer to the reservoir from the injected flow, the following assumptions are incorporated into the modeling system. The injected flow enters the reservoir from the injection wells at the user selected temperature. The injected flow exits the reservoir to the production wells at the temperature profile specified above. Though a portion of the exit flow may be heated by the production well flow from hotter regions, it does not affect the net heat transferred to the reservoir. The injection fluid flow path through the heated region is broken into ten radial or lateral segments (V₁-V₁₀) and ten segments along the flow path between the production and injection wells. The fraction of the overall injected fluid that flow s through each radial segment is calculated based on the composite fluid viscosity for the assumed temperatures along the flow length. The average exit temperature (ϊ_£χ<ΐ) is then calculated so that it is weighted for flow variation and therefore representative of bulk exit flow temperatures. Hie average fluid exit temperature (T_exj_t) is not the same as the average temperature of the fluid approaching the production well.

A visual representation of this process is shown, for example, in FIG. 10 where Vi represents the highest flow rate in the hottest fluid region, while Vi₀ represents the much slower flow velocity in the cooler region.

The modeling system imposes a user selected pressure gradient between the injection and production wells and checks for limits such as saturation pressures, model stability, etc., alerting the user if they have exceeded them. The overall flow rate is calculated based on the fluid composite viscosity, the reservoir permeability, and the heated region cross-sectional area. The thermal "deposit" from the injection flow is then calculated using this overall flow rate, the temperature change between the injection and average exit temperature the composite fluid properties (specific heat, density) and the model time step (e.g., one day).

With respect to the increase in heated reservoir volume and flow area, the following assumptions are incorporated into the modeling system. The calculated heat input from both the thermal well and the injected flow are combined for an overall heat addition over the period. The composite of the reservoir material properties (volume fraction, density, and specific heat) are used to calculate an incremental increase in the reservoir volume heated from the initial temperature to the reservoir average temperature. An increased radius of the heated zone is calculated (and related to a fraction of the model segments thermal well spacing and target zone thickness).

FIG. 1 1 is a visualization of this growing heated zone over time (ti- 14). The heated zone grows from each of the thermal well locations until the entire targeted region the reservoir is heated. This occurs in the model when the area heated to T_ave spreads to the midpoint between adjacent thermal wells (the "midpoint").

The modeling system further incorporates various assumptions regarding pressure and flow. The pressure drop through either the production or injection well is based on laminar or turbulent flow (based on Reynolds number), the average fluid pressure, and composite flow properties (density, viscosity, etc.). The static head in either the production or injection well is based on the composite production or injection fluid properties and the average pressure. The fluid temperature in the production and injection wells is assumed to be constant (at the reservoir average exit temperature and injection temperature respectively). The pressure at the inlet to the production well is assumed to be the reservoir average pressure.

With respect to the production well down-hole compressor, the modeling system assumes that a separate production well compressor is used if the pressure at the top of the production well would be lower than the saturation pressure required to maintain water in its liquid phase.

With respect to the POC compressor, the modeling system assumes the gas phase products of combustion are compressed to the pressure of the inlet to the main injection compressor (after the production well compressor if used).

For recycled water pumping, the modeling system assumes that the water injection pump raises the pressure of the recirculating water to the higher of the following: (a) Based on the flow rate and total pressure drop for the complete water circulation loop, or (b) to exceed the saturation pressure for the water at the selected injection temperature

With respect to CO₂/H₂O/₂ injection compressor, the modeling system assumes that inlet pressure is based on the production well exit pressure and outlet pressure is based on the reservoir pressure, static head and pressure drop in the injection well.

The reservoir inputs to achieve the output optimization entered into the modeling system may include, but are not limited to: (1 ) Dimensions of the reservoir field; (2) Temperature distribution of the reservoir; (3 ) Porosity distribution of the reservoir; (4) Permeability distribution of the reservoir; (5) Size and distribution of the capillary pores in the reservoir; (6) Physical description of the erode oil, including viscosity, density , gas fraction, and water fraction, (7) Conductivity of the in situ oil/rock formation; and (8) Acoustic testing results, including frequency versus dissipation rates over travel lengths and wave speed distribution.

The outputs to the system equipment configuration system of the EOR system may- include, but are not limited to: (1) Location, orientation, and length of the production and extraction wells; (2) Spacing between the production and injection wells; (3) Position, orientation, and length of the heat delivery wells relative to the production and injection; (4) Placement of the monitoring well (location and orientation) to maximize the useful information to the control system during operation; (5) The frequency of the pulsed pumping; (6) The desired amplitude of the pulsed pumping; (7) The anticipated capacity of the reservoir to accept heat from the heat delivery wells (used to size either electric heaters or fluid circulation capability in the heat delivery wells); (8) The anticipated rate of growth of the heated reservoir zone; (9) Injection pump pulsed volume and power requirement; (10) Extraction pump pulsed volume and power requirement; (11) Heat exchanger/mixer sizing; and (12) Green Boiler (or geothermal well geothermal heat input) sizing to meet the anticipated thermal input potential to the field.

The modeling system will also output a set of predicted system parameters based on the optimized performance of the Heat/Oil Matrix and system components specified. These parameters include, for example, the control system, input parameters described previously. In addition, a set of initial operating parameters for the system equipment can be specified, which can include the control system output parameters described previously, when applicable to a given design.

The predictive modeling system of the present invention is able to accurately model the temperature profiles in the oil reservoir of the EOR system in three dimensions over time, and accurately model the flow fields in three dimensions over time. The modeling system further allows for intelligent adjustment of the injection well (flow and temperature and composition) and thermal well inputs (input temperature and flow rate) over time. The modeling system allows the user to manipulate of the injection and production port profiles over time and manipulate the relative position of the production, thermal, and injection wells within the reservoir. The heat from the production well flow on the near field volume will be accurately modeled. The heterogeneous nature of a specific reservoir (permeability, porosity, etc.) can be set for specific nodal positions in the model. The seismic data that defines the detailed, specific shape of the reservoir can be utilized to create non-rectilinear fields.

Pulsing pressure waves from both the injection and production wells will be incorporated into the model along with pore size distribution data from core samples to estimate the increase in accessible oil. H e effect of flashing and recondensing of the injected fluid in the reservoir will be included in the modeling system.

The modeling system can be applied using FEA numerical program that is tailored for reservoir modeling. A program can be stored on a non -transitory computer readable medium, such as a memory, for executing by a processor of a computing device. When the program is executed, the processor of the computing device is configured to execute the modeling system as described herein. The modeling system may comprise a spreadsheet-based program stored on a computer readable medium for execution on a computing device, comprising a user interface and a display screen. A user may provide a plurality of inputs to the modeling system program via a user interface, which is stored with the algorithms for m aking the various determinations regarding the implementation of the enhanced oil recover}' system described above.

Output from the modeling system will be used to produce visual representations of the processes in the reservoir over time, which may be displayed on a display screen of a computer device or transmitted to a printer device. For example, the modeling system can be configured to create and provide an output of digital image files that show a visual representation of the optimum enhanced oil recovery system, and the processes that would occur within the enhanced oil recovery system, over time. The generated output of the modeling system will not only help design the system control approach, but also guide the placement of the monitoring weil(s) for optimum system control input.

While there have been shown and described and pointed out fundamental novel features of the invention as applied to preferred embodiments thereof, it will be understood that various omissions and substitutions and changes in the form and details of the devices and methods described may be made by those skilled in the art without departing from the spirit of the invention. For example, it is expressly intended that all combinations of those elements and/or method steps which perform substantially the same function in substantially the same way to achieve the same results are within the scope of the invention. Moreover, it should be recognized that structures and/or elements and/or method steps shown and/or described in connection with any disclosed form or embodiment of the invention may be incorporated in any other disclosed or described or suggested form or embodiment as a general matter of design choice.

Claims

WHAT IS CLAIMED:

1. An apparatus for reco vering oil from an underground reservoir designed using a predictive modeling system comprising:

a heat transfer matrix including:

at least one production well;

at least one thermal injection well; and

at least one heat delivery well,

wherein the at least one thermal injection well is arranged in parallel to the at least one production well and the at least one heat delivery well is arranged along one or more planes intersecting the at least one thermal injection well and the at least one production well; and

wherein the heat transfer matrix is configured to transfer heat to an underground reservoir at least within at least one volume leading to the at least one production well so as to increase temperature within the at least one volume; and at least one injection pump and/or compressor for recovering crude oil that flows to the at least one production well in the underground reservoir heated by the heat transfer matrix.

2. The apparatus of claim 1, wherein the predictive modeling system is configured to model temperature profiles in the underground reservoir in three dimensions over time and model fluid flow- fields in the underground reservoir in three dimensions over time

3. The apparatus of claim 1, wherein the predictive modeling system is configured to defi ne a model space corresponding to a segment of the underground reservoir comprising a length of a heat delivery well extending from a thermal injection well to a production well and parallel lengths of the thermal injection well and the production well extending between adjacent heat delivery wells and to determine one or more performance attributes of the model space based at least partly on a plurality of received user inputs,

4. The apparatus of claim 1, further comprising pressure wave stimulators designed using the predictive modeling system for stimulating the underground reservoir within the at least one volume surrounding the production well with synchronized pressure waves provided in the at least one production well and the at least one thermal injection well.

5. The apparatus of claim I, further comprising:

a boiler for burning natural gas or a fraction of the crude oil reco v ered from the underground reservoir, or for burning both natural gas and a fraction of the erode oil recovered from the underground reservoir, for transferring thermal energy to a circulating fluid;

a heat exchanger for receiving both brine separated from the recovered oil and the circulating fluid from the boiler for transferring the thermal energy from, the circulating fluid to the brine separated from the extracted oil, for providing heated brine; and

at least one injection pump for injecting the heated brine into the at least one thermal injection well in the underground reservoir for transferring heat to the underground reservoir with the heated brine.

6. The apparatus of claim 1, wherein the at least one thermal injection well and the at least one heat delivery well are arranged in relation to one another and to the at least one production well so as to define a volumetric shape for the at least one volume surrounding the at least one production well.

7. The apparatus of claim 6, further comprising wherein the volumetric shape is a parallelepiped.

8. The apparatus of claim 6, further comprising wherein the volumetric shape is a polyhedron shape.

9. The apparatus of claim 1 , wherein the transfer of heat from the heat transfer matrix gradually spreads within the at least one volume and increases the temperature in the at least one volume until the temperature stabilizes.

10. The apparatus of claim I, wherein the at least one thermal injection well is configured for injecting heated water into the at least one volume leading to the at least one production well and the at least one heat deliver}' well is configured for heating the at least one volume leading to the at least one production well with an electric cable or with heated water circulating within the at least one heat delivery well, the at least one volume having the at least one thermal injection well and the at least one heat delivery well arranged in relation to one another and to the at least one production well so as to increase tempe ature within the volume between the at least one production well and the at least one heat delivery well, and between the at least one production well and the at least one thermal injection well.

1 1. A method for designing an oil recovery system for recovering oil from an underground reservoir using a predictive modeling system, the oil recovery system comprising a heat transfer matrix including at least one production well, at least one thermal injection well, and at least one heat delivery w ell, and at least one injection pump and/or compressor for recovering crude oil that flows to the at least one production well in the underground reservoir heated by the heat transfer matrix, wherein the heat transfer matrix is configured to transfer heat to an underground reservoir at least within at least one volume leading to the at least one production well so as to increase temperature within the at least one volume, the method comprising:

receiving a plurality of user inputs relating to the oil recovery sy stem:

defining a model space corresponding to a segm ent of the underground reservoi r comprising a length of a heat delivery well extending from a thermal injection well to a production well and parallel lengths of the thermal injection well and the production well extending between adjacent heat delivery wells;

determining one or more performance attributes of the model space based at least partly on the plurality of user inputs; and

providing a predictive model of the oil recovery system based at least partly on the one or more determined performance attributes of the model space.

12. The method according to claim 11, wherein the plurality of user inputs comprise one or more of:

dimensions of the underground reservoir, temperature distribution of the underground reservoir, porosity distribution of the underground reservoir, permeability⁷ distribution of the underground reservoir, size and distribution of capillary pores in the underground reservoir, physical attributes of crude oil to be reco vered, including viscosity, density, gas fraction, and water fraction, conductivity of in situ crude oil or rock formation, and acoustic testing results, including frequency versus dissipation rates over travel lengths and wave speed distribution.

13. The method according to claim 11, further comprising determining locations of the at least one heat delivery well, at least one thermal injection well, and the at least one heat delivery well in the oil recovery system based on the received plurality of user inputs.

14. The method according to claim 13, wherein determining the locations of the at least one heat delivery well, at least one thermal injection well, and the at least one heat delivery well in the oil recovery system comprises determining distances between each of the at least one heat delivery well, the at least one thermal injection well, and the at least one production well .

15. The method according to claim 11, wherein the one or more performance attributes of the model space include an estimated amount of crude oil to be recovered by the production well of the model space, and

wherein said determining one or more performance attributes of the model space comprises determining an appropriate amount of thermal input via the thermal injection well to recover the estimated amount of crude oil based on an advective heat flow and a convective heat flow from the thermal injection well to the underground reservoir.

16. The method according to claim 11, wherein the one or more performance attributes of the model space include an estimated amount of crude oil to be recovered by the production well of the model space and,

wherein the production well is configured to recover crude oil and additional fluids from the underground reservoir, and the injection well and/or heat delivery well are configured to provide at least a portion of the additional fluids recovered from the production well to increase the amount of crude oil recovered by the production well.

17. The method according to claim 16, wherein said determining one or more performance attributes of the model space comprises determining an expected composition of fluid entering the production well ,

18. The method according to claim 16, wherein said determining one or more performance attributes of the model space comprises determining an average temperature of the underground reservoir over time based on at least an initial temperature of the underground reservoir, a temperature of fluid injected into the underground reservoir via the thermal injection well, and a temperature of fluid in the heat delivery well.

19. The method according to claim 16, wherein said determining one or more performance attributes of the model space comprises determining an amount of energy required to heat fluids to be injected into the underground reservoir via one or both of wherein the injection well and the heat deliver}' well to recover the estimated amount of oil to be recovered via the production well.

20. The method according to claim 16, wherein said determining one or more performance attributes of the model space comprises determining an amount of electrical energy required to circulate fluids tlirough the underground reservoir to recover the estimated amount of oil to be recovered via the production well.

21. The method according to claim 16, wherein said determining one or more performance attributes of the model space comprises determining a flow rate of the oil and additional fluids into the production well.

22. The method according to claim 11, providing a predictive model of the oil recovery system comprises providing one or more outputs, said one or more outputs including a visual representation of the oil recovery system over a predetermined period of time.

23. The method according to claim 11, wherein providing a predictive model of the oil recovery system comprises multiplying the one or more determined performance attributes of the model space by a number of segments in the oil recovesy system along a pair of thermal injection and production wells and a number of pairs of thermal injection and production wells in the oil recovery system, to determine performance attributes of the oil recovery system.

24. An apparatus for predictively modeling an oil recovery system in an underground reservoir, comprising:

a user interface configured to receive a plurality of user inputs rel ating to the oil recovery system comprising a heat transfer matrix including at least one production well, at least one thermal injection well, and at least one heat delivery well, and at least one injection pump and/or compressor for recovering crude oil that flows to the at least one production well in the underground reservoir heated by the heat transfer matrix;

a processor configured to:

define a model space corresponding to a segment of the underground reservoir comprising a length of a heat delivery well extending from a thermal injection well to a production well and parallel lengths of the thermal injection well and the production well extending between adjacent heat delivery wells;

determine one or more performance attributes of the model space based at least partly on the plurality of user inputs; and

provide a predictive model of the oil recovery system based at least partly on the one or more determined performance attributes.

25. The apparatus according to claim 24, further comprising a display configured to display a visual representation of the predictive model of oil recovery system, including a visual representation of the oil recovery system over a predetermined period of time.