Comprehensive enhanced oil recovery system
10443364 ยท 2019-10-15
Assignee
Inventors
Cpc classification
E21B43/305
FIXED CONSTRUCTIONS
International classification
E21B36/00
FIXED CONSTRUCTIONS
E21B43/30
FIXED CONSTRUCTIONS
E21B43/00
FIXED CONSTRUCTIONS
Abstract
A comprehensive enhanced oil recovery system that combines a plurality of different implementations of several enhanced oil recovery methods in an integrated system. The enhanced oil recovery system includes heating an underground reservoir having a heat transfer matrix to increase the temperature of the reservoir around a production well. The heat transfer matrix includes thermal injection wells, production wells and heat delivery wells.
Claims
1. A method, comprising: heating an underground reservoir within at least one volume surrounding at least one production well in the underground reservoir, the underground reservoir further comprising a heat transfer matrix configured to transfer heat to increase temperature within the volume surrounding the at least one production well, and recovering crude oil that flows to the at least one crude oil production well in the underground reservoir heated by the heat transfer matrix; wherein the heat transfer matrix of the underground reservoir comprises at least one thermal injection well arranged in parallel to the at least one production well and at least one heat delivery well arranged along one or more planes intersecting the at least one thermal injection well and the at least one production well; burning natural gas or a portion of the crude oil extracted from the underground reservoir, or burning both natural gas and crude oil extracted from the underground reservoir, for providing thermal energy, transferring the thermal energy to brine separated from the extracted oil, gas, or both, for providing heated brine, or converting the thermal energy to mechanical work, or both transferring the thermal energy to the separated brine and converting the thermal energy to mechanical work, and heating the underground reservoir with the heated brine injected into the at least one thermal injection well in the underground reservoir, or heating the underground reservoir with a resistive cable in a thermal well comprising a heat delivery well, the resistive cable energized by electricity generated by converting the mechanical work to electric energy, or heating the underground reservoir with both the heated brine and the energized resistive cable.
2. The method of claim 1, further comprising: burning natural gas recovered with the recovered crude oil, or a portion of the recovered crude oil, or both the recovered natural gas and a portion of the recovered crude oil to heat circulating water and transfer heat from the heated circulating water to the brine extracted from the underground reservoir; and returning the heated brine to the underground reservoir for thermal flooding via at least one of the at least one thermal injection well or at least one heat delivery well.
3. The method of claim 2, further comprising stimulating the underground reservoir within the at least one volume surrounding the at least one production well with synchronized pressure waves provided in the at least one production well and in one or more of the wells for thermal flooding.
4. The method of claim 2, further comprising mixing exhaust gas generated from the burning with the brine for thermal flooding.
5. The method of claim 4, further comprising stimulating the underground reservoir within the at least one volume surrounding the production well with synchronized pressure waves provided in the production well and in one or more of the wells for thermal flooding.
6. The method of claim 1, wherein the transfer of heat gradually spreads within the at least one volume and increases the temperature in the at least one volume until the temperature stabilizes.
7. The method of claim 6, further comprising: increasing by a selected amount the portion of the recovered crude oil or natural gas recovered with the recovered crude oil, or both, until the temperature stabilizes at a higher temperature level and repeating the increasing by selected amounts until the temperature stops stabilizing at increased temperature levels.
8. The method of claim 1, wherein the at least one thermal injection well is for injecting heated water into the at least one volume surrounding the least one production well and the at least one heat delivery well is for heating the at least one volume surrounding the 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 temperature within the at least one 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.
9. The method of claim 1, wherein the at least one thermal injection well and 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.
10. The method of claim 9, wherein the volumetric shape is a parallelepiped.
11. The method of claim 10, wherein the parallelepiped shape is a rectangular parallelepiped shape.
12. The method of claim 9, wherein the volumetric shape is a polyhedron shape.
13. The method of claim 1, wherein the heat transfer matrix comprises at least two thermal injection wells arranged in parallel to the at least one production well and situated on opposite sides of the at least one production well.
14. The method of claim 13, wherein the heat transfer matrix further comprises at least two heat delivery wells arranged perpendicular to the at least one production well and the at least two thermal injection wells.
15. The method of claim 13, wherein the heat transfer matrix further comprises at least two heat delivery wells arranged along a diagonal relative to the at least one production well and the at least two thermal injection wells.
16. The method of claim 1, further comprising using recycled CO.sub.2 in an inlet flow to burning devices so that a flame temperature of combustion can be controlled without adding additional volume to an exhaust stream.
17. An apparatus, 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 surrounding the at least one production well so as to increase temperature within the at least one volume; at least one production pump for recovering crude oil that flows to the at least one production well in the underground reservoir heated by the heat transfer matrix; a boiler for burning natural gas or a portion of the crude oil recovered from the underground reservoir, or for burning both natural gas and a portion of the crude 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 natural gas and the circulating fluid from the boiler for transferring the thermal energy from the circulating fluid to the brine separated from the extracted oil and natural gas, 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.
18. The apparatus of claim 17, further comprising pressure wave stimulators for stimulating the underground reservoir within the at least one volume surrounding the production well with synchronized oscillatory pressure waves provided in the at least one production well and the at least one thermal injection well.
19. The apparatus of claim 17, further comprising a mixer responsive to exhaust from the boiler for mixing the exhaust with the brine.
20. The apparatus of claim 17, 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.
21. The apparatus of claim 20, further comprising wherein the volumetric shape is a parallelepiped.
22. The apparatus of claim 21, wherein the parallelepiped shape is a rectangular parallelepiped shape.
23. The apparatus of claim 22, further comprising at least two thermal injection wells parallel to the at least one production well and are situated on opposite sides of the at least one production well.
24. The apparatus of claim 23, wherein a part of the production well that is parallel to the at least two thermal injection wells extends at an angle from a perpendicular to a surface of the earth.
25. The apparatus of claim 23, wherein the heat transfer matrix further comprises at least two heat delivery wells arranged perpendicular to the at least one production well and the at least two thermal injection wells.
26. The apparatus of claim 22, wherein the heat transfer matrix further comprises at least two heat delivery wells arranged along a diagonal relative to the at least one production well and the at least two thermal injection wells.
27. The apparatus of claim 20, further comprising wherein the volumetric shape is a polyhedron shape.
28. The apparatus of claim 17, 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.
29. The apparatus of claim 17, wherein the at least one thermal injection well is configured for injecting heated water into the at least one volume surrounding the least one production well and the at least one heat delivery well is configured for heating the at least one volume surrounding the 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 temperature 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.
30. A method, comprising: heating an underground reservoir within at least one volume surrounding at least one production well in the underground reservoir, the underground reservoir further comprising a heat transfer matrix configured to transfer heat to increase temperature within the volume surrounding the at least one production well, and recovering crude oil that flows to the at least one crude oil production well in the underground reservoir heated by the heat transfer matrix; wherein the heat transfer matrix of the underground reservoir comprises at least one thermal injection well arranged in parallel to the at least one production well and at least one heat delivery well arranged along one or more planes intersecting the at least one thermal injection well and the at least one production well; and wherein the method further comprises stimulating the underground reservoir within the at least one volume surrounding the production well with synchronized oscillatory pressure waves provided in the production well and in at least one of the at least one thermal injection well or at least one heat delivery well.
Description
BRIEF DESCRIPTION OF THE FIGURES
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DETAILED DESCRIPTION OF THE FIGURES
(44) The comprehensive enhanced oil recovery system according to the invention can integrate one or more of the following features: 1. A boiler system that provides power and resources in a closed loop. (See, e.g.,
Green Boiler System (FIGS. 4-9)
(45) In petroleum geology, a reservoir is a porous and permeable lithological unit or set of units in a formation that hold hydrocarbon reserves such as crude oil and natural gas. The flow rate (Q) of the hydrocarbon reserves through such a formation may be determined according to Darcy's Law:
(46)
where Q is the flowrate (in units of volume per unit time), is the relative permeability of the formation (typically in millidarcies), A is the cross-sectional area of the formation, is the viscosity of the fluid (typically in units of centipoise), and p/x represents the pressure change per unit length of the formation that the fluid will flow through.
(47) Crude oil viscosity () is its resistance to flow. It may be viewed as a measure of its internal friction such that a force is needed to cause one layer to slide past another. Newton's law of viscosity states that the shear stress between adjacent fluid layers is proportional to the negative value of the velocity gradient between the two layers. Alternatively, the law may be interpreted as stating that the rate of momentum transfer per unit area, between two adjacent layers of fluid, is proportional to the negative value of the velocity gradient between them. The unit of viscosity in cgs units is dyne.Math.sec/cm.sup.2 (1 dyne-sec/cm.sup.2 is called a poise (P)). From the units, it will be evident that viscosity has dimensions of momentum per unit area. One Poise (P) in mks units is 0.1 kg.Math.m.sup.1.Math.s.sup.1. The SI unit for viscosity is the pascal.Math.second (Pa.Math.s) which equals 10P. A centipoise is one-hundredth of a poise and one millipascal.Math.second (mPa.Math.s).
(48) API (American Petroleum Institute) gravity is an inverse measure of the relative density, as compared to water, of crude oil. It is measured in units called API degrees (API). The lower the number of API degrees, the higher the specific gravity of the oil. If greater than 10, the oil floats. If less than 10, it sinks.
(49) The permeability to flow through a rock for the case where a single fluid is present is different when other fluids are present in the reservoir. Saturation, the proportion of oil, gas, water and other fluids in a rock is a crucial factor in a pre-development evaluation of the reservoir. The relative saturations of the fluids as well as the nature of the reservoir affect the permeability. Crude oil mobility (.sub.0) is the ratio of the effective permeability (.sub.0) to the oil flow to its viscosity (.sub.0):
.sub.2=.sub.0/.sub.0
The effective permeability characterizes the ability of the crude oil to flow through the rock material of the reservoir. As will be evident from the above-mentioned Darcy's Law, permeability should be affected by pressure in the rock material. The millidarcy unit mentioned above in connection with the typical unit used for permeability (K) is related to the basic unit of permeability measure, m.sup.2 in the mks system. The darcy is referenced to a mixture of unit systems. A medium with a permeability of 1 darcy permits a flow of 1 cm.sup.3/s of a fluid with viscosity 1 cP (1 mPa.Math.s) under a pressure gradient of 1 atm/cm acting across an area of 1 cm.sup.2. A millidarcy (md) is equal to 0.001 darcy. Rock permeability is usually expressed in millidarcys (md) because rocks hosting hydrocarbon or water accumulations typically exhibit permeability ranging from 5 to 2000 md.
(50) Thus, the principle used herein is that heat applied to a reservoir increases its permeability and reduces the viscosity of the crude oil to increase the oil mobility. In other words, lowering oil viscosity with heat increases the flow rate of the oil. Conventional heating methods include cyclic steam injection, steam flooding and fire flooding. For cyclic steam injection, steam may first be injected into a well for a few days or weeks. Then the heat is allowed to dissipate into the reservoir for a few days to reduce oil viscosity. Finally, the production begins with improved flow rate. The three step process is then repeated e.g. after the flow rate diminishes. In steam flooding some wells are used for injecting steam and others for oil production. The steam flood acts to both heat the reservoir and push the oil by displacement toward the production wells. In many cases gravity is also used to move the oil toward the production well. Fire flooding is where combustion generates heat within the reservoir itself.
(51) TABLE-US-00001 TABLE 1 Composition by Weight Hydrocarbon Average Range Melting or Liquification Point Paraffins 30% 15 to 60% 115 F. to 155 F. (46 C. to 68 C.) Naphthenes 49% 30 to 60% Aromatics 15% 3 to 30% Asphaltenes 6% Remainder 180 F. (82 C.) Karogen 842 F. to 932 F. (450 C. to 500 C.)
It should be realized that the viscosity is affected by temperature, pressure, and by composition. Among others, the following conditions impact oil flow rate:
1) Crude oils contain substantial proportions of saturated and aromatic hydrocarbons with relatively small percentages of resins and asphaltenes and other substances as listed in Table 1. More degraded crude oils contain substantially larger proportions of resins and asphaltenes. Heavy crude oil (API<22) occurs when the oil contains paraffin and/or asphaltenes and the temperature of the oil reservoir is too low. See Table 1 above for melting or liquification points and see also
2) Crude oil (including light crude oil API>30) viscosity increases as it cools due to one or more of the following conditions: a) the oil reservoir is shallow and the temperature of the reservoir is low; b) it is heavy crude oil (API<22); c) the oil reservoir is deep and the oil cools as it is pumped out of the well; d) the ambient temperature is extremely cold and the oil cools quickly as it is exposed to the cold near or at the surface; and e) any set of conditions where the oil cools and the viscosity increases and this adversely effects the efficiency of the oil flow in a production well.
(52) As will be appreciated from the foregoing, heating the reservoir to remove barriers to the flow of fluids into a well will tend to lower the viscosity of the fluids so that the existing permeability will allow the oil to flow with an increased rate and hence increased volume to the production wells. An important teaching hereof is to burn crude oil or natural gas extracted from an underground reservoir (or burn both crude oil and natural gas extracted from the underground reservoir), in order to provide thermal energy. In other words, the teaching is to supply the necessary power and materials from the reservoir itself to mobilize the oil and move it to the production wells. A heat source fed by fuel produced from the reservoir accomplishes the production of heat. It does so in such a way, as shown below, as to allow enhanced oil recovery that is environmentally benign.
(53) Thus a method is disclosed herein, in that a portion of the crude oil or natural gas extracted from an underground reservoir is burned for providing thermal energy. Or, both crude oil and natural gas extracted from an underground reservoir is burned, for providing thermal energy. The thermal energy is transferred to brine separated from the extracted oil, gas, or both, for providing heated brine. Or, the thermal energy is converted to mechanical work. Or, the thermal energy is both transferred to the separated brine and converted to mechanical work. The underground reservoir is heated with the heated brine by injection into the underground reservoir. Or the underground reservoir is heated with a resistive cable energized by electricity generated by converting the mechanical work to electric energy. Or, the underground reservoir is heated with both heated brine and heat from an energized resistive cable.
(54) For instance, a Green Boiler may be provided to burn natural gas, crude oil, or both, produced from a reservoir. The boiler may be used to heat a flow of water that circulates in a closed loop out of a heat exchanger in a cooled condition and return a flow of heated water into the heat exchanger in order to transfer heat from the heated water to the brine pumped from a production well and injected back into the reservoir after gaining heat and flowing out of the heat exchanger. As such, the Green Boiler is a closed loop system that uses the resources of an oil and gas reservoir to enhance the extraction of oil and gas. The system eliminates any flaring gas and eliminates any negative emissions of any pollutants into the atmosphere. The byproducts may thus be used in the enhancement process. The heat exchanger may be any type that will transfer heat efficiently from the heated water to the brine such as a counter-flow heat exchanger where the fluids enter the exchanger from opposite ends.
(55)
(56) The natural gas 116 supplied by the manifold 114 may also be supplied to one or more gas, crude oil, or diesel fueled heat engines such as a gas turbine generator 127 that provides electricity 128. The electricity output from the generator may be connected to an electric resistant cable that is used to produce heat for heating a thermally assisted oil well. The electricity may be used for other purposes as well.
(57) The separated brine 110 from the separator 106 may be provided to a heat exchanger/mixer 130 to be heated. Although shown as a combined heat exchanger/mixer 130, it should be realized the heat exchanger and mixer could be separate. The thermal energy provided by the boilers 118 may be transferred to a fluid such as water circulating in a closed loop through the boilers and the heat exchanger. Heated water is shown being provided on one or more pipe lines 119 from outlets of the boilers 118 to at least one inlet of a hot water manifold 121. An outlet of the hot water manifold provides hot water on a line 123 to an inlet of a heat exchanger part of the heat exchanger/mixer 130 or to a separate heat exchanger.
(58) Hot exhaust gases from the one or more heat engines such as exhaust 129 from the plurality of gas boilers 118 and/or exhaust gases 131 from a gas turbine of the turbine generator 127 are provided to an exhaust scrubber 132. Scrubbed exhaust gases, containing CO.sub.2 and N.sub.2 for example, are then provided on a line 133 to the mixer part of the heat exchanger/mixer 130 or to a separate mixer. The mixer performs a mixing of the scrubber exhaust gas 133 from the scrubber 132 (fed by at least one of a heating vessel, e.g., boiler(s) 118 and a heat engine e.g. a turbine of turbine generator 127) with the separated brine at least before, during, or after the transfer of thermal energy to the separated brine, wherein hot brine on the line 140 mixed with the exhaust gas 133 is injected into the underground reservoir via one or more injection wells. A mixer may have a series of fixed, geometric elements enclosed within a housing. The fluids to be mixed are fed at one end and the internal elements impart flow division to promote radial mixing while flowing toward the other end. Simultaneous heating can be done if the mixer is inside the heat exchanger.
(59) The heat exchanger is thus for transferring the thermal energy produced in the boilers 118 to the separated brine 110, for providing heated brine on the line 140, or for converting the thermal energy to mechanical work for instance by a turbine part of the turbine generator 127, or (as in
(60) The system of
(61) Cooled circulating water on a line 150 that is shown circulating out of an outlet of the heat exchanger/mixer 130 is returned to the boilers 118 for re-heating and for again being fed into the hot water manifold 121 on lines 119 for heating more brine produced on an on-going basis by the wells 102. Geothermal heat 191 may be supplied to the hot water manifold 121. It is noted that hot water from the hot water manifold 121 may be further provided on a line 171 to provide heat for a thermally assisted oil well 170, or on a line 181 to other applications 180 requiring heat. The cooled water from these applications can be fed into the cooled circulating water on a line 150 by way of separate lines 172 or 182. It should be mentioned that if viscosity reducing additives are used for instance as shown on a line 160 for mixture in a mixer (not shown) with the extracted brine 110, there will need to be an additive separator (also not shown) as signified by the brine being sent on a line 162 to such an additive separator before it is returned on a line 110a to the heat exchanger/mixer 130.
(62) Another exemplary Green Boiler System is shown in detail in
(63) 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).
(64) 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 211 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.
(65) 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 brine-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 re-heating.
(66) 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.
(67) 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.
(68) The one or more injection wells 201 inject heated brine and/or oil, hot exhaust gases such as CO.sub.2, N.sub.2 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.
(69) 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.,
(70) 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 201a in the reservoir between the two wells, they interfere constructively as shown in
(71) One or more monitor wells 223 may be employed to provide control information to a control system that controls the operations of the system.
(72)
(73) Also shown in
(74) A further embodiment for circulating fluid in a reservoir is shown in
(75) The system shown in
(76)
(77) The production well 383 pumps oil, gas, brine and/or water 352. The production well 383 is equipped with an oscillator 368a and a jet pump 373, which aid in generating the pressure waves 385 that are used to increase oil recovery in the reservoir. A manifold 374a is also provided between the production well and a separator 353. The separator 353 separates the brine 351, gas 354 and the oil 355.
(78) A boiler and steam turbine or generator 360 is provided with oxygen from an oxygen/nitrogen separator 358, and is provided with the separated oil 354 and with methane/Carbon Dioxide (CH.sub.4/CO.sub.2) 357 from a carbon dioxide/methane separator 356, receiving the separated gas 354. Using these components, the boiler 360 convert water from the steam turbine 362 into steam 361 and generates electricity for operations 364, electricity for sale on the energy market 384, and supplies electricity 365 to an electric heating cable 366 in the production well 383. CO.sub.2 359 from the oxygen/nitrogen separator 358 can also be added to the inlet flow to the boiler 360 as needed to control flame temperature without adding unwanted N.sub.2 to the exhaust stream.
(79) The exhaust of the boiler and steam turbine or generator 360 is provided to one or more heat exchangers 390 configured to heat water and/or brine. Separated brine 351 is mixed with water and additives 393 and pumped by a pump 392a to a heat exchanger 390, which heats the brine and outputs heated brine 370 to the injection well 380. Carbon dioxide 359, separated by the separator 356, is mixed with hot exhaust 363 from the heat exchanger 390, and compressed by a compressor 391. The compressed and heated CO.sub.2 and exhaust gases 367 are supplied to a manifold 374b, and pumped into the injection well 380, which also incorporates an oscillator 368b to aid in creating pulsing pressure waves 385.
(80) The heat delivery well 381 is provided with a manifold 374c. The heat delivery well 381 pumps via a pump 392b cooled water 372 to a heat exchanger 390, which outputs heated water 371. The heated water 371 is provided to the heat delivery well 381 to transfer heat into the well. As the heated water 371 transfers heat to the well, the water cools and the cooled water 372 is provided back to the heat exchanger 390 in a cyclical manner.
(81) An example of a heat delivery well 275, as discussed above in reference to earlier Figures, is shown in
(82) An example of a production well 280, as discussed above in reference to earlier Figures, is shown in
(83) It should be realized that systems such as shown in
Enhanced Oil Recovery Pulsing (FIGS. 10a-10d and 12-13)
(84)
(85) In accordance with the present invention, excitation of an oil reservoir with a pressure wave results in a repeating pattern of high-pressure and low-pressure regions moving through the oil reservoir, which enhances oil recovery by causing movement in the walls of a pore 475 of a particle of rock 470, so as to induce movement and flow of capillaries 450 out of the pore 475, as shown in
(86) Wave interference is the phenomenon that occurs when two waves meet while traveling along the same medium. The interference of waves causes the medium to take on a shape that results from the net effect of the two individual waves upon the particles of the medium. Consider two pulses of the same amplitude traveling in different directions along the same medium. Each pulse is displaced upward one unit at its crest and has the shape of a sine wave. As the sine waves move towards each other, there will eventually be a moment in time when the waves completely overlap. At that moment, the resulting shape of the medium would be an upward displaced sine pulse with amplitude of two units. This is constructive interference as shown in
(87) According to the teachings of the present invention, constructive wave interference, such as shown in
(88) At a microscopic level a reservoir may contain hydrocarbon reserves as shown in
(89) When the reservoir is disturbed or displaced by imparting energy by way of stimulation, for instance by wave excitation, the displacement will give rise to an elastic force in the material adjacent to it, then the next particle of water 420, oil 430, or gas 440 will be displaced, and then the next, and so on. The displacement will be propagated with a speed dependent on the physical properties of the reservoir. If the excitation is oscillatory, an oscillatory pressure wave is the result, i.e., a wave that results from the back and forth vibration of particles of the medium through which the wave is moving. If a wave is moving from left to right through a medium, then particles of the medium will be displaced both rightward and leftward as the energy of the wave passes through it. The motion of the particles is parallel to the direction of the energy transport. This is what characterizes waves as longitudinal waves.
(90) A system and methodology for stimulating a reservoir with pressure waves is shown in
(91)
(92) The control system 540 of
(93) In an exemplary operation of the present invention, the oil production well 510 is pulsed, creating the first pressure wave 518 in the reservoir. The pressure wave 518 generated by the production well 510 has the effect of pulling oil, gas and/or brine towards the oil production well 510 through ports in the production well 510, where the oil is then pumped to the surface. The pressure pulse 518 can be generated by pulsing the pump 512 or by opening and restricting the flow through the valve 514 to the production well 510 using a valve 514. The amplitude of the pressure wave 518 is determined by the amount the pump 512 power is varied or the amount the flow is restricted through the valve 514 by partially closing the valve 514. The frequency of the pressure wave 518 is controlled by timing the pulsing of the pump 512 or the timing of opening and partially closing the valve 514. Another way of generating the pressure wave 518 is by adding a transducer that will provide additional timed pressure pulses to the flow. A starting low frequency for the generated pressure wave 518 is determined by the make-up of the geology of the reservoir. Once a starting frequency is selected, the frequency can be increased and/or decreased by the control system 540 until the maximum oil and gas flow is achieved. More than one frequency can be used over the course of generating the pressure waves 518.
(94) Further, one or more injection wells 520, 530 are pulsed creating pressure waves 528, 538 in the reservoir. The pressure waves 528, 538 generated by the injection wells 520, 530 from brine and CO.sub.2 passing through ports in the injection wells 520, 530 have the effect of pushing oil towards the oil production well 510, where the oil is then pumped to the surface. The pressure waves 528, 538 can be generated by pulsing the pump 522, 532, or by opening and restricting the flow through the valves 524, 534 through the injection wells 520, 530 using the valve 524, 534. The amplitude of the pressure waves 528, 538 is determined by the amount the pump 522, 532 power is varied or the amount the flow is restricted through the valves 524, 534 by repeatedly partially closing and opening the valves 524, 534. The frequency of the pressure waves 528, 538 is controlled by timing the pulsing of the pump 522, 532 or the timing of opening and partially closing the valves 524, 534. Another manner of generating the pressure waves 528, 538 is by adding a transducer that will add additional timed pressure pulses to the flow. The frequency (or frequencies if more than one frequency is used) of the waves 528, 538 should match the frequency of the pulsing waves 518 of the oil and gas production well 510. The timing of the creation of the pressure wave 128, 138 is timed by the control system 540 so that constructive wave interference 550, 552 is achieved to create a heightened pressure wave 480. The constructive wave interference 550, 552 increases the amplitude and distance the pressure wave 480 may penetrate and influence flow in the reservoir, which increases the pushing and pulling effects of the waves.
(95) The control system 540 constantly monitors the pressure wave system and adjusts the frequencies and amplitudes of the pressure waves 518, 528, 538 in order to maximize oil 430 and gas 440 flow out of the rock pores 470, and hence maximize the volume of oil 430 and gas 440 extracted per unit time. Because the pressure waves 518, 528, 538 will travel through different media of the reservoir at different speeds, the control system 140 is configured to adjust the timing of the pressure waves to ensure the maximum effect on the oil and gas extraction. The speeds of pulsing waves through various media are indicated below in Tables 2, 3 and 4.
(96) TABLE-US-00002 TABLE 2 (Solids) Density Vl Vs Vext Substance (g/cm.sup.3) (m/s) (m/s) (m/s) Metals Aluminum, rolled 2.7 6420 3040 5000 Beryllium 1.87 12890 8880 12870 Brass (70 Cu, 30 Zn) 8.6 4700 2110 3480 Copper, annealed 8.93 4760 2325 3810 Copper, rolled 8.93 5010 2270 3750 Gold, hard-drawn 19.7 3240 1200 2030 Iron, Armco 7.85 5960 3240 5200 Lead, annealed 11.4 2160 700 1190 Lead, rolled 11.4 1960 690 1210 Molybdenum 10.1 6250 3350 5400 Monel metal 8.9 5350 2720 4400 Nickel (unmagnetized) 8.85 5480 2990 4800 Nickel 8.9 6040 3000 4900 Platinum 21.4 3260 1730 2800 Silver 10.4 3650 1610 2680 Steel, mild 7.85 5960 3235 5200 Steel, 347 Stainless 7.9 5790 3100 5000 Tin, rolled 7.3 3320 1670 2730 Titanium 4.5 6070 3125 5080 Tungsten, annealed 19.3 5220 2890 4620 Tungsten Carbide 13.8 6655 3980 6220 Zinc, rolled 7.1 4210 2440 3850 Various Fused silica 2.2 5968 3764 5760 Glass, Pyrex 2.32 5640 3280 5170 Glass, heavy silicate flint 3.88 3980 2380 3720 Lucite 1.18 2680 1100 1840 Nylon 6-6 1.11 2620 1070 1800 Polyethylene 0.9 1950 540 920 Polystyrene 1.06 2350 1120 2240 Rubber, butyl 1.07 1830 Rubber, gum 0.95 1550 Rubber neoprene 1.33 1600 Brick 1.8 3650 Clay rock 2.2 3480 Cork 0.25 500 Marble 2.6 3810 Paraffin 0.9 1300 Tallow 390 Ash, along the fiber 4670 Beech, along the fiber 3340 Elm, along the fiber 4120 Maple, along the fiber 4110
(97) TABLE-US-00003 TABLE 3 (Liquids) Density Velocity at v/t Substance Formula (g/cm.sup.3) 25 C. (m/s) (m/sec C.) Acetone C.sub.3H.sub.6O 0.79 1174 4.5 Benzene C.sub.6H.sub.6 0.87 1295 4.65 Carbon tetrachloride CCl.sub.4 1.595 926 2.7 Castor oil CH.sub.11H.sub.10O.sub.10 0.969 1477 3.6 Chloroform CHCl.sub.3 1.49 987 3.4 Ethanol amide C.sub.2H.sub.7NO 1.018 1724 3.4 Ethyl ether C.sub.4H.sub.10O 0.713 985 4.87 Ethylene glycol C.sub.2H.sub.6O.sub.2 1.113 1658 2.1 Glycerol C.sub.3H.sub.8O.sub.3 1.26 1904 2.2 Kerosene 0.81 1324 3.6 Mercury Hg 13.5 1450 Methanol CH.sub.4O 0.791 1103 3.2 Turpentine 0.88 1255 Water (distilled) H.sub.2O 0.998 1496.7 2.4
(98) TABLE-US-00004 TABLE 4 (Gases) Density Velocity v/t Substance Formula (g/L) (m/s) (m/sec C.) Air, dry 1.293 331.45 0.59 Ammonia NH.sub.3 0.771 415 Argon Ar 1.783 319 0.56 (at 20 C.) Carbon monoxide CO 1.25 338 0.6 Carbon dioxide CO.sub.2 1.977 259 0.4 Chlorine Cl.sub.2 3.214 206 Deuterium D.sub.2 890 1.6 Ethane (10 C.) C.sub.2H.sub.6 1.356 308 Ethylene C.sub.2H.sub.4 1.26 317 Helium He 0.178 965 0.8 Hydrogen H.sub.2 0.0899 1284 2.2 Hydrogen chloride HCl 1.639 296 Methane CH.sub.4 0.7168 430 Neon Ne 0.9 435 0.8 Nitric oxide (10 C.) NO 1.34 324 Nitrogen N.sub.2 1.251 334 0.6 Nitrous oxide N.sub.2O 1.977 263 0.5 Oxygen O.sub.2 1.429 316 0.56 Sulfur dioxide SO.sub.2 2.927 213 0.47 Vapors Acetone C.sub.3H.sub.6O 239 0.32 Benzene C.sub.6H.sub.6 202 0.3 Carbon tetrachloride CCl.sub.4 145 Chloroform CHCl.sub.3 171 0.24 Ethanol C.sub.2H.sub.6O 269 0.4 Ethyl ether C.sub.4H.sub.10O 206 0.3 Methanol CH.sub.4O 335 0.46 Water vapor (134 C.) H.sub.2O 494 0.46
(99) A further method for generating pressure pulses in accordance with the invention is shown in
(100) A second, insulated water tube 502 is provided with a supply of cooler water that flows through the tube 502. The water supplied through the tube 502 is supplied in a timed, pulsed manner. As a result, water escapes through the perforations of the tube outlet 505 and mixes with the previously described vaporized water created from the drop in pressure of the water from tube 501 in spurts. The temperature of the resulting combined flow is lower and the causes the vaporized water to reliquify and with a significant pressure decrease.
(101) The rapid change of the water from a liquid form to a vapor form and back to a liquid form causes large pressure jumps and rapid depressurization. This creates a substantial pressure pulsing wave for pushing oil and gas in a reservoir to an oil production well.
(102) The pipe 500 of
(103) The techniques for generating pressure pulsing waves in an oil or gas reservoir are not limited to those techniques previously described, but other techniques can be used without departing from the spirit of the invention.
(104) Wave models will determine the optimum frequency, placement, and timing or phasing of pressure oscillations to maximize amplitude of the pressure waves at the target locations in the field. As shown in
(105) An example of a formation according to an embodiment of the invention is shown in
(106) The injection ports 560 are each separated by a distance W.sub.1. As an example, when the ports are separated by a distance of forty-two feet, waves having a frequency of twenty-seven hertz can be created. Pressure waves 561 are generated at the injection ports 560, each also having a wavelength that is the same distance W.sub.1 as the distance W.sub.1 between injection ports 560. By generating waves 561 with wavelengths W.sub.1 corresponding to the distance W.sub.1 between injection ports 560, the waves 561 constructively interfere and double in amplitude. In
(107) The extraction ports 570 are each separated by a distance W.sub.2. Pressure waves 571 are generated at the extraction ports 570, each also having a wavelength that is the same distance W.sub.2 as the distance W.sub.2 between extraction ports 570. By generating waves 571 with wavelengths W.sub.2 corresponding to the distance W.sub.2 between extraction ports 570, the waves 571 constructively interfere and double in amplitude. The distance W.sub.1 between injection ports 560 and the distance W.sub.2 between extraction ports 570 can be the same distance, and correspondingly the pressure waves 561 and 571 can have the same wavelength. In
(108) A second level of constructive interference occurs when the waves 561 from the injection wells 561 meet the waves 571 of the extraction wells 570. This further constructive interference results in waves 562 and 572 that are further increased in amplitude. If the wavelengths W.sub.1 and W.sub.2 of the waves 561 and 571 are the same, the amplitudes will double.
(109) A control system 540, as shown and described in
(110) Pulsed pressure waves are used to move oil that is locked into formations by being trapped by surface tension in the small capillary sized openings in the formation rock. The steep localized pressure gradient in a pressure pulse can move the oil droplets through the capillaries until they encounter larger passageways. The oil can then flow via the overall pressure gradient in the formation created by either natural pressure gradients or those induced by pumps for the production and injection wells. This increases oil recovery rates and overall yields in lower permeability formations. The portion of the tightly held oil that can be moved by a given pressure wave generator is dependent on the distribution of oil and gas in the formation, the pore size, the surface tension of the oil, the water and free gas content co-located in the formation and the number and size of the capillaries. By further heating the oil in the formation using techniques described below, the surface tension of the oil can be significantly reduced, i.e., by 50% or more, resulting in a significant increase in the amount of the formation oil that can be freed by this technique.
Thermal and Brine CO2 Flooding (FIGS. 16 and 17)
(111) A further technique that can be integrated into the comprehensive system according to the invention is thermal flooding of an oil and gas reservoir to maximize extraction rates and total yield from an oil and gas reservoir. Using an oil/heat delivery matrix, the rock or sand pores containing the oil, gas and water/brine, as shown in
(112) Heat is applied to an oil or gas field to lower the viscosity and surface tension in crude oil field rock pore 475 capillary cracks 450, as shown in
(113) As the heat is applied, the rock 470 expands, which shrinks the rock pore 475. The water 420, oil 430 and gas 440 all also expand. Each of these expansions creates pressure. The oil 430 emits gas, further creating pressure. The viscosities of the oil 430, gas 440 and water 420 lower and the interfacial tension or surface tension 460 of the capillary restrictors 450 is broken and the fluids 420, 430, 440 start to flow.
(114) Changing the rock pore 475 viscosity and breaking the surface tension 460 create flow paths for the oil 430 and gas 440 through the oil/heat delivery matrix.
(115) Hot fluid injection 490, including both brine and CO.sub.2 and preferably from a perforated horizontal pipe, can further provided, as shown in
(116) The injected CO.sub.2 (and in some instances N.sub.2) pushes the fluids (water 420, oil 430 and gas 440) in the rock pore 475 having a very low viscosity towards the producer well. The CO.sub.2 mixes with the oil 430, which lowers the viscosity of the oil 430. The hot CO.sub.2 and brine 490 heat the water 420, oil 430 and gas 440. As the viscosity of the fluids is lowered, the brine and CO.sub.2 continues to push the fluids toward the producer well. Additionally, the increase in pressure that is created enhances the breaking of the interfacial tension 460 of capillary restrictors 450. The directional pressure further creates oil and gas mobility.
(117) The parameters that determine the effectiveness of the CO.sub.2 injection are further relevant to the miscibility of CO.sub.2 and N.sub.2 and crude oil. Miscibility refers to the ability of two substances to be mixed. The oil 430 and gas 440 are miscible and mix well, unlike oil 430 and water 420, which are immiscible. Whether CO.sub.2 is miscible in specific oil in a reservoir depends on both the pressure and temperature in the reservoir. The lower the oil API (i.e., the heavier the crude), the higher the required minimum miscible pressure (MMP) will be. This relationship is shown in
(118) CO.sub.2 and N.sub.2 flooding of oil reservoirs is used to increase the mobility of the oil and to increase both the rate and the percentage of oil recovered from the reservoir. CO.sub.2 is soluble in oil, with the amount of CO.sub.2 that can be absorbed depending on oil composition and temperature, as discussed above. All crude oil weights can absorb significant amounts of CO.sub.2. When CO.sub.2 is absorbed into the oil, it decreases the viscosity of the oil and the interfacial tension between the oil and the rock, both of which increase the oil's mobility. Oil highly saturated with CO.sub.2 (and N.sub.2) can have viscosity reduced by one to two orders of magnitude. This absorption also causes the oil to swell which helps force the oil out of voids where it can be trapped. CO.sub.2 and N.sub.2 are generated by burning crude oil or gas that was normally flared, in a boiler, scrubbing the exhaust and re-injecting the CO.sub.2 and N.sub.2 and other gases into the reservoir, as described and shown in
(119) Heavy crudes and CO.sub.2 miscibility are generally found at less deep locations than light crude. This means that reservoir pressures are frequently below the MMP for heavy crudes. A reservoir will usually have about 1 psi (pound per square inch) of pressure for every 2 feet of depth. As seen in
(120) One technique that is commonly used in enhanced oil recovery processes using CO.sub.2 and N.sub.2 is to alternate brine (water) and CO.sub.2 and N.sub.2 injection. This tends to create water fronts that push the oil toward the production well that has been mobilized by the previous CO.sub.2 and N.sub.2 injection cycle. This water and gas alternating process (water after gas or WAG) has proven highly successful.
(121) Thermal enhanced oil recovery processes can be combined with CO.sub.2 and N.sub.2 processes to yield excellent results. The majority of the benefit of CO.sub.2 and N.sub.2 absorption to oil mobility occurs early in the approach to saturated levels of CO.sub.2 and N.sub.2 in the oil, so that much of the reduced viscosity benefit is obtained at low saturation levels. The combination of increased temperature and CO.sub.2 and N.sub.2 absorption both increase mobility. This is especially convenient if the CO.sub.2 and N.sub.2 can be obtained from burning natural gas (and/or crude oil) that is frequently contained in the harvested oil. The combustion of this gas yields CO.sub.2 and the thermal energy that can be added to the water (or brine) that is injected into the reservoir when applying enhanced oil recovery processes described in accordance with the present invention.
(122) Though varying significantly based on crude oil composition, surface tension () values at 100 F. (32 C.) range from 20 to 40 dynes/cm for oil, gas, rock interfaces. Values are roughly half that value for oil, water, rock interfaces. What is fairly consistent is the change in surface tension with temperature, generally running in the 0.10 to 0.18 dynes/cmK range.
(123) For example, by heating the formation oil from a typical temperature of 40 C. to 140 C., the surface tension would drop from 30 dynes/cm to 15 dynes/cm. As a quantitative example, for a pore size (d) of 1 mm (0.1 cm), the force required to break surface tension is estimated as follows:
F=.Math.d.Math.cos()=6.6 dynes When it is assumed there is a 45 degree contact angle for
(124) If it is assumed a single bubble in a gas filled pore has a pressure gradient of
dp/dx=F.Math.(4//d.sup.3)=8400 dynes/cm.sup.3=0.31 psi/in The issue then becomes what pressure pulse will create that pressure gradient in the pore. The peak gradient in a sine wave is calculated by the following:
dp/dt=.Math.A.Math.f where f is the pulse frequency and A is the pulse pressure amplitude If divided by the wave speed (v) which is dx/dt, it provides the peak physical gradient.
dp/dx=.Math.A.Math.(f/v) The frequency f in Hz is typically approximately 20 Hz to minimize attenuation while traveling through the formation A reasonable pressure wave velocity in a formation (gas/oil/water mixture) is 2000 m/s (78000 in/s) Equating the two equations allows solving for the required pressure pulse amplitude to dislodge the oil droplet.
A=0.31.Math.(v//f)=0.31.Math.(78000//20)=385 psi
(125) If the surface tension is halved then the pressure amplitude required is halved.
The Oil/Heat Delivery Matrix (FIGS. 20a-33)
(126) The position of the production, injection, and heat delivery wells is critical to maximizing the flow enhancement from the thermal and injection processes described above. There are a number of arrangements that can be used. The preferred arrangement for a particular reservoir can be selected based on the characteristics of the specific reservoir and the results of the performance models. The following sections will describe several of these arrangements, but are not intended to be an exhaustive listing of all of the possible permutations. These arrangements include: (1) a perpendicular layout having heat delivery wells running perpendicular to the production and injection wells, or lateral formations (
(127) In each of these arrangements, a key for long term success and maximizing the extracted amount of the closely held oil is to adjust the injection and extraction points to bias the oil, water, and gas flows induced by the injection well and production well pulsed pumping to move through areas of newly heated resource as the thermal soaking profile of the resources evolves over time. The adjustment of the fluid injection and extraction points along the length of these wells can be implemented using a number of mechanical means. These methods can involve the use of slotted liners and packers with variable positioning mechanisms, the use of controllable valves or other methods.
(128) The spacing of the injection ports and the extraction ports are critical to achieve the first level of constructive interference. The ports are preferably approximately one wave length of the pulsing frequency apart in order to have a first level of constructive interference, as shown in
(129) A region heated to a given temperature around the heat delivery wells expands over time as the heat soaks into the resource. The rate of heat absorption by the resource is controlled by the both conduction characteristic through the fluid and rock, and by the convective flow cells created in the fluid by the differential temperature between the heat delivery well and the formation. A heat transfer model is used to predict the increasing diameter of this heat soak over time. The viscosity of the oil is a critical value in determining the convective effect on the thermal soak rate. A typical result is shown in
(130) As mentioned above, the flow pattern from the injection well to the production well must be biased to direct flow through newly heated regions in the formation. Regions that are initially heated by the heat delivery wells (at closer radii from the pipe) will be swept by the pulsing injection flow and the oil extracted. As new, oil rich regions are heated (enabling pulse driven flow) the injected flow locations and the entry points to the production well must be adjusted to direct the flow through these newly heated regions. As these inlet and outlet flow locations are moved further from the heat delivery well location as the regions are heated, new oil rich regions will be swept with the injection fluids. Over time, the entire resource can be addressed.
Option 1Perpendicular Layout
(131) According to a first embodiment shown in
(132) This cross hatched pattern of heat delivery wells create low viscosity paths for the flooding (steam, water and CO.sub.2). In this arrangement the heat does not need to expand radially from the source to achieve this as low viscosity paths 630 are immediately created. As the heat does expand radially from the heat delivery well over time, the entire net pay zone is addressed.
(133) In the matrix arrangement shown in
(134)
(135)
(136) The system shown in
(137) The combination of the injector wells 610, heat delivery wells 620 and producer well 605 as shown in the
(138)
(139) The oil/heat delivery matrix can be established with perpendicular heat delivery wells or with any combination of perpendicular wells and angled wells, as shown in
(140) Using the flow path approach of the perpendicular matrix arrangement, heat delivery wells 620 create low viscosity areas 650 and low viscosity flow paths 630 for the oil to flow to the production well 605. The flow paths 630 also allow the other enhanced oil recovery techniques to operate with maximum efficiency. Heat delivery wells 620 also create a delivery matrix of low viscosity paths 630 for the flooding techniques (using steam, water and CO.sub.2 as described previously), pressure and pulsing to directionally enhance oil flow to the producer. The cross-hatched design of production wells 605, injection wells 610, and heat delivery wells 620 lowers drilling and installation cost, provides immediate low viscosity flow zones, creates many simultaneous flow paths, provides heat expansion in a non-linear fashion once flow starts, and over time, the design addresses the entire net-pay zone.
Option 2Parallel Layout
(141) According to a second embodiment shown in
(142) This arrangement can be implemented with ether one or more heat delivery wells 620 being provided in the space between injection wells 610 and production wells 605.
(143)
(144)
(145)
(146)
Option 3Circular Layout
(147) As a third alternative embodiment, a circular well layout can be provided.
(148) This arrangement can be used in situations where the drilling pad must be located in a central location. For example, this embodiment may be preferred for a reservoir beneath a bog or wetland where it is preferable to locate the surface equipment for the system, such as the equipment shown above the surface in the embodiments of
Option 4Vertical Well Layout
(149) A fourth embodiment for an arrangement is shown in
(150) The systems shown in the Figures herein can all incorporate a control system, such as control system 540 shown in
(151) The production to injection well spacing can be set so that constructive interference of the pressure pulses created by the injection well (pushing) and the production well (pulling) can be easily synchronized. During operation, pressure amplitude and phasing data can be taken at a monitoring well, and at the injection and production wells, along with flow rates of injected and extracted fluids. Frequency and phasing of the pulsed pumping in the wells can be adjusted to create the constructive interference so that amplitude of the pulses can be maximized for the target extraction zone.
(152) Another key to full reservoir harvesting is to adjust the location of the primary injection and extraction zones (the span of the series of evenly spaced access ports) along the well length as the resource matures, when a significant amount of oil has been extracted, and the region of higher temperature has expanded significantly into the resource. This is critical to directing the pulsed flow waves through newly heated regions in the resource so that the new oil reserves are accessed and swept toward the production well so that the oil to water ratio in the fluid entering the production well is maximized methods involving valves, concentric tubing, and acoustic manipulation can also be used. During operation, the control system can use information from the extracted flows such as flow rates and specifically oil to water ratio to determine when the pressure and flow access regions need to be adjusted. Unlike the pulse frequency and phasing control, which has a control loop cycle of seconds, the pulsed flow access region manipulation will only be adjusted in multiple month or year time periods.
(153) A final key control aspect is the measurement of the heated zone radius around the heat delivery wells. The heated region around the heat delivery wells expands radially from the well bore over time. Knowing the position of the heated region where oil viscosity and surface tension are reduced is critical to determining the specific positioning of the well lengths where flow into and out of the resource needs to be restricted so that the flow path of lower flow resistance leads to harvested volumes of the reservoir. This radius can be measured at various locations on the monitoring well. The monitoring well and heat delivery wells do not run parallel so as to allow the temperature versus radial position from the heat delivery well.
(154) The pressure amplitude of the pulsed pumping wave that is required to loosen oil held in tightly held formations can be determined in advance of operation. During operation, the control system can change the pulse amplitude in relatively small increments and then record the resulting extraction rate and composition of the oil. The energy used to extract the oil will be compared to the yield to maximize the efficiency of the process. This period for the modification of control parameters will be measured in days.
(155) Perturbations of injected flow rate and temperature will also be imposed on the system and the oil extraction results assessed. A control algorithm can calculate the optimum injection rate and fluid temperature to optimize the net energy extracted.
(156) The control system can also vary the amount of electric heat used in the heat delivery wells. Though the electrically imposed heat will produce higher heat saturation rates and temperatures, the resulting oil extraction rate must be balanced against the energy used to produce the electricity used for this purpose. Large amounts of hot fluid will be available for use in the heat delivery wells, so a control algorithm can specify the optimum process parameters to maximize the net energy yield form the formation. It should be noted that this process can be repeated periodically (likely in the monthly timeframe) to reassess the operation optimization, as these parameters will change significantly as the reservoir ages.
(157) The control system can control the system using the following parameters as inputs, where available in the particular system: CO.sub.2 flow rate and temperature in the injection well flowing into the formation, including a flow rate and temperature of the CO.sub.2 exhaust from a boiler and a flow rate and temperature of the CO.sub.2 exhaust optional gas/oil turbine generator; water flow rate in the injection well flowing into the formation composed of water (brine) return flow from the oil/gas/brine separator via the boiler and any additives or additional water used in the injection flow; temperature of the flow rate in the injection well; pressure wave amplitude, mean pressure, and frequency in the injection well; power to the injection well pump/oscillator; pressure wave amplitude, mean pressure, and temperature at the monitoring well at several locations; flow rate and temperature of the production well fluid composed of crude oil, water/brine/additives and gas to the boiler and/or turbine/generator; pressure wave amplitude, mean pressure, and frequency in the production well; power to the production well pump/oscillator; water flow rate to the boiler; temperature of the water flow rate to the boiler; temperature of the water flow rate from the boiler; flow rate of additional gas to the green boiler and/or turbine; separated gas flow rate to the green boiler; separated gas flow rate to the turbine/generator; electricity generated by the turbine/generator; temperature and flow rate to the heat exchanger mixer; temperature and flow rate to the heat delivery well; temperature leaving the heat delivery well; electric power to the heat delivery well; and electric power to the production well casing.
(158) Outputs from the control system controlling the system equipment can include: injection well oscillating pump maximum pressure; injection and production well oscillating pump frequency; production well oscillating pump minimum pressure; water/additive injection flow rate; CO.sub.2 injection flow rate; heated water injection flow rate; heated water flow rate to the heat exchanger/mixer; heated water flow rate to the heat delivery well; electric power to the delivery well heaters; electric power to the production well heaters; position of the pressure access port field in the injection well; position of the pressure access port field in the production well; additional gas fuel input to the boiler and/or turbine/generator; gas flow rate to the boiler; and gas flow rate to the turbine/generator.
(159) The above listed inputs and outputs are not exhaustive. The specific parameters can be adjusted to the particular details of a given resource or system equipment configuration.
(160) A modeling system that simulates a specific oil resource to determine the optimum design of the particular comprehensive EOR system is also provided and can specify a preferred system configuration and process operating parameters to maximize both the extraction rate and overall percentage of oil recovered from that field. As previously described herein, the array of wells that form the Heat/Oil Delivery Matrix can have several different configurations, including perpendicular, parallel, or circular arrangements. The modeling system according to the invention is capable of simulating any of these arrangements within the reservoir.
(161) The modeling system can use information taken from acoustic testing and geologic data of the resource, and other factors to specify the well spacing and pulse frequency range that will be effective in low attenuation transmission, and also to determine the spacing and placement of pulsing pump access ports along the injection and production wells, and the location of the primary injection and extraction zones and well length.
(162) The modeling system can be used help anticipate the timing of the injection and extraction zone adjustments during operation as they may require shutdown of extraction processes while the zone adjustments are being made.
(163) The pressure amplitude of the pulsed pumping wave that is required to loosen oil held in tightly held formations will also be determined prior to specifying the entire EOR system. The modeling system will determine this by the oil and formation parameters (pore size distribution, viscosity, surface tension) and the frequency of the pulsed waves used so as to address the minimum practical pore size in the formation that is retaining oil. The modeling system can be used within the control system to predict the appropriate operating parameter adjustments implemented by the control system.
(164) The modeling system can use information from reservoir testing to determine the optimum design of the comprehensive EOR components. The modeling system will also specify the starting operating parameters of the system and project the estimated change in these values over time as a baseline for the control system. Similar to the control system, the system model will specify the component sizing and placement (and operating parameters) to meet both short term and long term output goals.
(165) The reservoir inputs to achieve the output optimization entered into the modeling system will 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 crude 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.
(166) The outputs to the system equipment configuration will system will 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.
(167) 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.
(168) In summary, the comprehensive enhanced oil recovery system according to the invention incorporates several techniques, including: (1) Synergistic integration of the individual enhanced oil recovery techniques into a comprehensive enhanced oil recovery system; (2) Use of a closed loop power and resource supplier that reduces the environment impact of extracting oil and gas; (3) Using constant heat to volumetrically change the viscosity of the treated reservoir so that the integrated techniques will work; (4) Using the extracted gas (and/or crude oil) in a controlled burning environment creating thermal energy to heat the extracted brine while capturing the exhaust (CO.sub.2 and other gases) to mix with the brine for water/gas flooding and for CO.sub.2 miscibility with the reservoir oil; (5) Using controllable pressure gradients for the extractor ports and the injector ports along the well bore of the production and injection wells; (6) Using an oil/heat delivery matrix to heat the volumetric reservoir, provide flow paths for the oil and gas and directionally mobilize the oil toward the producing wells; (7) Using the controllable pressure gradients with the oil/heat delivery matrix to herd the oil to the producer wells; (8) Oscillate the pressure gradients and position the injection ports and extraction ports one wave length apart (of the oscillating frequency), which creates constructive interference starting one wave length from the injection and production wells, which approximately doubles the amplitude of the pressure waves in the reservoir; (9) Phase controlling the timing of the oscillations in the injection wells and the extractor wells (production wells) so the when the waves meet in the reservoir they again constructively interfere and again double the amplitude of the pressure waves; (10) Using a control system to control all the components of the comprehensive system allowing the system to maximize the flow of oil and gas; (11) In purely fluid flows the pressure amplitude of the pulsed flow is limited by the displacement of the pump and the elasticity of the well/reservoir combination. To address this limitation, an innovative approach has been developed which uses the documented instability of steam collapse under certain conditions to create pressure waves. Normally heated and supersaturated water injected into the reservoir will expand into steam as the pressure drops entering the reservoir and then condense due to gradual thermal loss to the cooler reservoir. By controlling the pressure, temperature, and flow rate of two injected flows, the primary heated water flow and a subcooled water flow can be pulsed so that the steam collapse will become unstable with rapidly fluctuating condensation rates. This will create significant negative pressure spikes in the injected water flow. The flow pulses are all created on the cold water flow so very little energy is required.
(169) The control system may comprise a non-transitory computer readable medium, such as a memory, and a processor configured to execute instructions for adjusting the components of the enhanced oil recovery system in response to feedback received from the monitoring well, pressure sensors and any other input receiving devices in the enhanced oil recovery system in communication with the control system.
(170) TABLE-US-00005 TABLE 5 Legacy Techniques API Required Expected Extraction Thermal Flooding (Steam) 5-40+ 20.0% Water Flooding (Brine) 30+ 16.0% CO.sub.2 Flooding 30+ 20.0% N.sub.2 Flooding 30+ 12.6% Pulsing Waves 30+ 15.0%
(171) In Table 5, when using legacy enhanced oil recovery processes individually, expected extraction percentages are shown for different APIs Required (excluding heavy crude oil in all but the top row). As may be seen in Table 6, when a comprehensive approach is taken, even assuming a conservative expected extraction of 50% for each process and including heavy crude oil, the system extracts over two times the result of any one legacy system taken alone.
(172) TABLE-US-00006 TABLE 6 API Expected Cumulative Comprehensive System Required Extraction Effect Thermal Flooding (Steam) 5-40+ 10.0% 10.0% Water Flooding (Brine) 5-40+ 8.0% 18.8% CO.sub.2 Flooding 5-40+ 10.0% 30.7% N.sub.2 Flooding 5-40+ 6.3% 38.9% Pulsing Waves 5-40+ 7.5% 49.3%
(173) 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.