US20170275537A1

US20170275537A1 - Systems and Methods for Oil and gas Recovery

Info

Publication number: US20170275537A1
Application number: US15/078,754
Authority: US
Inventors: Bradley D. Sanford, JR.; Timothy J. Bradley; William H. Winn; David E. Anderson; Pritam Mazumder
Original assignee: Winn-Marion Barber LLC; Winn-Marion Cos
Current assignee: Winn-Marion Barber LLC
Priority date: 2016-03-23
Filing date: 2016-03-23
Publication date: 2017-09-28

Abstract

The present inventions are related to oil and gas recovery, and in particular to enhanced oil and gas separation during oil and gas recovery.

Description

BACKGROUND OF THE INVENTION

The present inventions are related to oil and gas recovery, and in particular to enhanced oil and gas separation during oil and gas recovery.
Entrained gases in liquid hydrocarbons can be problematic. As one example, transporting oil with a high Reid vapor pressure can be dangerous, and in some cases results in the inability to move oil from a production site. In some cases, producers have installed expensive vapor recovery units on their tanks to recover gas separating from oil maintained in storage tanks. Such vapor recovery units draw gas out of the oil storage tanks, compresses the gas, and introduces the gas into the gas distribution system. In other cases, producers have installed tank venting systems that allow gas build up in the tanks to be released and flared. Both approaches cost money and often when ambient temperatures are cold fail to bring the stored oil into a transportable range.
Thus, for at least the aforementioned reasons, there exists a need in the art for more advanced approaches, devices and systems for oil and gas recovery.

BRIEF SUMMARY OF THE INVENTION

The present inventions are related to oil and gas recovery, and in particular to enhanced oil and gas separation during oil and gas recovery.
This summary provides only a general outline of some embodiments according to the present inventions. Many other objects, features, advantages and other embodiments of the present inventions will become more fully apparent from the following detailed description, the appended claims and the accompanying drawings and figures.

BRIEF DESCRIPTION OF THE DRAWINGS

A further understanding of the various embodiments of the present invention may be realized by reference to the figures which are described in remaining portions of the specification. In the figures, similar reference numerals are used throughout several drawings to refer to similar components. In some instances, a sub-label consisting of a lower case letter is associated with a reference numeral to denote one of multiple similar components. When reference is made to a reference numeral without specification to an existing sub-label, it is intended to refer to all such multiple similar components.

FIG. 1 shows an oil production facility including components operating as a vapor processing system capable of processing oil from two different sources in accordance with one or more embodiments of the present inventions;

FIG. 2 shows a vapor processing system capable of processing oil from two different sources in accordance with some embodiments of the present inventions;

FIG. 3 shows another oil production facility including components operating as a vapor processing system capable of processing oil from a separator in accordance with various embodiments of the present inventions;

FIG. 4 shows a vapor processing system capable of processing oil from a separator in accordance with some embodiments of the present inventions;

FIG. 5 shows a flow diagram showing a method in accordance with one or more embodiments of the present inventions for enhanced oil and gas recovery; and

FIG. 6 shows a vapor processing system capable of processing oil from two different sources and including an automated controller in accordance with some embodiments of the present inventions.

DETAILED DESCRIPTION OF THE INVENTION

The present inventions are related to oil and gas recovery, and in particular to enhanced oil and gas separation during oil and gas recovery.
Various embodiments of the present inventions provide oil recovery systems that include, a separator device, a compression pump, and a pressure reduction system. The separator device is operable to receive an input fluid and to separate the input fluid into a gas portion and an emulsion portion. The compression pump is operable to receive a part of the emulsion portion and to increase the pressure from a first pressure to a second pressure to yield a high pressure fluid. The pressure reduction system is operable to reduce the pressure of a prepared input to a third pressure to yield a return product where the prepared input is derived from the high pressure fluid. The pressure reduction system flows the return product back into the separator device, and the prepared input is derived from the high pressure fluid.
In some instances of the aforementioned embodiments, the first pressure is approximately the pressure in the separator device. In various instances of the aforementioned embodiments, both the first pressure and the third pressure are approximately equal to the pressure in the separator device. In one or more instances of the aforementioned embodiments, the second pressure is at least five times greater than the first pressure. In particular instances of the aforementioned embodiments, the first pressure is less than one hundred psi, and the second pressure is greater than five hundred psi.
In various instances of the aforementioned embodiments where the gas portion is a first gas portion and the part of the emulsion portion is a first part of the emulsion portion, the systems further include a treater device operable to receive a second part of the emulsion portion and to separate the emulsion portion into a second gas portion, an oil portion, and a water portion. In such instances, the pump is further operable to receive a part of the oil portion mixed with the first part of the emulsion portion and to increase the pressure from the first pressure to the second pressure to yield the high pressure fluid. In some cases, the systems further include a storage tank and a tank pump. In such cases, the aforementioned oil portion is stored to the storage tank, and the tank pump pumps the part of the oil portion to a tee fitting where the part of the oil portion mixes with the part of the emulsion portion. In some instances of the aforementioned embodiments, the systems further include a heater operable to heat the high pressure fluid to yield the prepared input. In particular cases, the prepared input is heated to between one hundred and one hundred, forty degrees Fahrenheit. In one or more instances of the aforementioned embodiments, the pressure reduction system includes a choke valve.
Other embodiments of the present inventions provide vapor processing systems that include: a compression pump, an inlet valve, a heater, an outlet valve, and a lockable enclosure. The compression pump is operable to increase a pressure of a processing fluid from a first pressure to a second pressure to yield a high pressure fluid. The inlet valve is operable to allow an input fluid to flow to the compression pump when open, wherein the processing fluid is derived from the input fluid. The heater is operable to heat the high pressure fluid to yield a heated and pressurized fluid. The outlet value operable to allow the heated and pressurized fluid to flow when open. The lockable enclosure encloses the compression pump and the heater. The inlet valve and the outlet valve are accessible external to the enclosure. In various instances of the aforementioned embodiments, the second pressure is at least five times greater than the first pressure. In some instances of the aforementioned embodiments, the high pressure fluid is heated to between one hundred and one hundred, forty degrees Fahrenheit. In one or more instances of the aforementioned embodiments, the systems further include a system controller operable to allow operation of the vapor processing system from outside of the enclosure.
In some instances of the aforementioned embodiments, the vapor processing system further includes a choke valve external to the enclosure, where the choke valve is operable to reduce the pressure of the heated and pressurized fluid to a third pressure to yield a return product. The return product is introduced into a separator device. In some cases, the input fluid is at least in part derived from the separator device. In particular cases, the first pressure is approximately equal to the third pressure, and the second pressure is at least five times greater than the third pressure.
Yet other embodiments of the present inventions provide methods for recovering oil and gas. The methods include: flowing an input fluid into a separator device, wherein the input fluid separates into a gas portion and an emulsion portion in the separator device; releasing the gas portion from the separator device; flowing at least a part of the emulsion portion at a first pressure to a compression pump, where the compression pump increases a pressure to a second pressure to yield a high pressure fluid; heating the high pressure fluid to yield a heated and pressurized fluid; decreasing the pressure of the heated and pressurized fluid to a third pressure through a choke valve to yield a return product; and flowing the return product into the separator device.
Turning to FIG. 1, an oil production facility 100 including components operating as a vapor processing system capable of processing oil from two different sources is shown in accordance with one or more embodiments of the present inventions. Oil production facility 100 receives an input fluid from a well head 121 which is processed through a check valve 124. The input fluid may include, but is not limited to, oil, gas, and salt and water mixed. Well head 121 may exhibit a wide variation of pressures and flow rates with pressures typically between two hundred (200) and four thousand (4000) psi. As a general rule, the younger the well, the higher the pressure. Check valve 124 operates to govern the flow rate of the input fluid introduced into production facility 100. In some embodiments, check valve 124 is a two inch check valve.
The flow rate controlled fluid output from check valve 124 flows to a ball valve 130 via a tee fitting 128. When open, ball valve 130 allows the flow rate controlled fluid to flow into a separator 102. In some embodiments, separator 102 is a two phase separator that divides the input fluid into two phases: a gas and an emulsion. The emulsion includes salt water and oil with the oil including liquid oil and trapped gas. The amount of trapped gas may be expressed as Reid vapor pressure. The gas not trapped in the oil is released from an opening in the top of separator 102 and travels to a gas main header 131 where it may either be flared or distributed to end users. Most of the gas introduced into separator 102 immediately separates from the emulsion when the pipe through which the liquid is transferred into separator 102 opens into the relatively vast expanse of separator 102. The pressure in separator 102 is approximately eighty-five (85) psi. The pressure in separator 102 is maintained relatively high so that it exceeds typical gas pipeline pressure causing the gas to move downstream to purchasers.
In contrast to the gas released from separator 102, the emulsion flows out of a float regulated dump valve included in separator 102 down a pipeline 133 into a treater 104 which operates at approximately twenty-five (25) psi. In some embodiments, treater 104 is a three phase treater operable to separate gas, oil and water. As the emulsion is introduced into treater 104, the drop in pressure from eighty-five psi in separator 102 to twenty-five psi in treater 104 causes an additional amount of gas trapped in the oil to separate and float to the top of the vessel of treater 104. As the pressure in treater 104 is below that required to distribute the gas, the gas is flared.
At this juncture, the emulsion remaining in treater 104 is expected to have only a small amount of gas trapped therein. The substantially gas free emulsion travels farther into treater 104 where it is heated causing the emulsion to separate into water and oil components. The oil being the lighter fluid floats on top of the water. The water is drained from treater 104 through a hydrostatic dump valve (not shown) to a water tank 191, and the oil is drained from treater 104 through another hydrostatic dump valve (not shown) via an oil line to one of more oil tanks 106. The oil and water may then be pumped from the respective tanks or hauled away in a truck. The oil in oil tank(s) 106 should have very little remaining trapped gas (i.e., the oil should exhibit a low Reid vapor pressure) and is suitable for transport.
Under some conditions, however, too much gas remains trapped in the oil being stored to tank(s) 106. This results in a loss of gas that can be distributed and sold via gas main header 131, and an inability to transport the oil maintained in tank(s) due to the high Reid vapor pressure. To further reduce the amount of gas trapped in the oil, a ball valve 156 is opened allowing the emulsion in separator 102 to move through a two inch drain line 135 to a high pressure pump 166 via a tee fitting 158. The fluid passing through ball valve 156 exhibits a flow that is dependent upon well conditions. In one embodiment, the flow through ball valve 156 is expected to be between two (2) and eight (8) gallons per minute. High pressure pump 166 receives fluid via a two inch line 159 at a pressure approximately equal to the pressure in separator 102 (i.e. ˜85 psi). High pressure pump 166 increases the pressure of the incoming fluid to approximately one thousand (1000) psi and transfers the pressurized fluid to a heater 178 via a one inch line 171 and a ball valve 176. In some embodiments, high pressure pump 166 is a 7.5 hp positive displacement pump capable of pumping eight (8) gallons per minute. A pump bypass including a one inch ball valve 168 and a one inch back pressure regulator 174 is installed to avoid damage to high pressure pump 166.
Heater 178 heats the pressurized fluid received via ball valve 176 to an increased temperature. In some embodiments, the increased temperature is between one hundred (100) and one hundred, forty (140) degrees Fahrenheit to yield a heated and pressurized fluid. This heated and pressurized fluid flows through a one inch check valve 186 to a one inch choke valve 110. One inch choke valve 110 reduces the pressure of the received heated and pressurized fluid down to a pressure compatible with separator 102 (i.e., ˜85 psi). This reduced pressure fluid flows into separator 102 via a ball valve 118, tee fitting 128, and ball valve 130. The dramatic reduction of pressure from approximately one thousand (1000) psi to the pressure of separator 102 (i.e., ˜85 psi) results in additional gas breaking free and being captured by separator 102 to gas main header 131. The inlet of choke valve 110 is a one inch line 188, and the outlet of choke valve 110 is a much larger line 115 (e.g., a two inch line or a three inch line).
A ball valve 126 when open allows a certain amount of the fluid from choke valve 110 to cycle directly into treater 104 via a line 137. Further, a low pressure pump 142 allows for pumping fluid from tank(s) 106 for re-processing via a check valve 144. A ball valve 146 and a ball valve 154 allow for selection of re-processing through treater 104 or through the vapor processing system including pressure and temperature increase by high pressure pump 166 and heater 178, respectively. Thus, where the oil stored in tank(s) 106 exhibits and excessive Reid vapor pressure, the oil can be processed through the vapor processing system to release and capture additional gas and reduce the gas trapped in the oil within tank(s) 106.
Such an approach results in additional gas being captured and distributed via gas main header 131, and a corresponding reduction in gas trapped in tank(s) 106. A ½ inch pressure relief valve 164 is installed between tee fitting 158 and high pressure pump 166, another ½ inch pressure relief valve 180 is installed between heater 178 and check valve 186, and yet another ½ inch pressure relief valve 112 is installed between choke valve 110 and ball valve 118.
Turning to FIG. 2, a vapor processing system 200 capable of processing oil from two different sources is depicted in accordance with some embodiments of the present inventions. Vapor processing system 200 is installed in a lockable housing 298 which limits access to the equipment which is connected to an oil and gas production facility through limited connections. Vapor processing system 200 includes a first inlet valve 294 and a second inlet valve 299 extending beyond housing 298. In some embodiments, first inlet valve 294 and second inlet valve 299 allow for processing a fluid supply derived from either or both of a first liquid input 295 and a second liquid input 201. The aforementioned liquid inputs may be, but are not limited to, liquid from a drain of a separator and liquid from a storage tank.
Fluids passing through one or both of first inlet valve 294 and a second inlet valve 299 are provided to a high pressure pump 266 via a tee fitting 258. High pressure pump 266 receives fluid via a two inch line 261 at a relatively low pressure and temperature (e.g., less than 100 psi and 120 degrees Fahrenheit). High pressure pump 266 increases the pressure of the incoming fluid to approximately one thousand (1000) psi and transfers the pressurized fluid to a heater 278 via a one inch line 271 and a ball valve 276. In some embodiments, high pressure pump 266 is a 7.5 hp positive displacement pump capable of pumping eight (8) gallons per minute. A pump bypass including a one inch ball valve 268 and a one inch back pressure regulator 274 is installed to avoid damage to high pressure pump 266.
Heater 278 heats the pressurized fluid received via ball valve 276 to an increased temperature. Heater 278 is a natural gas heater supplied from a gas source via a gas inlet valve 296 accessible external to housing 298. In some embodiments, the increased temperature is between one hundred (100) and one hundred, forty (140) degrees Fahrenheit to yield a heated and pressurized fluid. This heated and pressurized fluid flows through a one inch check valve 286 to a one inch outlet valve 292. The pressurized and heated fluid from outlet valve 292 may be transferred to a separator for additional separation. Outlet valve 292 is accessible external to housing 298. A ½ inch pressure relief valve 264 is installed between tee fitting 258 and high pressure pump 266, and another ½ inch pressure relief valve 280 is installed between heater 278 and check valve 286.
Turning to FIG. 3, an oil production facility 300 including components operating as a vapor processing system capable of processing oil components operating as a vapor processing system capable of processing oil from a separator is depicted in accordance with various embodiments of the present inventions. Oil production facility 300 receives an input fluid from a well head 321 which is processed through a check valve 324. The input fluid may include, but is not limited to, oil, gas, and salt and water mixed. Well head 321 may exhibit a wide variation of pressures and flow rates with pressures typically between two hundred (200) and four thousand (4000) psi. As a general rule, the younger the well, the higher the pressure. Check valve 324 operates to govern the flow rate of the input fluid introduced into production facility 300. In some embodiments, check valve 324 is a two inch check valve.
The flow rate controlled fluid output from check valve 324 flows to a ball valve 330 via a tee fitting 328. When open, ball valve 330 allows the flow rate controlled fluid to flow into a separator 302. In some embodiments, separator 302 is a two phase separator that divides the input fluid into two phases: a gas and an emulsion. The emulsion includes salt water and oil with the oil including liquid oil and trapped gas. The amount of trapped gas may be expressed as Reid vapor pressure. The gas not trapped in the oil is released from an opening in the top of separator 302 and travels to a gas main header 331 where it may either be flared or distributed to end users. Most of the gas introduced into separator 302 immediately separates from the emulsion when the pipe through which the liquid is transferred into separator 302 opens into the relatively vast expanse of separator 302. The pressure in separator 302 is approximately eighty-five (85) psi. The pressure in separator 302 is maintained relatively high so that it exceeds typical gas pipeline pressure causing the gas to move downstream to purchasers.
In contrast to the gas released from separator 302, the emulsion flows out of a float regulated dump valve included in separator 302 down a pipeline 333 into a treater 304 which operates at approximately twenty-five (25) psi. In some embodiments, treater 304 is a three phase treater operable to separate gas, oil and water. As the emulsion is introduced into treater 304, the drop in pressure from eighty-five psi in separator 302 to twenty-five psi in treater 304 causes an additional amount of gas trapped in the oil to separate and float to the top of the vessel of treater 304. As the pressure in treater 304 is below that required to distribute the gas, the gas is flared.
At this juncture, the emulsion remaining in treater 304 is expected to have only a small amount of gas trapped therein. The substantially gas free emulsion travels farther into treater 304 where it is heated causing the emulsion to separate into water and oil components. The oil being the lighter fluid floats on top of the water. The water is drained from treater 304 through a hydrostatic dump valve (not shown) to a water tank 391, and the oil is drained from treater 304 through another hydrostatic dump valve (not shown) via an oil line to an oil tank 396. The oil and water may then be pumped from the respective tanks or hauled away in a truck. The oil in oil tank 396 should have very little remaining trapped gas (i.e., the oil should exhibit a low Reid vapor pressure) and is suitable for transport.
Under some conditions, however, too much gas remains trapped in the oil being outlet to oil tank 396. This results in a loss of gas that can be distributed and sold via gas main header 331, and an inability to transport the oil maintained in tank(s) due to the high Reid vapor pressure. To further reduce the amount of gas trapped in the oil, fluid from a drain of separator 302 is moved through a two inch drain line 335 to a high pressure pump 366. The fluid passing through line 335 exhibits a flow that is dependent upon well conditions. In one embodiment, the flow through line 335 is expected to be between two (2) and eight (8) gallons per minute. High pressure pump 366 receives fluid via line 335 at a pressure approximately equal to the pressure in separator 302 (i.e. ˜85 psi). High pressure pump 366 increases the pressure of the incoming fluid to approximately one thousand (1000) psi and transfers the pressurized fluid to a heater 378 via a one inch line 371 and a ball valve 376. In some embodiments, high pressure pump 366 is a 7.5 hp positive displacement pump capable of pumping eight (8) gallons per minute. A pump bypass including a one inch ball valve 368 and a one inch back pressure regulator 374 is installed to avoid damage to high pressure pump 366.
Heater 378 heats the pressurized fluid received via ball valve 376 to an increased temperature. In some embodiments, the increased temperature is between one hundred (100) and one hundred, forty (140) degrees Fahrenheit to yield a heated and pressurized fluid. This heated and pressurized fluid flows through a one inch check valve 386 to a one inch choke valve 310. One inch choke valve 310 reduces the pressure of the received heated and pressurized fluid down to a pressure compatible with separator 302 (i.e., ˜85 psi). This reduced pressure fluid flows into separator 302 via a ball valve 318, tee fitting 328, and ball valve 330. The dramatic reduction of pressure from approximately one thousand (1000) psi to the pressure of separator 302 (i.e., ˜85 psi) results in additional gas breaking free and being captured by separator 302 to gas main header 331. The inlet of choke valve 310 is a one inch line 388, and the outlet of choke valve 310 is a much larger line 315 (e.g., a two inch line or a three inch line). A ball valve 326 when open allows a certain amount of the fluid from choke valve 310 to cycle directly into treater 304 via a line 337.
Such an approach results in additional gas being captured and distributed via gas main header 331, and a corresponding reduction in gas trapped in tank(s) 306. A 3/2 inch pressure relief valve 364 is installed between the drain of separator 302 and high pressure pump 366, another 3/2 inch pressure relief valve 380 is installed between heater 378 and check valve 386, and yet another 3/2 inch pressure relief valve 312 is installed between choke valve 310 and ball valve 318.
Turning to FIG. 4, a vapor processing system 400 capable of processing oil from a single source is shown in accordance with some embodiments of the present inventions. Vapor processing system 400 is installed in a lockable housing 498 which limits access to the equipment which is connected to an oil and gas production facility through limited connections. Vapor processing system 400 includes a fluid inlet valve 494 extending beyond housing 498. In some embodiments, fluid inlet valve 494 allows for processing a fluid supply derived from a liquid input 495. Liquid input 495 may be, but are not limited to, liquid from a drain of a separator or liquid from a storage tank.
Fluid passing fluid inlet valve 494 is provided to a high pressure pump 466. High pressure pump 466 receives fluid via a two inch line 461 at a relatively low pressure and temperature (e.g., less than 100 psi and 120 degrees Fahrenheit). High pressure pump 466 increases the pressure of the incoming fluid to approximately one thousand (1000) psi and transfers the pressurized fluid to a heater 478 via a one inch line 471 and a ball valve 476. In some embodiments, high pressure pump 466 is a 7.5 hp positive displacement pump capable of pumping eight (8) gallons per minute. A pump bypass including a one inch ball valve 468 and a one inch back pressure regulator 474 is installed to avoid damage to high pressure pump 466.
Heater 478 heats the pressurized fluid received via ball valve 476 to an increased temperature. Heater 478 is a natural gas heater supplied from a gas source via a gas inlet valve 496 accessible external to housing 498. In some embodiments, the increased temperature is between one hundred (100) and one hundred, forty (140) degrees Fahrenheit to yield a heated and pressurized fluid. This heated and pressurized fluid flows through a one inch check valve 486 to a one inch outlet valve 492. The pressurized and heated fluid from outlet valve 492 may be transferred to a separator for additional separation. Outlet valve 492 is accessible external to housing 498. A ½ inch pressure relief valve 464 is installed between fluid inlet valve 494 and high pressure pump 466, and another ½ inch pressure relief valve 480 is installed between heater 478 and check valve 486.
Turning to FIG. 5, a flow diagram 500 shows a method in accordance with one or more embodiments of the present inventions for enhanced oil and gas recovery. Following flow diagram 500, it is determined whether conditions are appropriate to perform vapor recovery using a vapor recovery system (block 505). In some cases, the conditions for vapor recovery occur in winter months when ambient air temperature drops. In such a situation, gas trapped in recovered oil is more likely to remain trapped. In other cases, the conditions for vapor recovery occur when a well from which oil and gas are being recovered reaches a predefined age. As a well ages the pressure in the well decreases making the trapping of gas in oil more likely. In yet other cases, the conditions for vapor recovery occur when an increase in Reid vapor pressure in recovered oil increases. In yet further cases, the conditions for vapor recovery are always considered to exist and the vapor recovery system operates at all times. Based upon the disclosure provided herein, one of ordinary skill in the art will recognize a variety of conditions and/or combinations of conditions that are appropriate for vapor recovery. In some cases, the conditions may be automatically sensed using a combination of sensor and/or temperature sensors incorporated into an oil production facility. Where such sensors are incorporated, the vapor recovery system may be operated automatically. In other cases, operation of the vapor recovery system is manual.
It is determined whether vapor recovery is to be performed on fluid exiting a separator (block 510). Where vapor recovery is not to be performed on fluid exiting the separator (block 510), it is determined whether vapor recovery is to be applied to fluid pumped from a storage tank (block 515). Where vapor recovery is not to be performed on fluid exiting the separator (block 510) nor on fluid pumped from the storage tank (block 515), no vapor recovery is performed even though the conditions are appropriate. Alternatively, where vapor recovery is not to be performed on fluid exiting the separator (block 510), but is to be performed on fluid pumped from the storage tank (block 515), a low pressure tank pump is turned on to transfer stored fluid from the tank to a vapor processing system (block 525).
Alternatively, where vapor recovery is to be performed on fluid exiting the separator (block 510), it is determined whether vapor recovery is to be applied to fluid pumped from a storage tank (block 520). Where vapor recovery is to be performed on fluid exiting the separator (block 510) and on fluid pumped from the storage tank (block 520), the low pressure tank pump is turned on to transfer stored fluid from the tank to a vapor processing system (block 525) and a drain on the separator is opened to allow fluid to flow out of the separator and into the vapor processing system (block 535). On the other hand, where vapor recovery is to be performed on fluid exiting the separator (block 510), but not on fluid pumped from the storage tank (block 520), only the drain on the separator is opened to allow fluid to flow out of the separator and into the vapor processing system (block 535).
Where fluid moved to the vapor recovery system from one or both of the storage tank and the separator (blocks 525, 535), the fluid from either or a combination of both the storage tank and the separator is run through a pressurizing pump in the vapor processing system to increase the pressure to yield a pressurized processing fluid (block 540). In some embodiments, the pressurizing pump increases the pressure of the incoming fluid to approximately one thousand (1000) psi. As the pressure of the fluid from the storage tank is approximately twenty-five (25) psi as controlled by the low pressure tank pump and the pressure of the fluid exiting the separator is approximately eighty-five (85) psi, the increase in pressure due to the pressurizing pump is significant. The pressurized processing fluid is then passed through a heater where it is heated to between one hundred (100) and one hundred, forty (140) degrees Fahrenheit to yield a heated and pressurized fluid (block 545).
The heated and pressurized fluid is rapidly de-pressurized to a pressure approximately equal to the pressure in the separator to yield a return product that is reintroduced back into the separator (block 550). The dramatic reduction of pressure from approximately one thousand (1000) psi to the pressure of the separator (i.e., ˜85 psi) results in additional gas breaking free from the fluid and being captured by the separator to a gas main header. Such an approach results in additional gas being captured and distributed via the gas main header, and a corresponding reduction in gas trapped in oil stored in the storage tank.
Turning to FIG. 6, a vapor processing system 600 capable of processing oil from two different sources and including an automated system controller 603 is depicted in accordance with some embodiments of the present inventions. Vapor processing system 600 is installed in a lockable housing 698 which limits access to the equipment which is connected to an oil and gas production facility through limited connections. Vapor processing system 600 includes a first inlet valve 694 and a second inlet valve 699 extending beyond housing 698. In some embodiments, first inlet valve 694 and second inlet valve 699 allow for processing a fluid supply derived from either or both of a first liquid input 695 and a second liquid input 601. The aforementioned liquid inputs may be, but are not limited to, liquid from a drain of a separator and liquid from a storage tank.
Fluids passing through one or both of first inlet valve 694 and a second inlet valve 699 are provided to a high pressure pump 666 via a tee fitting 658. High pressure pump 666 receives fluid via a two inch line 661 at a relatively low pressure and temperature (e.g., less than 100 psi and 120 degrees Fahrenheit). High pressure pump 666 increases the pressure of the incoming fluid to approximately one thousand (1000) psi and transfers the pressurized fluid to a heater 678 via a one inch line 671 and a ball valve 676. In some embodiments, high pressure pump 666 is a 7.5 hp positive displacement pump capable of pumping eight (8) gallons per minute. A pump bypass including a one inch ball valve 668 and a one inch back pressure regulator 674 is installed to avoid damage to high pressure pump 666.
Heater 678 heats the pressurized fluid received via ball valve 676 to an increased temperature. Heater 678 is a natural gas heater supplied from a gas source via a gas inlet valve 696 accessible external to housing 698. In some embodiments, the increased temperature is between one hundred (100) and one hundred, forty (140) degrees Fahrenheit to yield a heated and pressurized fluid. This heated and pressurized fluid flows through a one inch check valve 686 to a one inch outlet valve 692. The pressurized and heated fluid from outlet valve 692 may be transferred to a separator for additional separation. Outlet valve 692 is accessible external to housing 698. A ½ inch pressure relief valve 664 is installed between tee fitting 658 and high pressure pump 666, and another ½ inch pressure relief valve 680 is installed between heater 678 and check valve 686.
Automated system controller 603 may be, but is not limited to a programmable logic controller. Automated system controller 603 receives a temperature input from an ambient temperature sensor 632, and a pressure input from a well head pressure sensor 630. The ambient temperature and well head pressure may be used to automatically turn vapor processing system 600 on and off. For example, where the ambient temperature drops the volume of gas that remains trapped in recovered oil may increase. Thus, when automated system controller 603 determines that the ambient temperature has dropped below a programmed threshold, vapor processing system 600 may be turned on. As another example, as the pressure at the well head decreases, the propensity for gas to remain trapped in recovered oil may increase. Thus, when automated system controller 603 determines that the well head pressure has dropped below a programmed threshold, vapor processing system 600 may be turned on. In other cases, a combination of the ambient temperature and the well head pressure may be used by automated system controller 603 to control operation of vapor processing system 600. As yet another possibility, automated system controller 603 may include three manual buttons: (1) one button to select fluid from inlet valve 694, (2) one button to select fluid from inlet valve 699, and (3) one button to turn vapor processing system 600 on.
When automated system controller 603 determines (either from input sensor data or through manual switch) that vapor processing system is to be turned on and process fluid only from inlet valve 694, automated system controller 603: (1) asserts a control signal 618 causing inlet valve 694 to open, (2) asserts a control signal 616 causing high pressure pump 666 to turn on, (3) asserts a control signal 612 causing valve 696 to open, (4) asserts a control signal 614 causing heater 678 to turn on, and (5) asserts a control signal 610 causing valve 692 to open.
Alternatively, when automated system controller 603 determines (either from input sensor data or through manual switch) that vapor processing system is to be turned on and process fluid only from inlet valve 699, automated system controller 603: (1) asserts a control signal 620 causing inlet valve 699 to open, (2) asserts a control signal 616 causing high pressure pump 666 to turn on, (3) asserts a control signal 612 causing valve 696 to open, (4) asserts a control signal 614 causing heater 678 to turn on, and (5) asserts a control signal 610 causing valve 692 to open.
Alternatively, when automated system controller 603 determines (either from input sensor data or through manual switch) that vapor processing system is to be turned on and process fluid both inlet valve 695 and inlet valve 699, automated system controller 603: (1) asserts a control signal 618 causing inlet valve 695 to open, (2) asserts a control signal 620 causing inlet valve 699 to open, (3) asserts a control signal 616 causing high pressure pump 666 to turn on, (4) asserts a control signal 612 causing valve 696 to open, (5) asserts a control signal 614 causing heater 678 to turn on, and (6) asserts a control signal 610 causing valve 692 to open.
It should be noted that while the various embodiments have been discussed primarily in relation to the reduction in Reid vapor pressure, that the same embodiments may be used to reduce fugitive emissions. More generally, the embodiments may be used to reduce entrained gasses in liquid hydrocarbon steam. Where ambient temperatures are low a product may exhibit a relatively high Reid vapor pressure indicative of gasses trapped in an oil product. In contrast, where ambient temperatures are high, gasses trapped in the oil product may be released during storage and the light hydrocarbons may escape from the storage tank resulting in an environmental problem. The embodiments disclosed herein may be used to effectuate a controlled or forced release of trapped gasses such that the released gasses may be captured or flared, and a corresponding reduction in Reid vapor pressure occurs. Based upon the disclosure provided herein, one of ordinary skill in the art will recognize other valuable uses for the systems and methods disclosed herein.
In conclusion, the present invention provides for novel systems, devices, and methods for recovering oil and gas. While detailed descriptions of one or more embodiments of the invention have been given above, various alternatives, modifications, and equivalents will be apparent to those skilled in the art without varying from the spirit of the invention. Therefore, the above description should not be taken as limiting the scope of the invention, which is defined by the appended claims.

Claims

What is claimed is:

1. A oil recovery system, the system comprising:

a separator device operable to receive an input fluid and to separate the input fluid into a gas portion and an emulsion portion;

a compression pump operable to receive a part of the emulsion portion and to increase the pressure from a first pressure to a second pressure to yield a high pressure fluid;

and a pressure reduction system operable to reduce the pressure of a prepared input to a third pressure to yield a return product, wherein the pressure reduction system flows the return product back into the separator device, and wherein the prepared input is derived from the high pressure fluid.

2. The oil recovery system of claim 1, wherein the first pressure is approximately the pressure in the separator device.

3. The oil recovery system of claim 1, wherein both the first pressure and the third pressure are approximately equal to the pressure in the separator device.

4. The oil recovery system of claim 1, wherein the second pressure is at least five times greater than the first pressure.

5. The oil recovery system of claim 1, wherein the first pressure is less than one hundred psi, and the second pressure is greater than five hundred psi.

6. The oil recovery system of claim 1, wherein the gas portion is a first gas portion, the part of the emulsion portion is a first part of the emulsion portion, and wherein the system further comprises:

a treater device operable to receive a second part of the emulsion portion and to separate the emulsion portion into a second gas portion, an oil portion, and a water portion; and

wherein the pump is further operable to receive a part of the oil portion mixed with the first part of the emulsion portion and to increase the pressure from the first pressure to the second pressure to yield the high pressure fluid.

7. The oil recovery system of claim 6, the system further comprising:

a storage tank;

a tank pump;

wherein the oil portion is stored to the storage tank; and

wherein the tank pump pumps the part of the oil portion to a tee fitting where the part of the oil portion mixes with the part of the emulsion portion.

8. The oil recovery system of claim 1, wherein the system further comprises:

a heater operable to heat the high pressure fluid to yield the prepared input.

9. The oil recovery system of claim 7, wherein the prepared input is heated to between one hundred and one hundred, forty degrees Fahrenheit.

10. The oil recovery system of claim 1, wherein the pressure reduction system includes a choke valve.

11. A vapor processing system, the system comprising:

a compression pump operable to increase a pressure of a processing fluid from a first pressure to a second pressure to yield a high pressure fluid;

an inlet valve operable to allow an input fluid to flow to the compression pump when open, wherein the processing fluid is derived from the input fluid;

a heater operable to heat the high pressure fluid to yield a heated and pressurized fluid;

an outlet value operable to allow the heated and pressurized fluid to flow when open; and

a lockable enclosure enclosing the compression pump and the heater, wherein the inlet valve and the outlet valve are accessible external to the enclosure.

12. The system of claim 11, the system further comprising:

a choke valve external to the enclosure, wherein the choke valve is operable to reduce the pressure of the heated and pressurized fluid to a third pressure to yield a return product, wherein the return product is introduced into a separator device.

13. The system of claim 12, wherein the input fluid is at least in part derived from the separator device.

14. The system of claim 13, wherein the first pressure is approximately equal to the third pressure, and wherein the second pressure is at least five times greater than the third pressure.

15. The system of claim 11, wherein the second pressure is at least five times greater than the first pressure.

16. The system of claim 11, wherein the high pressure fluid is heated to between one hundred and one hundred, forty degrees Fahrenheit.

17. The system of claim 11, the system further comprising:

a system controller operable to allow operation of the vapor processing system from outside of the enclosure.

18. The system of claim 11, wherein the input fluid is a first input fluid, wherein the inlet valve is a first inlet valve, and wherein the system further comprises:

a second inlet valve operable to allow a second input fluid to flow to the compression pump when open, wherein the processing fluid is derived from a combination of the first input fluid and the second input fluid.

19. A method for recovering oil and gas, the method comprising:

flowing an input fluid into a separator device, wherein the input fluid separates into a gas portion and an emulsion portion in the separator device;

releasing the gas portion from the separator device;

flowing at least a part of the emulsion portion at a first pressure to a compression pump, wherein the compression pump increases a pressure to a second pressure to yield a high pressure fluid;

heating the high pressure fluid to yield a heated and pressurized fluid;

decreasing the pressure of the heated and pressurized fluid to a third pressure through a choke valve to yield a return product; and

flowing the return product into the separator device.

20. The method of claim 1, wherein the first pressure and the third pressure are approximately equal to the pressure in the separator device, and wherein the second pressure is at least five times greater than the first pressure.