METHOD AND APPARATUS FOR THERMAL ASSISTED OIL-WATER SEPARATION AND ENERGY RECOVERY IN OIL PRODUCTION WELLS

Abstract

Systems, methods, and apparatuses for separating oil and water include a tubular member, an insulating material disposed within the tubular member, at least one heating element disposed within an inner axial area of the tubular member and within the insulating material, at least one sensor in electrical communication with the at least one heating element configured to measure a temperature of a downhole fluid, and a control system coupled to the at least one heating element and the at least one sensor. Methods include disposing an apparatus for separating oil and water inside a wellbore, where an uphole side of the apparatus is fluidly connected to a production well at a surface of a well, measuring, using a sensor, a first measured temperature of a downhole fluid, receiving, with a control system, the first measured temperature, and adjusting the first measured temperature to the surface temperature.

Description

BACKGROUND

During natural gas and oil production, oil and water may be separated in oil producing wells by several means. A common technique for oil-water separation is by gravity, where gases, oil, and water may be separated due to their differing densities. For example, a crude oil mixture may be contained in a vessel and allowed to naturally separate via gravity over time. In gravity separation, gases rise to the top of the vessel, oil forms a middle layer, and water sinks to the bottom. While gravity separation of oil and water is a relatively simple separation method, gravity separation may be time consuming.

To assist with gravity separation of oil and water mixtures, physical (i.e., heat and agitation) and chemical (i.e., demulsifiers) mechanisms may be added to the gravity separation process. However, using physical and chemical means in addition to the gravity separation process generally adds cost and complexity to the process, and may even negatively affect the environment, for example, by use of harmful chemicals. Accordingly, there exists a need for improved oil-water separation mechanisms for fluids produced from oil wells.

SUMMARY

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

In one aspect, embodiments disclosed herein relate to an apparatus for separating oil and water including a tubular member having an inner flow passage formed axially therethrough, an insulating material disposed within an inner axial area of the tubular member, at least one heating element disposed within the inner axial area of the tubular member and within the insulating material. The apparatus of one or more embodiments also includes at least one sensor in electrical communication with the at least one heating element configured to measure a temperature of a downhole fluid, and a control system coupled to the at least one heating element and the at least one sensor configured to receive a measured temperature of the downhole fluid from the at least one sensor and configured to adjust the measured temperature to an operating temperature of the at least one heating element.

In another aspect, embodiments disclosed herein relate to a system for separating oil and water, including an apparatus for separating oil and water disposed in a wellbore, the apparatus having a tubular member having an inner flow passage formed axially therethrough, an insulating material disposed within an inner axial area of the tubular member, at least one heating element disposed within the inner axial area of the tubular member and within the insulating material, and at least one sensor in electrical communication with the at least one heating element configured to measure a temperature of a downhole fluid. The system of one or more embodiments may also include a production well located on a surface of the wellbore, where an uphole side of the apparatus is fluidly connected to the production well, a two phase fluid separator, fluidly connected to a downstream side of the production well, a gas line having a gas stream fluidly connected to and exiting the two phase fluid separator, a liquid flow line including a liquid stream fluidly connected to exiting the two phase fluid separator, and a control system, coupled to the at least one heating element and the at least one sensor.

In yet another aspect, embodiments disclosed herein relate to a method for separating oil and water, including disposing an apparatus for separating oil and water inside a wellbore, where an uphole side of the apparatus is fluidly connected to a production well at a surface of a well, the apparatus including a tubular member having an inner flow passage formed axially therethrough, an insulating material disposed within an inner axial area of the tubular member, at least one heating element disposed within the inner axial area of the tubular member and within the insulating material, at least one sensor in electrical communication with the at least one heating element configured to measure a temperature of the downhole fluid. Methods disclosed herein also include measuring, using a sensor of the at least one sensors coupled to a heating element of the at least one heating elements, a first measured temperature of the heating element, receiving, with a control system, the first measured temperature, and adjusting, using the control system, the first measured temperature to the surface temperature.

Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1A shows an apparatus for separating oil and water according to one or more embodiments.

FIG. 1B shows a cutaway view of a tubular member according to one or more embodiments.

FIG. 2 shows a system for separating oil and water according to one or more embodiments.

FIG. 3 shows a flowchart for a method according to one or more embodiments.

FIG. 4 shows a computer system according to one or more embodiments.

In the figures, the same reference numeral may be used to indicate process equipment as well as the material or component contained within the equipment.

DETAILED DESCRIPTION

Throughout the application, ordinal numbers (for example, first, second, third) may be used as an adjective for an element (that is, any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.

It is to be understood that the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to “a fluid sample” includes reference to one or more of such samples.

Terms such as “approximately,” “substantially,” etc., mean that the recited characteristic, parameter, or value need not be achieved exactly, but that deviations or variations, including for example, tolerances, measurement error, measurement accuracy limitations and other factors known to those of skill in the art, may occur in amounts that do not preclude the effect the characteristic was intended to provide.

It is to be understood that one or more of the steps shown in the flowcharts may be omitted, repeated, and/or performed in a different order than the order shown. Accordingly, the scope of the invention should not be considered limited to the specific arrangement of steps shown in the flowcharts.

Although multiply dependent claims are not introduced, it would be apparent to one of ordinary skill that the subject matter of the dependent claims of one or more embodiments may be combined with other dependent claims.

Embodiments disclosed herein generally relate to systems and methods for separating oil and water in oil-producing wells. In contrast to traditional oil-water separation techniques, embodiments disclosed herein may efficiently separate oil from water in oil-producing wells by using an approach that involves heating the well casing to a critical temperature of 100° C. By heating the casing, water is vaporized as it flows from the reservoir to the surface, facilitating a two-phase separation at the production well that isolates hydrocarbon gases and steam from crude oil, resulting in purified crude oil ready for further processing.

Apparatus

Embodiments disclosed herein relate to an apparatus for separating oil and water in an oil well. An example apparatus 100 according to one or more embodiments is shown in FIG. 1A. The apparatus 100 for separating oil and water includes a tubular member 108, an insulating material 106, at least one sensor 114, at least one heating element 112, and a control system 118.

In the apparatus 100 of one or more embodiments, as best shown in the cut-away view in FIG. 1B, the tubular member 108 is a tubular body defined by an outer surface 108a and an inner surface 108b. The inner surface 108b and outer surface 108a are not defined to a specific location and are only used to represent relative locations on the tubing 108 surface. The insulating material 106 may be disposed within an inner axial area of the tubular member 108. At least one heating element 112 may be disposed within the insulating material 106 contained within the tubular member 108.

The tubular member of one or more embodiments may be any suitable tubing. In the art, tubing may refer to different types of pipes, such as tubing, drill pipe, casing, coiled tubing, etc., used as conduits for fluids in an oil or gas well. The first tubular member and the second tubular member of one or more embodiments may be fabricated from materials capable of withstanding temperatures of at least 100° C., as well as the corrosive nature of the fluids within the well. Suitable materials (e.g., for the outer surface 108a and inner surface 108b of the tubular member 108) include, for example, stainless steel or other corrosion-resistant alloys.

The insulation material of one or more embodiments may be any high-temperature insulating material configured to retain heat within the tubular members, minimizing energy loss to the surrounding wellbore. In one or more embodiments, the insulating material may include magnesium oxide.

In FIG. 1A, the tubular member 108 includes an inner flow passage 116 formed axially therethrough (e.g., radially within the inner surface 108b). During production of an oil and gas well, a downhole fluid may flow from a downhole direction of a wellbore 102 through the inner flow passage 116 and to a surface location 104.

At least one sensor 114 may be disposed on the at least one heating element 112. For example, a sensor 114 may be disposed on an outer surface of a heating element 112 proximate the surface of the earth such that the sensor 114 measures a surface temperature of a downhole fluid traveling within the inner flow passage 116. The at least one sensor 114 is in electrical communication with the at least one heating element 112 and a control system 118 is coupled to and in electrical communication with the at least one heating element 112 and the at least one sensor 114. Electrical communications are depicted by dashed lines in the Figures. The control system 118 is configured to perform methods according to one or more embodiments disclosed herein, including receiving a measured temperature of the downhole fluid from the at least one sensor 114 and adjusting the measured temperature to an operating temperature of the at least one heating element 112. Methods will be described in more detail in the following sections.

The heating element of one or more embodiments may be any industrial-grade heating element capable of enduring high temperatures and corrosive environments in a downhole environment. The heating element may be configured to heat a downhole fluid. In one or more embodiments, the at least one heating element is configured to heat the downhole fluid from a downhole temperature at a downhole location to a temperature of about 100° C. when the downhole fluid is at a surface location (for example, the surface of the earth 206 shown in FIG. 2). Advantageously, the operating temperature may be adjusted to 100° C. according to methods disclosed herein, in order to vaporize a water component of a downhole fluid.

Examples of a heating element include but are not limited to a heating wire or cable. The heating element may be constructed of any suitable material, including but not limited to nickel-chrome alloys, iron chromium aluminum alloys, and positive thermal coefficient ceramic heating elements.

As would be understood by one of ordinary skill in the art, the downhole temperature as described above may vary based on factors specific to the downhole environment including but not limited to geographical location, depth, pressure, formation type, and the like.

The sensor according to one or more embodiments may be configured to measure at least one property, including but not limited to a temperature. The sensor may be any high precision sensor capable of measuring a temperature and a depth corresponding to a fluid temperature within the inner flow passage of the first tubular member.

Keeping with FIG. 1A, in some embodiments, a cement 110 is disposed in an annulus formed between an outer axial surface 108a of the tubular member 108 and an inner surface of a wellbore 102. As would be understood by one of ordinary skill in the art, an annulus created between a tubular member (i.e., a casing) and a wellbore may be cemented in what is typically known as a “primary cement job.” Upon curing of the cement, a cement sheath is formed and is used to support the casing and provide effective zonal isolation for the life of the well while ensuring gas flow potential (or gas migration) is minimized.

The cement disposed in the annulus may have any suitable composition known in the art. The type and composition of the cement may vary based on many factors, including but not limited to geological formations found within the wellbore, wellbore properties such as depth, temperature, etc., available water sources, and the like.

System

Embodiments disclosed herein also relate to systems for separating oil and water in an oil-producing well. FIG. 2 shows an example system 200 according to one or more embodiments. The system 200 may include an apparatus 100 for oil-water separation according to one or more embodiments, a production well 212, a two-phase fluid separator 216, and a central processing facility 228.

In one or more embodiments, the apparatus 100 for oil-water separation may be disposed in a wellbore 102. The wellbore 102 may be any wellbore drilled beneath the surface of the earth 104. A production well 212 located on the surface of the earth 104 may be fluidly connected to an uphole side of the apparatus 100. The apparatus for oil-water separation may be the apparatus 100 described in FIGS. 1A and 1B, above including all of the elements described therein.

The production well may be any suitable production well known in the art used to retrieve oil or gas from an underground reservoir. The production well may include a tree (also known as a Christmas tree) disposed on top of a wellhead to control the flow of fluids into or out of the wellbore. The Christmas tree may include a configuration of valves to control the fluids being injected into or pumped out of the wellbore. For example, the Christmas tree may have one or more valves including an injection wing valve, a swab valve, a production wing valve, an upper master valve, a lower master valve, and the like. When an operator is ready to conduct well operations the valves are either opened or closed to control the fluids being injected into or pumped out of the wellbore.

Returning to FIG. 2, the system 200 also includes a two-phase fluid separator 216. The two-phase fluid separator 216 may be fluidly connected to a downstream side of the production well 212 via a downhole fluid flow line 210. In one or more embodiments, a downhole fluid 208, such as crude oil, may be produced from the wellbore 102 using the production well 212 to facilitate a flow of the downhole fluid in a fluid flow direction of the inner flow passage 116. Upon exiting the wellbore 102, the downhole fluid 208 may then be transported via the downhole fluid flow line 210 to the two-phase fluid separator 216. The two-phase fluid separator 216 of one or more embodiments is configured to separate the downhole fluid 208 into a gas stream and a liquid stream. The gas stream may then flow through a gas line 218 and the liquid stream may flow through a liquid flow line 226 which are fluidly connected to and exiting the two-phase fluid separator 216.

The downhole fluid 208 transported from the production well 212 to the two-phase fluid separator 216 by the downhole fluid flow line 210 according to one or more embodiments may be any fluids produced by an oil and gas production well. For example, the downhole fluid may include steam, natural gas, oil, dissolved solids, and the like.

The two-phase fluid separator 216 of one or more embodiments may be any two phase fluid separator known in the art configured to separate a fluid into a liquid phase and a gas phase, including separating at least natural gas, oil, water, and combinations thereof. The separator may be horizontal, vertical, or spherical. Although not explicitly shown in the figures, one or more separators may be used in combination without departing from embodiments disclosed herein. The two-phase fluid separator of one or more embodiments may be constructed from corrosion-resistant materials such as stainless steel or other suitable alloys. In one or more embodiments, the two-phase fluid separator 216 may include internal components, including but not limited to baffles, mist extractors, and other necessary internal components for effective separation of the phases. Additionally, a test separator vessel may be connected to a choke valve on the wellhead of the production well 212. In general, a test separator vessel separates produced fluids based on their density. For example, solids, such as sand, settle to the bottom of the separator. Denser liquids such as oil and water are drawn from a valve at the bottom of the separator and less dense fluids, such as gas, migrate to the top of the separator vessel where they may be withdrawn. The withdrawn gas may be flared or captured for further use.

In one or more embodiments, the downhole fluid 208 recovered from the production well 212 using methods disclosed herein may include primarily natural gas and steam as the vapor components, and oil in liquid form. Methods will be discussed in more detail in the following sections, however, methods disclosed herein advantageously heat the downhole fluid 208 to a temperature of about 100° C. such that a water component from the downhole fluid 208 boils and may therefore be more easily separated from an oil component in the two phase separator. Accordingly, upon separation of the downhole fluid 208 by the two-phase fluid separator 216, the gas stream flowing through the gas line 218 may include primarily natural gas and steam and the liquid stream flowing through the liquid flow line 226 may include primarily oil.

As defined herein, a fluid stream containing “primarily” certain amounts of one or more components refers to about 80% or more. For example, the gas stream may contain 80% of natural gas and steam, 90% of natural gas and steam, 95% of natural gas and steam, 99% of natural gas and steam, or 99.99% of natural gas and steam. The liquid stream may contain 80% oil, 90% oil, 95% oil, 99% oil, or 99.99% oil.

Keeping with FIG. 2, the liquid stream may then flow through the liquid flow line 226 to a central processing facility 228 fluidly connected to a downstream side of the two-phase fluid separator 216 via the liquid flow line 226. The central processing facility 228 according to one or more embodiments may be any facility capable of further refining the liquid stream. For example, the central processing facility 228 may further separate and/or refine components of the liquid stream and prepare them for export or sale. The central processing facility 228 may include, for example, processing tanks suitable for handling crude oil with minimal water content and other refining equipment as necessary per the requirements of the crude oil specification and processing needs.

In one or more embodiments, the system 200 also includes at least one power source, electrically connected to and configured to provide power to the apparatus 100. The power source may include one or more selected units from the group consisting of an auxiliary generator 204, a backup battery 202, a natural gas generator 220, and combinations thereof. The auxiliary generator 204 may be any generator configured to provide power for initial startup of the system and/or capable of facilitating methods disclosed herein, including but not limited to providing the necessary power to initiate the heating process in one or more heating elements provided in the apparatus 100. Similarly, the backup battery 202 may be any battery system configured to provide power to any necessary components of the system 200. The backup battery 202 may be an industrial-grade rechargeable battery with adequate capacity to power the well site instrumentation and may be used alone as a power source or in combination with other power sources disclosed.

In some embodiments, the power source may include a natural gas generator 220 fluidly connected to the two-phase fluid separator 216 via the gas line 218. As shown in FIG. 2, the natural gas generator 220 may be fluidly connected to a downstream side of the 2-phase separator by the gas line 218 and an exhaust gas line 224 may exit the natural gas generator 220. The exhaust gas line 224 may transport any gases entering the natural gas generator 220 which are not consumed to produce power in the natural gas generation process. The natural gas generator 220 may include an engine suitable for running on a mixed fuel of hydrocarbon gases and steam, for example, gas stream 218. The natural gas generator 220 may be any suitable system configured to convert mechanical energy to electrical energy. Electricity generated by the natural gas generator 220 may be used, for example, to power the apparatuses 100 according to one or more embodiments disclosed herein or other onsite operations or may be transported and sold. The natural gas generator 220 may also include a cooling system. The cooling system may be any efficient cooling system configured to manage the heat generated during the operation of the generator. A battery charging system may also be integrated with the natural gas generator 220 for charging one or more batteries during operations, for example, backup battery 202. In some embodiments, the auxiliary generator 204 may provide power to initiate or startup the process, with a subsequent switch to power from the natural gas generator 220 once the system is operational. The natural gas generator 220 may also include other components necessary to operate the generator, even though they may not be explicitly shown in the Figures, as would be understood by one of ordinary skill in the art.

The system 200 also includes a control system 118. The control system 118 of one or more embodiments may be coupled to the at least one heating element 112 and the at least one sensor 114 disposed within the apparatus 100 for separating oil and water. As described with respect to FIG. 1A above, the control system 118 is in electrical communication with each of the at least one heating elements 112 and the at least one sensors 114, where dashed lines represent electrical communications. The control system 118 may also be configured to perform methods according to one or more embodiments disclosed herein, including receiving a measured temperature from a sensor of the at least one sensors and adjusting the measured temperature to an operating temperature of a heating element of the at least one heating element 112, where the sensor is coupled to the heating element. Methods will be described in more detail in the following sections.

In one or more embodiments, the control system 118 may include a temperature regulation system, including a microprocessor-based control system for real-time monitoring and control of the heating system. The temperature regulation system may help ensure a consistent temperature of the one or more heating elements within the apparatus 100 described in FIG. 1A, above. The control system may be a computer, such as the computer described in FIG. 4, below. As would be understood by one of ordinary skill in the art, the control system may include or be coupled to other elements not explicitly shown in the Figures, which may be necessary to conduct methods according to one or more embodiments disclosed herein. For example, the control system 118 may be coupled to and configured to control one or more actuators and/or valves used to control the one or more heating elements based on a temperature feedback and data acquisition from the one or more sensors.

As would be understood by one of ordinary skill in the art, systems described herein may also include other components not explicitly shown in the Figures. For example, systems disclosed herein may include various instruments for monitoring and controlling the system such as pressure gauges, flow meters, level sensors, and other necessary instrumentation, all rated for use in hazardous and high-temperature environments. Systems may also include necessary corrosion-resistant piping and valves for directing the flow of fluids and gases through the system.

Systems described herein may also include other components not explicitly shown, including but not limited to structural supports for supporting the various equipment and piping, electrical and control wiring suitable for high-temperature and hazardous environment operations, and safety systems including emergency shutdown systems, fire suppression systems, and other necessary safety equipment.

For the purposes of the present disclosure, accompanying components that are conventionally used in oilfield operations, such as pumps and compressors, gas handling apparatuses, valves, sensors, electronic controllers, heat exchangers, and mixers, are not shown or discussed for the sake of simplicity, although in an actual operating system these and many more apparatuses and systems may be included. One of ordinary skill in the art appreciates that such components may be included in the embodiments disclosed.

Method

One or more embodiments disclosed herein also relate to methods for separating oil and water. FIG. 3 presents a flowchart of an example method 300 according to one or more embodiments. As shown in FIG. 3, the method 300 includes, in step 302, disposing an apparatus for separating oil and water inside a wellbore. As described above, an uphole side of the apparatus may be fluidly connected to a wellhead at a surface of a well. The apparatus may include a tubular member, an insulating material disposed within an inner axial area of the tubular member, at least one heating element and at least one sensor disposed on the at least one heating element, where the at least one sensor is in electrical communication with the at least one heating element, as described in FIGS. 1A and 2, above.

In one or more embodiments, the method 300 also includes, in step 304, measuring, using a sensor (e.g., 114 in FIG. 1A) of the at least one sensors coupled to a heating element ((e.g., 112 in FIG. 1B) of the at least one heating elements, a first measured temperature. In one or more embodiments, the surface temperature may advantageously be 100° C. such that water from the downhole fluid may vaporize upon reaching the surface temperature.

The method 300 of one or more embodiments also includes, in step 306 receiving, with a control system, the first measured temperature. The method 300 of one or more embodiments also includes, in step 308 adjusting, using the control system, the first measured temperature to the surface temperature.

The method 300 according to one or more embodiments may include repeating steps 304, 306, and 308 for each of the heating elements and associated sensors provided within the apparatus. For example, in step 304, a temperature associated with each heating element (or, for the heating plate system, for a location in the temperature gradient of the heating plate) may be measured using each sensor (e.g., a first sensor may measure a first temperature, a second sensor may measure a second temperature, a third sensor may measure a third sensor, and so on). Then, in step 306, the control system may receive each of the first temperature, the second temperature, the third temperature, and so on and in step 308 the control system may send instructions to adjust the first temperature, the second temperature, the third temperature, and so on to the surface temperature, a second determined temperature, a third determined temperature, and so on.

In some embodiments, the method 300 further includes separating a gas stream and a liquid stream using a two phase fluid separator (e.g., 216 in FIG. 2) fluidly connected to a downstream side of a production well (e.g., 212 in FIG. 2), the production well located on the surface of the wellbore (e.g., 206 in FIG. 2), where an uphole side of the apparatus (e.g., 100 in FIG. 1A) is fluidly connected to the production well.

In some embodiments, the method 300 further includes powering the apparatus (e.g., 100 in FIG. 1A) with a natural gas generator (e.g., 220 in FIG. 2), electrically connected to the apparatus, where the natural gas generator is fluidly connected to a downstream side of the two phase fluid separator (e.g., 216 in FIG. 2) via a gas line (e.g., 218 in FIG. 2) and the gas stream flows through the gas line (e.g., 218 in FIG. 2).

In some embodiments, the method 300 further includes transporting the liquid stream from the two phase fluid separator (e.g., 212 in FIG. 2) to a central processing facility (e.g., 228 in FIG. 2) fluidly connected to a downstream side of the two-phase fluid separator via a liquid flow line (e.g., 226 in FIG. 2) where the liquid stream comprises primarily oil.

FIG. 4 shows a computer 400 system that may be used in the control process for adjusting a temperature to minimize fuel consumption in an incinerator system in accordance with one or more embodiments. Specifically, FIG. 4 shows a block diagram of a computer 400 system used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures as described in the instant disclosure, according to an implementation. The illustrated computer 400 is intended to encompass any computing device such as a server, desktop computer, laptop/notebook computer, wireless data port, smart phone, personal data assistant (PDA), tablet computing device, one or more processors within these devices, or any other suitable processing device, including both physical or virtual instances (or both) of the computing device.

Additionally, the computer 400 may include a computer that includes an input device, such as a keypad, keyboard, touch screen, or other device that can accept user information, and an output device that conveys information associated with the operation of the computer 400, including digital data, visual, or audio information (or a combination of information), or a GUI.

The computer 400 can serve in a role as a client, network component, a server, a database or other persistency, or any other component (or a combination of roles) of a computer system for performing the subject matter described in the instant disclosure. The illustrated computer 400 is communicably coupled with a network 402. In some implementations, one or more components of the computer 400 may be configured to operate within environments, including cloud-computing-based, local, global, or other environments (or a combination of environments).

At a high level, the computer 400 is an electronic computing device operable to receive, transmit, process, store, or manage data and information associated with the described subject matter. According to some implementations, the computer 400 may also include or be communicably coupled with an application server, e-mail server, web server, caching server, streaming data server, business intelligence (BI) server, or other server (or a combination of servers).

The computer 400 can receive requests over network 402 from a client application (for example, executing on another computer 400) and responding to the received requests by processing the said requests in an appropriate software application. In addition, requests may also be sent to the computer 400 from internal users (for example, from a command console or by other appropriate access method), external or third-parties, other automated applications, as well as any other appropriate entities, individuals, systems, or computers.

Each of the components of the computer 400 can communicate using a system bus 404. In some implementations, any or all of the components of the computer 400, both hardware or software (or a combination of hardware and software), may interface with each other or the interface 406 (or a combination of both) over the system bus 404 using an application programming interface (API) 408 or a service layer 410 (or a combination of the API 408 and service layer 410. The API 408 may include specifications for routines, data structures, and object classes. The API 408 may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of APIs. The service layer 410 provides software services to the computer 400 or other components (whether or not illustrated) that are communicably coupled to the computer 400.

The functionality of the computer 400 may be accessible for all service consumers using this service layer 410. Software services, such as those provided by the service layer 410, provide reusable, defined business functionalities through a defined interface. For example, the interface may be software written in JAVA, C++, or other suitable language providing data in extensible markup language (XML) format or other suitable format. While illustrated as an integrated component of the computer 400, alternative implementations may illustrate the API 408 or the service layer 410 as stand-alone components in relation to other components of the computer 400 or other components (whether or not illustrated) that are communicably coupled to the computer 400. Moreover, any or all parts of the API 408 or the service layer 410 may be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.

The computer 400 includes an interface 406. Although illustrated as a single interface 406 in FIG. 4, two or more interfaces 406 may be used according to particular needs, desires, or particular implementations of the computer 400. The interface 406 is used by the computer 400 for communicating with other systems in a distributed environment that are connected to the network 402. Generally, the interface 406 includes logic encoded in software or hardware (or a combination of software and hardware) and operable to communicate with the network 402. More specifically, the interface 406 may include software supporting one or more communication protocols associated with communications such that the network 402 or interface's hardware is operable to communicate physical signals within and outside of the illustrated computer 400.

The computer 400 includes at least one computer processor 412. Although illustrated as a single computer processor 412 in FIG. 4, two or more processors may be used according to particular needs, desires, or particular implementations of the computer 400. Generally, the computer processor 412 executes instructions and manipulates data to perform the operations of the computer 400 and any algorithms, methods, functions, processes, flows, and procedures as described in the instant disclosure.

The computer 400 also includes a non-transitory computer 400 readable medium, or a memory 414, that holds data for the computer 400 or other components (or a combination of both) that can be connected to the network 402. For example, memory 414 can be a database storing data consistent with this disclosure. Although illustrated as a single memory 414 in FIG. 4, two or more memories may be used according to particular needs, desires, or particular implementations of the computer 400 and the described functionality. While memory 414 is illustrated as an integral component of the computer 400, in alternative implementations, memory 414 can be external to the computer 400.

The application 416 is an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer 400, particularly with respect to functionality described in this disclosure. For example, application 416 can serve as one or more components, modules, applications, etc. Further, although illustrated as a single application 416, the application 416 may be implemented as multiple applications 416 on the computer 400. In addition, although illustrated as integral to the computer 400, in alternative implementations, the application 416 can be external to the computer 400.

There may be any number of computers 400 associated with, or external to, a computer system containing computer 400, each computer 400 communicating over network 402. Further, the term “client,” “user,” and other appropriate terminology may be used interchangeably as appropriate without departing from the scope of this disclosure. Moreover, this disclosure contemplates that many users may use one computer 400, or that one user may use multiple computers 400.

Embodiments disclosed herein may include one or more of the following advantages. The heat-based separation process of one or more embodiments also harnesses generated natural gas to produce electricity, which may be used/recycled to power the components of the system, with an auxiliary generator for startup and a battery backup for enhanced reliability. Furthermore, the systems disclosed herein may incorporate a temperature regulation mechanism to ensure the casing/tubing remains at the optimal temperature, contributing to self-sustainability and environmental friendliness of the process.

Additionally, for enhanced operational reliability, a backup battery may be provisioned for well site instrumentation and may be recharged by the electricity generated from the natural gas generators during inactive periods or post startup, thereby ensuring a self-sustaining, efficient, and environmentally friendlier oil extraction process.

The advantages of embodiments disclosed herein include but are not limited to improved oil-water separation, energy recovery, reduced water handling challenges, enhanced environmental sustainability, increased operational efficiency, reduced dependency on external power sources, increased oil recovery and potential cost savings.

In one or more embodiments, by converting the oil's temperature from 60° C. in the reservoir to 100° C. at the well head through conduction and convection over 5000 feet well length, the invention optimizes energy recovery, reduces water handling challenges, and improves overall operational efficiency. Embodiments disclosed herein may advantageously provide a significant improvement over existing solutions, offering increased oil recovery, potential cost savings, and enhanced environmental sustainability.

EXAMPLES

Example 1

Example 1 provides a detailed description of the heat transfer mechanisms in an example well. The example well has the following initial conditions:

• • Initial Temperature of Oil, T_i=60° C.
  • Final Temperature at Well Head, T_f=100° C.
  • Length of Well, L=5000 ft

Assumptions include assuming a uniform casing diameter and constant flow rate.

The process of heating the oil from 60° C. in the reservoir to 100° C. at the well head involves a combination of heat transfer mechanisms, primarily conduction and convection, as the fluid moves through the 5000 feet long well. The following detailed explanation delves into the thermodynamics involved in this transition.

A first heat transfer mechanism occurring in the well is conduction. Heat conduction through the well casing can be described using Fourier's Law of heat conduction:

$\begin{array}{cc}q=-\mathrm{kA}\frac{\mathrm{Dx}}{\mathrm{DT}}& \left(\mathrm{Equation}1\right)\end{array}$

• • where, q is the heat rate (W), k is the thermal conductivity of the casing material (W/m·K), A is the cross-sectional area of the casing (m²), and Dx/DT is the temperature gradient along the well (K/m).

A second heat transfer mechanism occurring in the well is convection. As the oil moves along the well, it gains heat from the casing through convective heat transfer. The heat transfer due to convection can be expressed using Newton's Law of Cooling:

$\begin{array}{cc}q=\mathrm{hA}\left(T_s-T_f\right)& \left(\mathrm{Equation}2\right)\end{array}$

• • where, h is the convective heat transfer coefficient (W/m²·K), A is the surface area for heat transfer (m²), T_s is the temperature of the casing surface (° C.), and T_f is the temperature of the fluid (° C.).

Furthermore, a transit time of liquid molecules from the reservoir to the well head can be calculated using the formula:

$\begin{array}{cc}\mathrm{Time}=\frac{L}{v}& \left(\mathrm{Equation}3\right)\end{array}$

• • where, v is the velocity of the fluid (m/s).

Finally, a temperature rise of the oil can be integrated over the length of the well, considering the heat gained from the casing, and any potential heat losses due to radiation or convection to the surrounding earth.

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.

Claims

1. An apparatus for separating oil and water comprising:

a tubular member having an inner flow passage formed axially therethrough, wherein the tubular member is disposed in at least a portion of a wellbore;

an insulating material comprising magnesium oxide and disposed within an inner axial area of the tubular member;

at least-one heating element disposed within the inner axial area of the tubular member and within the insulating material; at least two sensors, wherein: a first sensor of the at least two sensors is disposed proximate the surface of the earth and configured to measure a surface temperature of a downhole fluid and the first sensor is in electrical communication with the at least one heating element, and a second sensor of the at least two sensors is disposed at a lower end of the wellbore and configured to measure a temperature of the downhole fluid at a total well length; and

a control system coupled to the at least one heating element and the at least two sensors configured to: receive a measured surface temperature of the downhole fluid located proximate the surface from the first sensor and a measured downhole temperature of the downhole fluid at the lower end of the wellbore from the second sensor; determine, based on the measured surface temperature, the measured downhole temperature, and the total well length, an operating surface temperature; and adjust the measured surface temperature to the operating surface temperature such that the downhole fluid located proximate the surface is maintained at a temperature of about 100° C.

2. (canceled)

3. The apparatus of claim 1, wherein a cement is disposed in an annulus formed between an outer axial surface of the tubular member and an inner surface of the wellbore.

4. (canceled)

5. The apparatus of claim 1, wherein the tubular member comprises a corrosion resistant alloy.

6. The apparatus of claim 1, wherein the at least one heating element comprises at least one selected from the group consisting of nickel-chrome alloys, iron chromium aluminum alloys, and positive thermal coefficient ceramic heating elements.

7. A system for separating oil and water, comprising:

an apparatus for separating oil and water disposed in a wellbore, the apparatus comprising: a tubular member having an inner flow passage formed axially therethrough, an insulating material disposed within an inner axial area of the tubular member, at least one heating element disposed within the inner axial area of the tubular member and within the insulating material, and at least one sensor in electrical communication with the at least one heating element configured to measure a temperature of a downhole fluid;

a production well located on a surface of the wellbore, wherein an uphole side of the apparatus is fluidly connected to the production well;

a two phase fluid separator, fluidly connected to a downstream side of the production well;

a gas line comprising a gas stream fluidly connected to and exiting the two phase fluid separator;

a liquid flow line comprising a liquid stream fluidly connected to exiting the two phase fluid separator;

a control system, coupled to the at least one heating element and the at least one sensor; and

at least one power source: electrically connected to and configured to provide power to the apparatus, and comprising a natural gas generator fluidly connected to a downstream side of the two phase fluid separator via the gas line, wherein the natural gas generator comprises an exhaust gas line.

8. The system of claim 7, wherein a cement is disposed in an annulus formed between an outer axial surface of the tubular member and an inner surface of the wellbore.

9. The system of claim 7, further comprising a central processing facility fluidly connected to a downstream side of the two phase fluid separator via the liquid flow line.

10-11. (canceled)

12. The system of claim 7, wherein the at least one heating element is configured to heat the downhole fluid from a downhole temperature at a downhole location to a temperature of about 100° C. when the downhole fluid is at a surface location.

13. The system of claim 7, wherein the insulating material comprises magnesium oxide.

14. The system of claim 7, wherein the tubular member comprises a corrosion resistant alloy.

15. The system of claim 7, wherein the at least one heating element comprises at least one selected from the group consisting of nickel-chrome alloys, iron chromium aluminum alloys, and positive thermal coefficient ceramic heating elements.

16. A method for separating oil and water, comprising:

disposing an apparatus for separating oil and water inside a wellbore, wherein an uphole side of the apparatus is fluidly connected to a production well at a surface of a well, the apparatus comprising; a tubular member having an inner flow passage formed axially therethrough, an insulating material disposed within an inner axial area of the tubular member, at least one heating element disposed within the inner axial area of the tubular member and within the insulating material, at least one sensor in electrical communication with the at least one heating element configured to measure a temperature of the downhole fluid; and

measuring, using a sensor of the at least one sensors coupled to a heating element of the at least one heating elements, a first measured temperature of the heating element,

receiving, with a control system, the first measured temperature;

adjusting, using the control system, the first measured temperature to a surface temperature, powering the apparatus with at least one power source electrically connected to the apparatus, and

separating a gas stream and a liquid stream using a two phase fluid separator fluidly connected to a downstream side of the production well,

wherein: the at least one power source comprises a natural gas generator fluidly connected to a downstream side of the two phase fluid separator via a gas line, and the natural gas generator comprises an exhaust gas line.

17-19. (canceled)

20. The method of claim 16, further comprising transporting the liquid stream from the two phase fluid separator to a central processing facility fluidly connected to a downstream side of the two phase fluid separator via a liquid flow line, wherein the liquid stream comprises primarily oil.

21. The apparatus of claim 1, wherein the at least one heating element is cylindrical in shape.

22. The apparatus of claim 1, wherein the at least one heating element is disposed within a single layer of the insulating material.