The present invention relates to devices and processes used in well drilling and well testing. More specifically, the invention relates to a closed loop well fluid heat exchange system, a control assembly and a method for monitoring and controlling a closed loop heat exchange system.

INTRODUCTION

During the life of a hydrocarbon well reservoir, it is desirable to conduct measurements on the producing subsurface reservoir formation and its effluents to assess the well's commercial potential. The tests commonly used to evaluate the reservoir are varied and widely understood in the industry. Different tests may measure different characteristics of the reservoir and its effluents but the intent of all the tests are focused on understanding how to successfully manage a producing well.

In well testing, for example, it is often necessary to exchange heat between different fluids in order to either increase or decrease the temperature of a well fluid in preparation for further processing of that fluid. The heat may be used to reduce the viscosity of the well fluid, break down emulsions for efficient separation of oil and water or to simply prevent hydrate formation. In a particular example, a steam-heat exchanger, such as a shell & tube heat exchanger, may be used to heat the well fluids. Here, the steam for the heat exchanger is provided by a steam boiler and the heat exchanger also accommodates a separate fluid path for the well fluids that flow through the heat exchanger. In the shell & tube heat exchanger, the well fluids usually flow through inner tubes, while the steam flows outside the tubes but within the shell of the heat exchanger. Heat is then transferred from the steam to the well fluids through the inner tube walls. The condensed steam may be routed back to a steam boiler water tank so that it can be re-used as feed water for the steam boiler to produce hot steam for the heat exchanger system. This closed loop arrangement between the heat exchanger and the steam boiler allows retaining at least some of the heat that was not transferred to the well fluids, thus improving the heat generator's energy efficiency.

However, since well fluids can reach pressures of up to 10,000 psi (ca. 690 bar) and the steam provided by the steam boiler is usually under a pressure of around 150 psi (ca. 10 bar), one of the main concerns during well testing are potential "pin holes" that may occur in the walls of the inner tubes within the heat exchanger. Such "pin holes" or any other fissures or cracks may allow hydrocarbons to leak into the shell chamber of the heat exchanger and contaminate the feed water of the steam boiler. In the event the leak is even bigger than a "pin hole", hydrocarbons may not only be released into the steam side of the heat exchanger, but may also result in a pressure increase within the closed loop fluid path containing steam an/or steam condensate. The pressure increase is then transmitted through to the condensate return system and the steam boiler fluid tank, creating an "over-pressure" within the whole system.

In the normal course of operation, such an event may be a rare occurrence, but it is still a realistic possibility that cannot be ignored.

Consequently, when planning a well test and going through the HAZOP (Hazard and Operability) study, it is quite often decided that the risk of potential tube failure in the well test heat exchanger is too high for returning steam condensate to the steam boiler, and the steam condensate exiting the heat exchanger is instead run overboard into the sea or disposed of in any other suitable way. However, a steam boiler, such as Scan Tech Steam boiler provided by Scan Tech Air Supply UK Limited of Oldmeldrum, UK, requires up to 2,800 liters / hour of potable water in order to run at maximum steam production. Thus, in a 48 hour flow period, 134,400 liters of water would be required from the drilling rig / production platform and all of which would be discharged overboard. Furthermore, not returning the high-temperature steam condensate to the steam boiler, much more energy is required to heat up the "fresh" low- temperature feed water past 100°C in order to produce steam so that the overall boiler efficiency drops considerably.

Accordingly, it is an object of the present invention to provide a heat exchange system with improved efficiency by allowing the re-use of heat exchange fluids, such as feed water or steam condensate, whilst minimising or eradicating the risk of contamination.

SUMMARY OF THE INVENTION

Preferred embodiments of the invention seek to overcome one or more of the above disadvantages of the prior art.

According to the first aspect of the present invention, there is provided a well fluid heat exchange system for processing well fluids, comprising:

a heat exchanger adapted to exchange at least part of the heat between a first fluid medium and a second fluid medium, the second fluid medium being fluidly isolated from said first fluid medium;

a heat generator adapted to increase the temperature of said first fluid medium so as to change the phase of said first fluid medium, wherein said heat exchanger and said heat generator form a closed loop fluid path for said first fluid medium, and

a control assembly, located downstream of said heat exchanger and upstream of said heat generator within said closed loop fluid path, and adapted to monitor at least a first physical property of said first fluid medium and selectively divert at least part of said first fluid medium from said closed loop fluid path.

Advantageously, the first fluid medium may be selectively diverted in response to at least one predetermined condition. Preferably, said heat generator may be adapted to change the phase of said first fluid medium from its liquid phase to its gaseous phase.

This provides the advantage that heated fluids, such as hot steam, provided by the heat generator can be safely re-used within a closed loop fluid path arrangement of the heat exchanger (e.g. shell & tube heat exchanger) and the heat generator (e.g. steam boiler) so that the energy efficiency of the heat exchange system is improved. In particular, the risk of feeding potentially contaminated steam and/or steam condensate back to the steam boiler for re- use or the risk of the system reaching a potentially dangerous condition is minimized by continuous monitoring of at least one specific characteristic of the returned fluid. The monitored characteristic (s) is compared to a pre-set threshold, which may be a measure of an unacceptable fluid contamination and/or a potentially dangerous "over-pressure" within the system.

In the event the control assembly detects such potentially dangerous or harmful condition, the fluid exiting the heat exchanger is automatically diverted out of the closed loop fluid path and removed from the heat exchange system. For example, during offshore well testing, the fluid causing the potentially "dangerous" condition, either through contamination or over-pressure, is simply diverted into the sea so that (i) none of the contaminated fluid is returned to the heat generator (i.e. steam boiler), or (ii) fluid is diverted or otherwise removed to decrease the pressure within the system. Therefore, the monitored and automatically controlled heat exchange system provides a safeguard in the event of unforeseeable structural damage or component failure when recycling heat exchange fluid such as steam and steam condensate.

The control assembly may comprise a remotely actuatable diverter valve in direct fluid communication with an output of said heat exchanger and which is adapted to selectively direct, remove, expel or divert said first fluid out of the closed loop fluid path. Advantageously, the diverter valve may be pneumatically operable. Furthermore, the control assembly may further comprise a monitor device located downstream of said diverter valve and adapted to monitor at least said first physical property of said first fluid medium and provide at least one signal in response to at least one predetermined condition. Advantageously, the at least one signal may be any one or all of an actuating signal, a monitoring signal, visual alarm signal and audible alarm signal. Even more advantageously, the control assembly may further comprise an actuator device operatively coupled to said diverter valve and adapted to receive said at least one signal and selectively actuate said diverter valve.

This provides the advantage of using available system components to effectively implement the invention. For example, the diverter valve may be a 3 -way slam shut valve, such as the Norbo 40R (although, other suitable valves may also be used), which is activated by a solenoid valve via an air supply line. This particular mechanism provides a failsafe and fast valve shut and/or diverter mechanism. The monitor device may comprise a turbidity meter and/or a pressure switch and/or a pressure gauge.

The use of a turbidity meter provides the advantage of a relatively simple, but clear and unambiguous mechanism showing fluid contamination (e.g. increased cloudiness), which may be a clear indicator that well fluids have leaked through structurally damaged heat exchanger tubes (i.e. pin holes, fissures). The pressure switch can provide an actuating signal to the actuator device in direct response to a predetermined pressure change within the heat exchange system allowing a fast response to any potentially harmful changes within the system. The pressure gauge can provide valuable information to the operator about the current pressure status of the system so that providing an early indication of a potentially harmful situation.

The heat exchange system may further comprise a condenser device located downstream of said diverter valve and upstream of said monitor device within said closed loop fluid path, and which is adapted to change said first fluid medium from its gaseous phase into its liquid phase. Advantageously, the condenser device may be operable using said first fluid medium directly from said heat generator bypassing said heat exchanger. Even more advantageously, the heat exchange system may further comprise a filter device located downstream of said diverter valve and upstream of said monitor device and adapted to filter said first fluid medium. Furthermore, the first fluid medium may comprise steam and steam condensate.

This provides the advantage of improving the system efficiency even further. In particular, the filter device can remove potentially harmful particles from the recycled fluid, wherein the condenser device ensures that only fully liquefied fluid condensate is returned to the heat generator.

Advantageously, the heat exchanger may be a shell and tube heat exchanger having isolated / separate fluid paths for respective first fluid medium and second fluid medium. These are common and proven heat exchanger systems within the oil and gas industry.

Additionally, the heat generator may comprise an external fluid tank adapted to receive and store said first fluid medium. According to a second aspect of the present invention, there is provided a control assembly for a well fluid heat exchange system, comprising:

a remotely actuatable diverter valve directly coupleable to an output of a well fluid heat exchanger and adapted to selectively direct a fluid medium into at least one of a first fluid path and a second fluid path;

a monitor device located downstream of said diverter valve during use and adapted to monitor at least a first physical property of a fluid medium and provide at least one signal at a predetermined condition, and

an actuator device operatively coupled to said diverter valve and adapted to receive said at least one signal and selectively actuate said diverter valve to direct the said fluid medium into at least one of said first fluid path and said second fluid path.

This provides the advantage that an already installed heat exchange system can be retrofitted with a control assembly to ensure a minimized risk that contaminated re-used fluid is fed back into the heat generator and/or that a potentially harmful over-pressure builds up within the system due to structural damage to, for example, the heat exchanger inner tubes. The well fluid heat exchange system may be in accordance with the first aspect of the invention. Advantageously, the monitor device may comprise a turbidity meter and/or a pressure switch and/or a pressure gauge. Even more advantageously, the at least one signal may be any one or all of an actuating signal, a monitoring signal, visual alarm signal and audible alarm signal.

According to a third aspect of the present invention, there is provided a method for monitoring and controlling the re-use of a fluid medium in a closed loop well fluid heat exchange system, comprising the steps of:

(i) providing said first fluid medium from an outlet of a well fluid heat exchanger through a selectively actuatable diverter valve that is actuated into a first direction so that said first fluid medium flows through a closed loop fluid path of the heat exchange system;

(if) monitoring at least one physical property of said first fluid medium flowing out of a heat exchanger within the closed loop fluid path and comparing said monitored at least one physical property to at least one predetermined condition;

(iii) when the predetermined condition is met, providing a first signal triggering an actuator device to actuate said diverter valve into a second direction so that said first fluid medium is diverted out of the closed loop fluid path of the well fluid heat exchange system.

The at least one physical property may be either one or both of first fluid medium turbidity and first fluid medium pressure. Advantageously, the predetermined condition may be either one or both of a predetermined first fluid turbidity and a predetermined first fluid pressure.

The method may further comprise the step of providing an audible and/or visible alarm when the predetermined condition is met. The method may further comprise the step of providing said monitored at least one physical property to a remote location.

This provides the advantage that an operator is informed of any "incident" and/or is provided with useful system information (i.e. current system pressure or fluid turbidity), allowing the operator to take early action. The method may further comprise the step of condensing said first fluid medium received from the outlet of the heat exchanger before monitoring said at least one physical property. Advantageously, the method may further comprise the step of filtering said first fluid medium before the step of condensing said first fluid medium. BRIEF DESCRIPTION OF THE DRAWINGS

A preferred embodiment of the present invention will now be described, by way of example only and not in any limitative sense, with reference to the accompanying drawing, in which:

Figure 1 shows a schematic of the preferred embodiment of the well fluid heat exchange system in accordance with the various aspects of the present invention.

DETAILED DESCRIPTION OF EMBODIMENTS

An example of the preferred embodiment of the heat exchange system 100 comprises a shell & tube heat exchanger 101 in a closed loop fluid path arrangement with a heat generator having, for example, a steam boiler 102 and a feed water tank 104 that is in fluid communication with the steam boiler 102. The closed loop fluid path comprises a steam feed line 105, a feed return line 106 and a bypass supply line 107. In general, the steam is generated in the steam boiler 102 and fed via steam feed line 105 into the heat exchanger 101, where heat is exchanged between the hot steam and the well fluids. The steam and steam condensate is then returned through an outlet of the heat exchanger 101 via the return line 106 and into the feed water tank 104, which supplies the steam boiler 102.

A detailed system operation is now described by way of example with reference to Figure 1. The following process assumes that all connections, i.e. electrical, steam, condensate and air supply connections, have been made and that the system is at full steam pressure provided by the heat generator 102, 104. (i) Under normal condition

Steam is fed from the steam boiler 102 to the heat exchanger 101 via steam feed line 105 and through a tee piece 108. The tee piece 108 also provides a steam supply through bypass supply line 107, which is a valved (by means of a 1" steam isolation valve 109) 1" steam hose 107, to drive a condenser device 114 (for example, via another 1" steam isolation valve), which is a combined returns pump and steam trap 114 (e.g. a TLV PowerTrap GT10, although other suitable combined steam driven returns pump and steam traps can be used instead) including a no-return valve.

The steam provided to heat exchanger 101 transfers it's latent heat to the well fluids and condenses in the process. The condensed steam then flows out of the heat exchanger 101 and through a diverter valve 110, such as a slam shut diverter valve (e.g. Norbro 40R, Flowserve®, 20 bar rated, although other suitable valves can be used instead), through a filter device 112, such as a selected strainer 112 (e.g. duplex strainer assembly) and into the condenser device 114. If the pressure upstream of the condenser device 114 is greater than the downstream pressure, then the condenser device 114 operates as a steam trap. On the other hand, if the pressure upstream of the condenser device 114 is less than the downstream pressure, then the condenser device 114 operates as a pump. The steam condensate from the condenser device 114 is then fed back into the feed water tank 104 via a steam manifold 124 (e.g. 2" steam condensate return manifold).

During that process, condensate pressure is continuously monitored at a pressure switch 118 (e.g. Danfoss, type RT, although other suitable pressure switches can be used instead). Part of the steam condensate provided by the condenser device 114 is fed by the steam manifold 124 through a turbidity meter 120 (e.g. Flowserve ® GESTRA OR 52-5, OR 52-6, although other suitable meters can be used instead) bypassing a 2" non-return valve of the steam manifold 124. This may create a slight back pressure within the system. The steam condensate sample diverted to the turbidity meter 120 passes through a sight glass in the turbidity meter 120 so that it's turbidity can be measured. The steam condensate sample then returns to the 2" steam manifold 124 and is returned to the feed water tank 104.

The heat exchange system 100 further comprises a pressure gauge 130 located downstream of the 2" steam manifold 124 providing a visual indication of the pressure within the feed return line 106. Under normal working condition, the pressure in the feed return line 106 should not exceed 25 psi (ca. 1.7 bar) and the turbidity reading should not be higher than 5 ppm (parts per million). The pressure switch 118 in the system is fully adjustable and can be calibrated on location using the pressure reading provided by the pressure gauge 130. The pressure switch 118 should be set at about 10 psi (ca. 0.7 bar) higher than the normal steam condensate pressure reading at the pressure gauge 130. The turbidity meter 120 may further be set to provide an alarm at 15 ppm of oil in the steam condensate. The alarm 122 may be a visual and/or audible alarm.

(ii) Under abnormal condition

In the event the pressure within the feed return line 106 exceeds the threshold pressure set on the pressure switch 118, an actuator device 116, such as a solenoid valve (e.g. 240V 3/2 solenoid valve), de-energises venting a control pressure line to the slam shut diverter valve 110 to atmosphere pressure. The slam shut diverter valve 110 then diverts all condensate from the heat exchanger 101 out of the closed loop fluid path via a 2" bypass line 111. For example, the condensate may simply be diverted overboard into the sea. The audible and visual alarm 122 will sound and display. This alarm 122 is preferably mounted on top of the turbidity meter enclosure. In the event there is a detection of turbidity at or higher than 15 ppm, the solenoid valve 116 will lose it's voltage supply (de-energize) and divert the air supply to the slam shut diverter valve 110 to atmosphere pressure, causing the slam shut valve 110 to actuate and divert the condensate coming from the heat exchanger 101 out of the closed loop fluid path (i.e. overboard into the sea) via the 2" bypass line 111. The audible and visual alarm 122 mounted on the turbidity meter enclosure will activate and provide a sound and display.

In case the condensate flow decreases or even stops, the filter device 112 may be used in duplex mode so that the filter device 112 (i.e. strainer assembly) can be bypassed and cleaned without affecting the process. In the event the condenser device 114 runs in its steam trap mode for any period of time, an additional steam trap 126 may be used in (via a ½" steam trap isolation valve) from the 1" bypass supply line 107 and in parallel to the condenser device 114 to knock out any condensed steam on cooling, and send the condensate to the feed water tank 104 via the 2" steam manifold 124.

An air supply 123 from a Well Test ESD system (Emergency Shutdown) or Well Test Separator provides a feed to the slam shut diverter valve 110 via a pressure regulator 128 (e.g. a pressure regulating valve), the turbidity meter 120 and the pressure switch 118. In the event of an emergency shutdown in the well test area, the slam shut valve 110 closes and diverts all condensate out of the closed loop fluid path (i.e. overboard into the sea) by diverting the condensate along 2" bypass line 111, the outer end of which projects overboard. Also, in case a tube rupture or split inside the heat exchanger 101 occurs, the 2" bypass line 111 from the slam shut valve 110 will act as an additional pressure relief overboard, with the heat exchanger pressure support ventilation (PSV). In addition, if required, a 4-20 mA signal may be made available to the operator allowing connection to the process monitoring system. This provides instant information of any potentially dangerous situation, e.g. high turbidity condition. The signal can be fed via a screened line with, for example, plug and socket connections to suit the operator's requirements.

The steam driven condenser device 114 and the filter device 112 (i.e. duplex strainer assembly) may be housed together in an offshore lifting frame. Also, the turbidity meter 120, pressure switch 118, solenoid valve 116 and pressure regulator 128 may be housed in a portable stainless steel enclosure rated at IP 65 c/w, preferably comprising a clear viewing window in the hinged door. The audio & visual alarm 122 may be mounted on top of this enclosure. All electrical, pneumatic and condensate connections may be external, therefore, allowing the door of the enclosure to remain closed during operation. The 2" tee piece 108 may comprise one outlet that may be reduced to 1" diameter allowing it to be fitted in series with the bypass supply line 107. The 2" steam manifold 124 including all connections and hoses may be adapted to be fitted in series with the condensate returns line 106. A 240 volt power supply of the turbidity meter 120 may either be provided from the steam boiler control system via a dedicated switched plug and socket or from the rig power supply.

According to a second aspect of the present invention, an embodiment of a control assembly 200 is provided, comprising a diverter valve 110, a filter device 112, a condenser device 114, a steam manifold 124, a turbidity meter 120, a pressure switch 118, an actuator device 116 (i.e. solenoid valve), an alarm 122 and a pressure gauge 130, may be retrofitted to any existing well fluid heat exchange system to provide the function described in accordance with the first aspect of the present invention. Preferably, the diverter valve 110 is a slam shut diverter valve (Norbo 40 R), the filter device 112 is a duplex strainer assembly, the condenser device 114 is a steam driven returns pump and steam trap (TLV PowerTrap GT10), the pressure switch 118 is a pressure controlled, single-pole changeover switch (Danfoss, type RT), the actuator device 116 is a solenoid valve and the turbidity meter is a Flowserve GESTRA< OR 52-5/6, but any other suitable components may be used to perform the function described in accordance with the first aspect of the present invention.

It will be appreciated by persons skilled in the art that the above embodiments have been described by way of example only and not in any limitative sense, and that various alterations and modifications are possible without departing from the scope of the invention as defined by the appended claims.