AU735485B2 - Method and apparatus for producing and shipping hydrocarbons offshore - Google Patents

Description

-1- METHOD AND APPARATUS FOR PRODUCING AND SHIPPING HYDROCARBONS OFFSHORE BACKGROUND OF THE INVENTION FIELD OF THE INVENTION The present invention relates to a method and apparatus for producing and shipping hydrocarbons, crude oil, from an offshore site. In particular, the present invention relates to a method and apparatus which does not require an offshore processing plant and which allows both gas and oil to be shipped to an onshore processing plant.

0.0 DESCRIPTION OF THE PRIOR ART Any discussion of the prior art throughout the specification should in no way be .o considered as an admission that such prior art is widely known or forms part of common So." general knowledge in the field.

o i 15 Crude oil and natural gas from offshore wells is produced in the following manner according to the teachings of the presently-known prior art technology. First, the crude oil and gas wells are drilled and completed using drilling equipment that is mounted on either a jack-up drilling rig or on a floating vessel.

After the wells have been drilled and completed they are typically connected to an offshore processing plant WO 98/31919 PCT/US98/00127 that separates the live crude oil from the well which is typically a mixture of oil, gas, water, salt and other solids into a stabilized crude oil with a low vapor pressure that is therefore suitable for transportation in ordinary tanker vessels and a natural gas component that is suitable for transportation onshore by a pipeline. Ordinarily, the stabilized crude oil is processed at the offshore processing plant sufficiently so that it may be used in a standard onshore refining process without further treatment to remove solids, salt, and water from the crude oil. Therefore, the offshore processing facility also removes water, salt and other solids from the live crude oil before it is transferred to the vessel as stabilized crude oil.

The stabilized crude oil may then be transported ashore by pipeline or by tanker vessels, which tanker vessels normally store the stabilized crude oil at or near atmospheric pressure. The produced gas is ordinarily transported ashore in pipelines. In addition to transporting the produced gas ashore by pipeline, a number of emerging technologies exist to transport the gas in ships, by subjecting the gas to chemical processes that convert it, for example, into methanol or by liquefying the gas and transporting it as a cooled liquid. The technologies for transporting the gas in ships all require large capital expenditures and cause the loss of a significant fraction of the energy content in the gas during processing and transportation.

If tanker transportation of the stabilized crude oil is used from the offshore oil field processing plant, significant hydrocarbon losses usually occur due to degassing of the crude oil in the cargo tanks. The economics and safety of ordinary tanker transportation do not permit the re-capture and retention of this gas, leading to the waste of this energy source.

WO 98/31919 PCT/US98/00127 In the event that no pipeline is available to transport the gas ashore, because of, distance, many jurisdictions today require that the gas be re-injected into the hydrocarbon-bearing soil formation to preserve the gas for future production when the economics of exploitation permits the production and transportation of the gas. At locations where re-injection requirements do not exist, the gas may be burned in a flare. Either of these processes, re-injection or flaring, are expensive and waste energy that could otherwise be produced or used.

The offshore processing plant of the presently-known prior art technology may be mounted on a platform sitting on the sea bed, on a ship-like vessel, on a semisubmersible, or on a tension leg platform. Other possible means of mounting offshore processing plants also exist.

However, all of these means have in common the fact that the platform for supporting the processing plant is very expensive.

The offshore processing plant of the presently-known prior art technology is expensive compared to a comparable crude oil processing plant on land, because the offshore processing plant must be specially adapted for the offshore environment, for operation in a restricted space, to compensate for possible movement and accelerations. of the plant during operations, and for limited possibilities for maintenance. Furthermore, the crew operating the offshore plant is regularly ferried back and forth between the platform and land, and all their needs, with the possible exception of fuel, must also be ferried to the plant from shore.

Thus, the capital costs and the operating costs for an offshore processing plant of the presently-known technology is much higher than for a corresponding plant on land.

WO 98/31919 PCT/US98/00127 Some of the problems of the above-described method are addressed in U.S. Patent No. 4,446,804. In this patent, a method is described-for loading shuttle ships with live crude oil directly from subsea oil wells. This process consists of loading the live crude oil into tanks on the shuttle tanker that are pre-filled with a displacement liquid and pressurized to a pressure near the pressure of the live crude oil to be received. The live crude oil then displaces the displacement liquid under nearly constant pressure during the loading operation. This procedure results in a shuttle tanker having an extraordinary complex cargo handling system with a large number of valves and instruments. Another disadvantage of the system described in U.S. Patent No. 4,446,804 is that the tanker must be designed for a pressure near the bubble point of the crude oil, to take full advantage of the shuttle tanker loading system.

The system described in U.S. Patent No. 4,446,804, however, has the advantage of minimizing the release of gas from the crude oil by maintaining the cargo always near maximum pressure. A severe drawback to the system described in U.S. Patent No. 4,446,804 is that the containment system in the tanker must be designed for the bubble pressure of the received crude oil. This pressure varies from oil field to oil field. Therefore a tanker may be designed to serve a specific oil field, which limits its utility, or may be designed to be used in a number of oil fields. In the latter case the cargo containment system must be designed for a highest pressure in the oil fields, possibly as high as 35 MPa.

Another relevant patent to this field is U.S. Patent No. 5,199,266. This patent describes a method for transporting gas from offshore fields, which gas has been produced on offshore production platforms by pressurizing the gas and cooling it to a temperature in the range of -100°C to -120°C. In this temperature range and at a pressure of approximately 1.5 MPa, all hydrocarbon gases normally occurring in oil wells are liquid. As described in U.S.

Patent No. 5,199,266 the gas must be delivered to the transport vessel in gaseous form and is then cooled and liquefied on the shuttle vessel. A very large and expensive cooling plant is required on the gas transport vessel to cool and condense the gas to be transported. Thus, the system described in U.S. Patent 5,199,266 not only requires an offshore production platform in accordance with the traditional technology but also require a number of high pressure; refrigerated tanker vessels each fitted with a largecapacity cooling plant.

The object of the present invention is to overcome some or all of the drawbacks oooe associated with the present technologies.

SUMMARY OF THE INVENTION *According to a first aspect of the invention there is provided an oil production system for off-shore use comprising: 15 an oil well, the oil well producing produced fluid, the produced fluids including at least one of water, crude oil and gas; oo*.

a riser connected to the oil well; and a floating vessel, the float vessel including at least one high pressure storage tank, the high pressure storage tank being designed to store the produced fluids at a pressure above 200 kPa gauge pressure, the vessel further including at least one flash drum, the at least one flash drum being selectively coupled to the riser, the at least one flash drum being coupled to the at least one storage tank by at least one line.

Unless the context clearly requires otherwise, throughout the description and the claims, the words 'comprise', 'comprising', and the like are to be construed in an inclusive sense as opposed to an exclusive or exhaustive sense; that is to say, in the sense of "including, but not limited to".

Advantageously, at least in preferred forms the present invention may provide special shuttle tankers with high-pressure cargo tanks capable of containing the produced live crude oil crude oil which has not been stabilized by removal of mixed gas, or further processed to remove water, salt or other solids) at a pressure close to that of the ambient pressure inside the subterranean oil field, and without any processing of the live crude oil prior to transportation. The produced live crude oil from the subterranean oil field is pumped into high-pressure cargo tanks aboard the shuttle tanker, either directly or through a flash drum. Reinjection or flaring of produced gas mixed with the crude oil is avoided or greatly reduced, and escape of the lighter fractions of the crude oil to the atmosphere is prevented.

According to a second aspect of the invention there is provided a method for producing crude oil offshore, comprising: producing the crude oil from an oil well; transferring the crude oil into at least one flash drum on a vessel; transferring gas and liquid from the at least one flash drum to at least one storage tank through at least one line; and S"storing the gas and liquid in the at least one storage tank at a pressure above 200kPa gauge pressure.

According to a third aspect of the invention there is provided an oil production system for off-shore use comprising: an oil well, the oil well producing produced fluids; ,a riser connected to the oil well; a floating vessel, the floating vessel including at least one storage tank, the vessel further including at least one flash drum, the at least one flash drum being selectively coupled to the riser, the at least one flash drum being coupled to the at least one storage tank by at least one line; a gas line connected to the at least one storage tank, the gas line drawing off gas from the at least one storage tank; and powered equipment on the vessel, the gas line being connected to the powered equipment, gas from the produced fluids powering the powered equipment.

According to a fourth aspect of the invention there is provided a method for producing crude oil offshore, comprising: producing the crude oil from an oil well; 0, transferring the crude oil into at least one flash drum on a vessel; and transferring gas and liquid from the at least one flash drum to at least one storage o, tank through at least one line; 15 drawing off gas from the at least one storage tank; and using gas drawn off from the at least one storage tank to propel the vessel.

According to another aspect of the invention there is provided a method for producing crude oil offshore, comprising: S°producing the crude oil from an oil well; transferring the crude oil directly into at least one unpressurized storage tank on a vessel without further processing of the crude oil.

In the ordinary application of the invention, the produced oil will separate into two

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phases, a gas phase and an oil phase that has a lower gas-oil ratio (GOR) than the ~x produced crude oil. As the pressure in the receiving tanks WO 98/31919 PCT/US98/00127 rise the gas phase becomes proportionally smaller compared to the oil phase. If the bubble point of the produced oil is sufficiently low, -the gas phase may become zero when the pressure in the tanks have risen sufficiently. Re-injection or flaring of produced gas is avoided or greatly reduced and escape of the lighter fractions of the crude oil to the atmosphere is prevented.

The volumetric ratio between gas and oil may vary between zero and one. Thus a vessel according to the present invention is universal and may produce crude oil from offshore oil fields having all GORs from zero no gas in the produced fluids) to the produced fluids being 100 percent gas.

In the practice of the present invention, it is the intent to use the lighter fractions, such as methane, of the produced live crude oil stored in the shuttle tanker as a fuel to power the propulsion machinery and the auxiliary machinery aboard the shuttle tanker. This action lowers the pressure of the contained live crude oil. The ambient temperature of the live crude oil in the ground is ordinarily significantly higher than the ambient temperature at the sea surface. During the production process the produced live crude oil is cooled, as the result of transfer of the live crude oil from the well, through the riser and into the vessel, with a consequent reduction in vapor pressure of the live crude oil.

The pressures at which the cargo must be contained in order to contain most of the lighter fractions of the produced live crude oil in liquid form vary greatly from oil field to oil field. However, the pressures would ordinarily be above 70 kPa gauge pressure, may be higher than 1.8 MPa gauge, and may range as high as 35 MPa gauge or even higher. Standard shuttle tankers of the prior art can only accept a pressure differential of approximately WO 98/31919 PCT/US98/00127 kPa between the interior of the cargo tanks and the exterior atmosphere, a pressure of 25 kPa gauge.

Therefore, tanks in ordinary tankers of the prior art must be vented to the atmosphere to prevent dangerous differential pressures from building within the cargo tank as gas dissociates from the stabilized crude oil because of the vapor pressure increase as the result of storing the stabilized crude oil at or near atmospheric. This venting in the prior art causes significant energy loss, which loss is eliminated or greatly reduced using the method and apparatus of the present invention.

A particular advantage of the present invention is that the live crude oil is produced into tanks aboard the shuttle tanker that have an internal pressure close to atmospheric at the start of the loading process. This crude oil dissociates into liquid and gas phases in the tanks. As more crude oil enters the cargo tanks the dissociated gas is compressed and raises the pressure in the tanks.

Normally the cargo tank design pressure is reached before the cargo tanks are full. Therefore, a shuttle tanker having a particular design pressure may be applied to wide variety of oil fields with different crude oils, regardless of the bubble pressure. The only difference is the degree to which the tanker can be filled without venting the gas.

When the crude oil having a high GOR is discharged into a vessel with much lower pressure, the flow expands violently and may cause high wear of the piping, fittings, valves, and the receiving tank itself. The produced crude oil often contains sand and other grit increasing the erosion of the system. For this reason the tankers in this invention will usually be fitted with a flash drum that is maintained at the pressure of the receiving cargo tank.

This flash drum is the pressure vessel that receives and reduces the pressure of the crude oil. The flash drum may be located at an easily-accessible location on the tanker WO98/31919 PCT/US98/00127 so that it can be replaced whenever the wear of its components warrant its replacement.

To be able to efficiently handle crude oils with a high GOR the present invention also allows the venting of the gas in the cargo tanks of the shuttle vessel into refrigerated cargo tanks that are cooled by an onboard refrigeration plant. By this method, all hydrocarbons normally occurring in crude oil except methane will condense and become liquid, and the methane itself can be stored at a higher density because of its lower temperature.

The discharging of crude oil and gas at the processing plant is particularly easy in the present invention. The crude oil is drawn from the bottom of the cargo tanks using the high pressure in the tanks to provide energy to pump the oil ashore. If the vessel is fitted with cooled storage tanks natural gas liquids are drawn from the bottom of these tanks, and pumped ashore by the high pressure in these tanks. The natural gas remaining is only partly discharged so that a sufficient quantity remains to be used as fuel for propulsion on the tanker's return trip to the oil field.

Application of the present invention requires that the tanker vessel transport the produced live crude oil to an onshore processing plant for separation into gas, water, solids, and stabilized crude oil. This plant may be situated anywhere that the tanker vessel can go that is advantageously situated relative to customers of the oil and the gas.

The present invention is also applicable to existing or future oil or gas fields that are not situated in the vicinity of a gas pipeline and for which such a pipeline is uneconomical. Such fields are normally equipped with a WO 98/31919 PCT/US98/00127 processing plant that separate the crude oil from the gases. Normally the gases are re-injected into the hydrocarbon bearing- formation. In such cases vessels constructed in accordance with the teaching of this invention may be employed to bring the hydrocarbon gases ashore. The processing plant may deliver so-called fuel gas which contains significant amounts of propane, butane and higher hydrocarbons or may deliver pipeline-ready gas that can be directly injected into gas pipelines ashore without further treatment.

The present invention is similar to the process described by U.S. Patent No. 5,199,266, with the exception that the gas is not cooled to below -100 degrees C, but stored under pressure partly or fully in the form of a gas.

The present invention also applies to oil fields found on land in the vicinity of the ocean or in the vicinity of navigable rivers. The technology may also be used to transport gas on inland waterways. The only alternative technologies for transporting gas along inland waterways are pipeline transportation or transportation in ships or barges carrying the gas as a liquid at a temperature that is typically -162 degrees C (Liquefied Natural Gas, "LNG").

The first of the two prior art technologies discussed above has high fixed costs, whereas the second has both high fixed costs and high energy consumption in the liquefaction process. Transportation of gas in accordance with the teaching of the present invention is particularly advantageous and lower in cost for small volumes of transportation such as between 100 tonnes/day and 2000 tonnes/day and for relatively small distances such as 200 km to 1000 km.

The above and other features and advantages of the oil production method and apparatus are described in detail below in connection with the drawings.

WO 98/31919 PCT/US98/00127 BRIEF DESCRIPTION OF THE DRAWINGS Fig. 1 is diagram representing the existing technology of offshore oil production; Fig. 2 is a diagram describing offshore oil production in accordance with the present invention; Fig. 3 is side view of a vessel adapted for the production of offshore oil in accordance with the present invention; Fig. 4 is a diagram showing the processes aboard a shuttle tanker according to one embodiment of the present invention, adapted for cooling produced gasses; Fig. 5 is a diagram showing the flash drum receiving the crude oil in tankers according to the embodiment of Fig. 4.

DETAILED DESCRIPTION OF THE INVENTION Figure 1 illustrates an example of the production of oil in accordance with the present, prior art, technology.

An underground sub-sea hydrocarbon reservoir 10 may include a gas layer 11, an oil layer 12, and a water layer 13. The reservoir 10 is tapped though a well 14. The well 14 terminates in a wellhead 15 at the sea bed 16. A crudeoil/water/gas mixture (which mixture may also contain salt and other solids), also known as live crude oil, flows from the well head 15 through the pipe 20 to a processing plant 21 elevated above the sea surface 22 by a platform 23. The processing plant 21 separates the live crude oil into a gas that is conveyed to shore by the pipeline 24, produced water that is discharged to the sea through pipe 25, and stabilized crude oil that is transferred through a pipe 26 to a floating storage vessel 27. Stabilized crude oil is -11crude oil which has had, inter alia, volatile gas removed from it by the processing plant 21.

The storage vessel 27 is permanently moored near the platform 23 by anchor lines 28 connected to sea bed anchors (not shown) and stores the stabilized crude oil produced by the processing plant 21 at approximately atmospheric pressure or at a pressure no greater than 25 kPa gauge. The crude oil is transported away from the storage tanker 27 by shuttle tankers 29 that receive the oil through a cargo transfer hose 30. Shuttle tankers 29 also store the stabilized crude oil at approximately atmospheric pressure or at a pressure no greater than 25 kPa gauge.

Figure 2 shows an oil production system in accordance with the teachings of the present invention. A sub-sea hydrocarbon reservoir 10 comprises a gas layer 11, an oil i layer 12, and a water layer 13. The reservoir 10 is tapped by the well 14 terminating in a sub-sea wellhead 15. The wellhead 15 may be located at the sea-bed 16 or above or below the seabed 16 as circumstances may dictate. The wellhead 15 is connected 15 through a pipeline 40 to a riser 41 terminatingin a mooring buoy 42 for the shuttle 6: tanker 50. Mooring buoy 42 may be of the type shown in my U.S. Patent Nos.

5,305,703; 5,339,760; 5,380,229; 5,553,976; 5,447,114; 5,515,803; 5,647,297 and 5,676,083. The live crude oil is conveyed through the mooring buoy 42 by piping (not

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*ooeSS Sshown) in the mooring buoy 42 topiping 51 in the shuttle tanker 50, through a multipath swivel 52, and to cargo piping 53 aboard the tanker 50. The tanker 50 is a special tanker adapted to store the produced crude oil at a pressure at or somewhat below the pressure in the sub-sea oil field r The well head 15 may include instrumentation and controls (not shown) in order to cmonitor the flow from the WO 98/31919 PCT/US98/00127 well and in order to be able to shut in the well. The instrumentation and the controls (not shown) at the well head 15 are connected to the vessel 50 by an umbilical connected to control and instrument cabling 55 aboard the vessel 50. The cabling 55 is connected through the multipath swivel 52 to fixed cabling 54 to control and monitoring systems 56 aboard the vessel The riser 40, submarine pipeline 41, and umbilical may consist of multiple individual units connecting to a number of different wellheads 15. Each of the risers and umbilicals 45 may connect to multiple pipes 53 and multiple cabling 54 aboard the vessel. The multi-path swivel 52 in such a case would be equipped with sufficient fluid, instrument, and control paths (not shown) to service all risers 41 and umbilicals 45 individually. The umbilical 45 may also contain electrical or hydraulic power conduits (not shown) to power subsea pumping equipment (not shown) to boost the flow in the well 14.

Some of the wells 14 may serve as water injection wells 91 or as gas injection wells 93 (see Fig. 3) being supplied with water and gas, respectively, from the vessel While it is usually advantageous to avoid gas injection wells 93 when producing the crude oil using the technology taught in the present invention, all standard well production and stimulation schemes may be employed, provided the vessel 50 is fitted with the required equipment.

Figure 3 shows in more detail the vessel 50. In this figure the control, power, and instrumentation equipment 56, 54, 55, and 45 have been omitted for clarity.

Three risers 41 are shown, one 61 is connected to an oil producing well (not shown), one 62 is connected to a water injection well 91, and one 92 is connected to a gas WO 98/31919 PCT/US98/00127 injection well 93. It is to be understood that water injection well 91, water injection riser 62, gas injection well 93 and gas injection riser 92 are all optional features, and are only needed where local geological conditions or local regulations require that water or gas be re-injected into reservoir 10. Water for water injection is drawn from the sea at intake 76 and conveyed to the pump 74 through suction piping 75. The pump 74 has a discharge pressure sufficient to overcome the flow pressure losses in the well and the pressure in the oil field itself. The water is conveyed through the discharge pipe 73, through the multi-path fluid swivel 52, and into connector pipe 72. The connector pipe 72 is connected to internal piping (not shown) in mooring buoy 42 and then to the riser 62, and thereafter into the water injection well 91.

The produced crude-oil/water/gas mixture or live crude oil is received through riser 61 then through piping in the mooring buoy 42 (not shown) to connector pipe 71. The produced fluids are then conveyed through the multi-path swivel 52 to suction pipe 77 for pump 80. Pump 80 raises the pressure in the produced fluid sufficient so that the dissociation of gases in the crude oil stops or slows down significantly. The produced fluid is then conveyed through pipe 81 to the high pressure storage tank 82. Storage tank 82 is normally spherical or cylindrical. The vessel is usually equipped with a large number of tanks 82, but only one is shown in Fig. 3, for clarity. The produced fluid stored in tanks 82 will typically dissociate into a gas phase and fluid phase, separated by a surface 83 within the tank 82. The gas phase may be drawn off through the pipe 84 for use as fuel for powering the propulsion system 95 of tanker 50 or for other purposes aboard the tanker 50. As an alternative, the gas phase may also be drawn off, pressurized by a gas pump 94, conveyed by piping (not shown) to the multi-path fluid swivel 52, into a connector WO 98/31919 PCT/US98/00127 pipe (not shown) connected to internal piping (not shown) in mooring buoy 42, then conveyed to a gas injection riser 92 connected to the internal piping in the mooring buoy 42, and thereafter into a gas injection well 93.

Storage tanks 82, in order to limit the dissociation of gases in the crude oil and to safely handle and transport the crude-oil/water/gas mixture, must be designed to maintain the crude-oil/water/gas mixture at a pressure approximating that in the formation 10. The storage tanks 82 must therefore be capable of holding pressures of above kPa gauge pressure, pressures which may be in excess of 1.8 MPa gauge, and pressures possibly as high as 35 MPa gauge. One tank which will hold the pressure in this range and which will comply with maritime and other safety regulation is the type of tank described in U.S. Patent no.

4,010,864. This type of tank is particularly advantageous because it is much lighter than tanks of standard solid wall design. Application of tanks 82 similar to those described in US Patent 4,010,864 typically increases the amount of gas that can be carried by a given vessel 50 by to 100%.

In the event that produced water settles out in tank 82 it may be withdrawn through piping (not shown) and conveyed to pump 74 for re-injection into the formation through water injection riser 62 and water injection well 91.

Operation of the device of the present invention is as follows. First, one or more crude oil and gas wells 14 are drilled and completed using drilling equipment that is mounted on either a jack-up drilling rig or on a floating vessel (not shown). Thereafter, each drilled well is capped with a suitable wellhead 15. Wellheads 15 may include or be connected to subsea pumping equipment (not WO 98/31919 PCT/US98/00127 shown) which boosts the flow in the well, instrumentation and control equipment (not shown) which monitors the flow from the well and may shut off the flow from the well.

Riser 40, which may contain one or more risers 41 and umbilicals 45, is then connected to the wellheads 15, which riser 40 is then connected to a mooring buoy 42, which mooring buoy 42 is anchored to the sea bed in a known fashion.

When it is desired to retrieve and transport live crude oil from the wells 14, vessel 50 steered over the mooring buoy 42 and thereafter attached to the mooring buoy in a known manner. Cabling 54 and piping 53 on the vessel is connected to the umbilicals 45 and risers 41 by connection of piping 51 and cabling 55, connected to the swivel connection 52 on the vessel 50, with piping and cabling (not shown) in the mooring buoy 42, connected to risers 41 and umbilicals 45. Control and monitoring systems 56 on vessel 50 are then activated to send a signal, through cabling 54 and umbilicals 45, to open the flow of fluids from the wells 14 and/or to pump fluids from the wells 14. The live crude oil flowing from wells 14 flows through risers 61, through mooring buoy 42, through connector pipe 71 and suction pipe 77. The live crude oil is thereafter pressurized by pump 80 so that it flows into tanks 82, through pipe 81, and is thereafter stored in tanks 82 at a pressure approximately equal to that at which the live crude oil was kept in the reservoir 10, i.e., pressures of above 70 kPa gauge, pressures which may be in excess of 1.8 MPa gauge, and pressures possibly as high as MPa gauge. During the time when the vessel 50 is connected to mooring buoy 42, seawater may be pumped by pump 74 through intake 76, discharge pipe 73, riser 62 and into water injection well 91, if local conditions or regulations require water re-injection into the reservoir Additionally, or alternatively, water which settles out in tanks 82 may be pumped by pump 74 into water -16injection well 91. Additionally, if local conditions or regulations require gas re-injection into the reservoir 10, gas in tanks 82 may be pumped by pump 94 through pipe 84, through riser 92 and into gas injection well 93.

After the tanks 82 on vessel 50 have been filled with live crude oil, the control and monitoring systems 56 on vessel 50 are then activated to send a signal, through cabling 54 and umbilicals 45, to shut off the flow of fluids from the wells 14 and/or to discontinue pumping of fluids from the wells 14. Cabling 54 and piping 53 on the vessel are disconnected to the umbilicals 45 and risers 41 by disconnection of piping 51 and cabling 55 with piping and cabling (not shown) in the mooring buoy 42. Vessel thereafter is unattached from the mooring buoy 42 in a known manner. Vessel 50 then sails to a suitable onshore processing plant (not shown), where the vessel 50 is moored o and the live crude oil in tanks 82 is transferred to the processing plant for subsequent processing. During sailing of vessel 50, gas from tanks 82 may be conveyed through pipe 84 to powered equipment, including the propulsion system, on vessel 50, to be used 15 as a source of power for that equipment.

Figure 4 shows in diagram of a modified embodiment of the present invention, for the receipt and storage of live crude oil. Live crude oil is received on the vessel 50 at the flash tank 90 through pipe 81. In the flash tank 90 the live crude oil separates into a S"gas phase 98 and a liquid phase 97 which are separated by the liquid surface 91. The gas phase 98 is conveyed through pipe 88 to the storage tank 82. The liquid phase is conveyed through pipe 89 to the storage tank 82. In the storage tank 82, the liquid R occupies the bottom part 130 and the gas the top part 132, separated by the liquid surface S134.

o~ The continued production of oil keeps raising the level 134 and thereby raising the pressure in the tank 82. At some point the set pressure of relief valve 131 is reached -17and the gas phase 132 vents through pipe 99 to gas tank 100. Tank 100 is cooled by a coil 105 powered by a refrigeration machine 106. The crude oil liquid phase 130 would typically be maintained at temperatures ranging from 5°C to 60 0 C, depending on the characteristics of the crude oil. Tank 100 would typically be maintained at a temperature of -20'C to 10 0 C. Normally the pressure in tanks 82 and 100 would exceed 5 MPa, and thus all hydrocarbons but methane would condense into liquid form in tank 100. The liquids 101 collect at the bottom of tank 100 separated from the gas 103 by liquid surface 102.

Figure 5 depicts the system in Figure 4 in more detail. Pipe 77 aboard the tanker receives the crude oil and feeds it to pump 80 that raises the pressure of the fluid. For *oo* some oil wells, pump 80 may benecessary to increase the drive force on the crude oil o• from the well. For other wells having a high drive pressure, pump 80 may be omitted or 4" bypassed. The crude oil is conveyed through pipe 81 through metering valve 112, from which it flashes into flash tank 90. Flash tank 90 is preferably located at a low elevation 15 near the bottom of the vessel 50. The storage tanks 82 are generally located at a higher elevation than tank 90. The flash drum 90 is fitted with a liquid level sensor 115 sensing the location of the liquid-gas interface 96. The signal from sensor 115 is sent to a processing unit 116 that controls valve 117. Valve 117 is opened whenever the level 96 oooo falls below a preset level and closed when the level 96 rises above a preset level. By this action the crude oil is forced by the gas pressure in tank 90 into storage tank 82 through pipe 89. The gas 93 that flashes out of the crude oil in flash drum 90 is metered in the proper amount into tank 82 to maintain a nearly constant liquid level in tank p As the liquid level 134 rises in tank 82, the pressure increases as well. At some point the gas 132 is vented through relief valve 131 to the gas storage tank 100. The gas storage tank 100 functions in a similar manner to the oil storage tank 82, with the -18 exception that it is cooled by heat exchanger 105, powered by refrigeration machine 106.

As the liquid level increases in tank 100 the set pressure of relief valve 121 will be reached. The pressure in tank 100 is then kept constant by venting the gas through pipe 122 which may for example vent to a flare (not shown) or to the power plant or propulsion equipment for the vessel 50. The system will reach its maximum storage capacity when either the liquid level 134 or the liquid level 102 reaches the top of the tank 82 and 100 respectively.

Typically the vessel will be fitted with numerous storage tanks 82 and 100. The vessel may also be fitted with more than one flash drum 90. In this event the vessel will be fitted with piping and valving (not shown) that permits the sequential loading of tanks oo* 82 and 100.

.o However, in an alternative embodiment, the valve 117 may be closed continuously or the pipe 88 may be eliminated. In this embodiment, the liquid surface 96 would at all times be at the bottom of flash drum 90. Pipe 89 would, in this embodiment, convey a mixture of gas and liquid. The gas would in this embodiment bubble up through the liquid 130 in tank 82. In all other respects, the operation of this embodiment is identical to the embodiment described above.

The tanks 82, 90 and 100 may particularly advantageously be constructed as 000000 S• taught by U.S. Patent No. 4,010,864. The subject matter of that patent is incorporated herein by reference. The tank construction taught in U.S. Patent No. 4,010,864 is a cylindrical tank which is reinforced on the outside by helically deployed high strength wires. This construction typically reduces the weight of the tank by 30 to 50% compared to a solid wall tank. Thus the amount of gas that can be carried in a tanker fitted with reinforced cylindrical tanks is typically increased between 50% and 100% compared to a tanker fitted with solid wall tanks. The teaching of U.S. Patent No. 4,010,864 includes -19an outer spirally wound sheet made impermeable through welding along the helical lines between two adjacent windings. This feature may be omitted from the tanks 82, 90 and 100 because they are normally situated within a sealed hold in the tanker and therefore do not need the corrosion protection afforded by the impermeable outer sheath.

While the invention has been described in the specification and illustrated in the drawings with reference to preferred embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements of the invention without departing from the scope of the claims.

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Claims (46)

1. An oil production system for off-shore use comprising: an oil well, the oil well producing produced fluid, the produced fluids including at least one of water, crude oil and gas; a riser connected to the oil well; and a floating vessel, the float vessel including at least one high pressure storage tank, the high pressure storage tank being designed to store the produced fluids at a pressure above 200 kPa gauge pressure, the vessel further including at least one flash drum, the at least one flash drum being selectively coupled to the riser, the at least one flash drum being coupled to the at least one storage tank by at least one line. The system of claim 1, further comprising: a pump, the pump being connected to the oil well, the pump increasing the pressure of the produced fluids. The system of claim 1 or claim 2, wherein: the at least one line coupling the at least one flash drum to the at least one storage tank includes a first gas line and a liquid line.

4. The system of claim 3, further comprising: a second gas line, the second gas line drawing off gas from the at least one storage "tank.

5. The system of claim 4, further comprising: a relief valve in the second gas line, the relief valve opening at a set gas pressure.

6. The system of claim 4 or claim 5, wherein: the vessel includes powered equipment, and wherein the second gas line is -o connected to the powered equipment, gas from the produced fluids powering the powered equipment. -21

7. The system of any one of the preceding claims, wherein at least one of the at least one storage tank and the at least one flash drum comprises a cylindrical metal storage tank reinforced on the outside by one or more layers of helically deployed metal wires.

8. The system of claim 6 or claim 7, wherein: the powered equipment is a propulsion system.

9. The system of any one of the preceding claims, further comprising: a mooring buoy, the riser being connected to the mooring buoy, the mooring buoy selectively coupling the flash drum to the riser. The system of any one of claims 4 to 9, further comprising: at least one gas storage tank, the at least one gas storage tank being connected to .fl. the second gas line.

11. The system of claim 10, wherein: 0 the at least one gas storage tank includes a heat exchanger.

12. The system of claim 11, further comprising: a refrigeration unit, the refrigeration unit being connected to the heat exchanger, CC.. the heat exchanger cooling gas in the at least one gas storage tank.

13. The system of any one of claims 10 to 12, further comprising: C a vent line connected to the at least one gas storage tank, the vent line venting gas from the at least one gas storage tank.

14. The system of claim 13, further comprising: a relief valve in the vent line, the relief valve opening at a set gas pressure. R 15. The system of any one of the preceding claims, further comprising: a liquid level sensor in the at least one flash drum, the liquid level sensor sensing a 2 liquid level in the at least one flash drum.

16. The system of claim 15, further comprising: -22- a control valve in the at least one line, the control valve being connected to the liquid level sensor, the control valve controlling the flow of gas in the at least one line, thereby controlling the liquid level in the at least one flash drum.

17. The system of any one of the preceding claims, wherein the at least one gas storage tank comprises a cylindrical metal storage tank.

18. A method for producing crude oil offshore, comprising: producing the crude oil from an oil well; transferring the crude oil into at least one flash drum on a vessel; transferring gas and liquid from the at least one flash drum to at least one storage tank through at least one line; and neo storing the gas and liquid in the at least one storage tank at a pressure above i 200kPa gauge pressure. C V. 19. The method of claim 18, further comprising: pumping the crude oil from the well into the at least one flash drum.

20. The method of claim 18 or claim 19, further comprising: ~transporting the crude oil in the vessel.

21. The method of any one ofclaims 18 to 20, further comprising: °oo0!drawing off gas from the at least one storage tank.

22. The method ofclaim 21, further comprising: using gas drawn off from the at least one storage tank to propel the vessel.

23. The method of claim 21, further comprising: Rtransferring the gas drawn off from the at least one storage tank to at least one gas storage tank. S24. The method of claim 23, further comprising: cooling gas transferred to the at least one gas storage tank. -23- The method of claim 23, further comprising: venting gas from the at least one gas storage tank.

26. The method of any one of claims 18 to 25, further comprising: sensing a level of liquid in the at least one flash drum; and controlling the transfer of gas from the at least one flash drum to thereby control the level of liquid in the at least one flash drum.

27. The method of any one of claims 18 to 26, further comprising: transferring gas from the at least one flash drum to the at least one storage tank on the vessel through a first gas line, and transferring liquid from the at least one flash drum to the at least one storage tank on the vessel through a liquid line. :ooo 28. The method of claim 17, firther comprising: :oO. cooling gas transferred to the at least one storage tank to a temperature not below •0 -20 0 C. oo. 000S

29. The method of claim 20, further comprising: 15 disconnecting the vessel from the oil well; and S using gas drawn off from the at least one storage tank to propel the vessel after the i° vessel is disconnected from the oil well.

30. An oil production system for off-shore use comprising: oo*oo an oil well, the oil well producing produced fluids; a riser connected to the oil well; a floating vessel, the floating vessel including at least one storage tank, the vessel further including at least one flash drum, the at least one flash drum being selectively 1 coupled to the riser, the at least one flash drumbeing coupled to the at least one storage tank by at least one line; -24- a gas line connected to the at least one storage tank, the gas line drawing off gas from the at least one storage tank; and powered equipment on the vessel, the gas line being connected to the powered equipment, gas from the produced fluids powering the powered equipment.

31. The system of claim 30, further comprising: a pump, the pump being connected to the oil well, the pump increasing the pressure of the produced fluids.

32. The system of claim 30, wherein: the at least one line includes a second gas line and a liquid line.

33. The system of claim 30, wherein: the powered equipment is a propulsion system. 00".

34. The system of claim 30, further comprising: .a mooring buoy, the riser being connected to the mooring buoy, the mooring buoy selectively coupling the flash drum to the riser. 15 35. The system of claim 30, further comprising: S:at least one gas storage tank, the at least one gas storage tank being connected to the gas line.

36. The system of claim 35, wherein: the at least one gas storage tank includes a heat exchanger.

37. The system of claim 36, further comprising: a refrigeration unit, the refrigeration unit being connected to the heat exchanger, Rthe heat exchanger cooling gas in the at least one gas storage tank.

38. The system of claim 35, further comprising: Va vent line connected to the at least one gas storage tank, the vent line venting gas from the at least one gas storage tank.

39. The system of claim 38, further comprising: a relief valve in the vent line, the relief valve opening at a set gas pressure. The system of claim 30, further comprising: a liquid level sensor in the at least one flash drum, the liquid level sensor sensing a liquid level in the at least one flash drum.

41. The system of claim 30, further comprising cylindrical metal storage tanks reinforced on the outside by one or more layers of helically deployed metal wires.

42. A method for producing crude oil offshore, comprising: producing the crude oil from an oil well; transferring the crude oil into at least one flash drum on a vessel; and transferring gas and liquid from the at least one flash drum to at least one storage o• tank through at least one line; drawing off gas from the at least one'storage tank; and using gas drawn off from the at least one storage tank to propel the vessel. 15 43. The method of claim 42, further comprising: pumping the crude oil from the well into the at least one flash drum. go 44. The method of claim 42, further comprising: transporting the crude oil in the vessel. The method of claim 42, further comprising: using gas drawn off from the at least one storage tank to propel the vessel.

46. The method of claim 42, further comprising: /1 transferring the gas drawn off from the at least one storage tank to at least one gas storage tank. VT 47. The method of claim 46, further comprising: cooling gas transferred to the at least one gas storage tank. -26-

48. The method of claim 46, further comprising: venting gas from the at least one gas storage tank.

49. The method of claim 42, further comprising: sensing a level of liquid in the at least one flash drum; and controlling the transfer of gas from the at least one flash drum to thereby control the level of liquid in the at least one flash drum. The method of claim 42, further comprising: transferring gas from the at least one flash drum to the at least one storage tank on the vessel through a first gas line, and transferring liquid from the at least one flash drum to the at least one storage tank on the vessel through a liquid line.

51. The method of claim 45, further comprising: S••disconnecting the vessel from the oil well; and using gas drawn off from the at least one storage tank to propel the vessel after the vessel is disconnected from the oil well. 15 52. The method of claim 42, further comprising: cooling gas transferred to the at least one storage tank to a temperature not below 0 C.

53. A method for producing crude oil offshore, comprising: producing the crude oil from an oil well; transferring the crude oil directly into at least one unpressurized storage tank on a vessel without further processing of the crude oil. i R 54. The method of claim 53, further comprising: storing the crude oil in the at least one storage tank at a pressure in excess of -o kPa.

55. The method of claim 54, further comprising: -27- storing the crude oil in the at least one storage tank at a pressure in excess of 1.8 MPa.

56. The method of claim 53, further comprising: pumping the crude oil from the well into the at least one storage tank.

57. The method of claim 53, further comprising: pumping water into an oil field.

58. The method of claim 53, further comprising: transporting the crude oil in the vessel.

59. The method of claim 53, further comprising: drawing off gas from the at least one storage tank.

60. The method of claim 59, further comprising: oe using gas drawn off from the at least one storage tank to propel the vessel.

61. The method of claim 59, further comprising: pumping gas drawn off from the at least one storage tank into an oil field. 15 62. The method of claim 53, further comprising: cooling gas transferred to the at least one storage tank to a temperature not below 20 0 C.

63. An oil production system for off-shore use substantially as herein described with S"reference to any one of the embodiments of the invention illustrated in the accompanying drawings.

64. A method for producing crude oil off-shore substantially as herein described with reference to any one of the embodiments of the invention illustrated in the 1- accompanying drawings. -28 A system for transporting natural gas substantially as herein described with reference to any one of the embodiments of the invention illustrated in the accompanying drawings. DATED this 15 t Day of May, 2001 JENS KORSGAARD Attorney: KENNETH W. BOLTON Registered Patent and Trade Mark Attorney of Australia of BALDWIN SHELSTON WATERS