Patent Abstract:
A method and apparatus for off-shore production of oil. Special shuttle tankers with high-pressure cargo tanks capable of containing the produced live crude oil at a pressure close to that of the ambient pressure inside a subterranean oil field, and without any processing of the live crude oil prior to transportation are used. The produced live crude oil from the subterranean oil field is pumped directly into the high-pressure cargo tanks aboard the shuttle tanker. Lighter fractions of the live crude oil stored in the shuttle tanker may be used as a fuel to power the propulsion machinery and the auxiliary machinery aboard the shuttle tanker. The pressures in the tanks are ordinarily 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. The tanker vessel transports the produced live crude oil to an onshore processing plant for separation into gas, water, solids, and stabilized crude oil.

Full Description:
This application is a continuation-in-part of U.S. patent application Ser. No. 08/784,871, filed Jan. 16, 1997, issued as U.S. Pat. No. 6,012,530 on Jan. 11, 2000, and a continuation in part of U.S. patent application Ser. No. 08/814,147, filed Mar. 10, 1997, issued as U.S. Pat. No. 6,019,174 on Feb. 1, 2000. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to a method and apparatus for producing and shipping hydrocarbons, e.g., 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. 
     2. Description of the Prior Art 
     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 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 de-gassing 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. 
     In the event that no pipeline is available to transport the gas ashore, because of, e.g., 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 semi-submersible, 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. 
     Some of the problems of the above-described method are addressed in U.S. Pat. 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. Pat. 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. Pat. 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. Pat. 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. Pat. 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. Pat. 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. Pat. No. 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 large-capacity cooling plant. 
     SUMMARY OF THE INVENTION 
     The object of the present invention is to overcome some or all of the drawbacks associated with the present technologies. This object is achieved by constructing special shuttle tankers with high-pressure cargo tanks capable of containing the produced live crude oil (i.e., 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. Re-injection 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. 
     In the ordinary application of the invention, the produced oil will separate into two phases, a gas phase and an oil phase that has a lower gas-oil ratio (GOR) than the produced crude oil. As the pressure in the receiving tanks 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 (i.e., 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 25 kPa between the interior of the cargo tanks and the exterior atmosphere, i.e., 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 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&#39;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 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. Pat. 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. 
     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 
     FIG. 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 crude-oil/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 crude 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. 
     FIG. 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 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 through a pipeline  40  to a riser  41  terminating in a mooring buoy  42  for the shuttle tanker  50 . Mooring buoy  42  may be of the type shown in my U.S. Pat. Nos. 5,305,703; 5,339,760; 5,380,229; 5,553,976; 5,447,114 and 5,515,803; and my U.S. Pat. Nos. 5,647,295 and 5,676,083. The live crude oil is conveyed through the mooring buoy  42  by piping (not shown) in the mooring buoy  42  to piping  51  in the shuttle tanker  50 , through a multi-path 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  10 . 
     The well head  15  may include instrumentation and controls (not shown) in order to monitor the flow from the 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  45  connected to control and instrument cabling  55  aboard the vessel  50 . The cabling  55  is connected through the multi-path swivel  52  to fixed cabling  54  to control and monitoring systems  56  aboard the vessel  50 . 
     The riser  40 , submarine pipeline  41 , and umbilical  45  may consist of multiple individual units connecting to a number of different wellheads  15 . Each of the risers  40  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  50 . 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. 
     FIG. 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 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 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 70 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. Pat. 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 U.S. Pat. No. 4,010,864 typically increases the amount of gas that can be carried by a given vessel  50  by 50% 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  10 , 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 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. Pipeline  40 , which may contain one or more risers  41  and umbilicals  45 , is then connected to the wellheads  15 , which riser  41  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 riser  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 35 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  10 . Additionally, or alternatively, water which settles out in tanks  82  may be pumped by pump  74  into water injection 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 dis connection of piping  51  and cabling  55  with piping and cabling (not shown) in the mooring buoy  42 . Vessel  50  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 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 as a source of power for that equipment. 
     FIG. 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 gas phase  98  and a liquid phase  97 , which are separated by the liquid surface  96 . 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 occupies the bottom part  130  and the gas the top part  132 , separated by the liquid surface  134 . 
     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  96  is reached and 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° C., depending on the characteristics of the crude oil. Tank  100  would typically be maintained at a temperature of −20° C. to 10° 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 . 
     FIG. 5 depicts the system in FIG. 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 some oil wells, pump  80  may be necessary to increase the drive force on the crude oil from the well. For other wells having a high drive pressure, pump  80  may be omitted or 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 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  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  98  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  90 . 
     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 exception that it is cooled by heat exchanger  105 , cooled 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  82  and  100 . 
     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  90 ,  82  and  100  may particularly advantageously be constructed as taught by U.S. Pat. No. 4,010,864. The subject matter of that patent is incorporated herein by reference. The tank construction taught in U.S. Pat. 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. Pat. No. 4,010,864 includes an outer spirally wound sheet made impermeable through welding along the helical lines between two adjacent windings. This feature may be omitted from the tanks  90 ,  82  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.

Technology Classification (CPC): 1