BRPI0504586B1 - subsea heating module for hydrocarbon production and method for subsea storage and replacement - Google Patents

Abstract

subsea hydrocarbon production module and methods for subsea storage and replacement thereof a subsea hydrocarbon production module, said module comprising an electrical or hydrocarbon combustion heating system (11) integrated with other equipment submarines a pumping module (10), a bab (30), an anm (20), plet, plem, corel flow type flow system, and the like, so it is possible to direct oil production from one or more wells to a PEU located over long distances or on land. Also described is a method for subsea storage of the modules of the invention, comprising providing the seabed with at least two coated holes (61) and (62) such that a spare module (63) is installed in the first hole (61). in perfect working condition, while the second hole (62) is available to receive (accommodate) any defective module removed (10), where it will be parked awaiting subsequent removal to the surface for repair. Failed equipment will be removed by boat with or without sound.

Description

SUBMARINE HEATING MODULE FOR HYDROCARBON PRODUCTION AND UNDERWATER STORAGE AND REPLACEMENT METHOD The present invention pertains to the field of subsea equipment intended for the production of hydrocarbons in general (petroleum), where the production of one or more oil wells must be transported by subsea pipelines to a stationary production unit.

To increase flow and ensure flow, oil is heated through one or more subsea, electric or combustion heating modules, where such modules can be integrated with other subsea equipment, directing the production of one or more wells directly to a stationary production unit (UEP) that can be located over long distances from wells, even on land.

An innovative method of underwater storage and quick replacement of faulty (faulty) modules of said system is part of the present invention.

BACKGROUND OF THE INVENTION Offshore hydrocarbon (petroleum) production requires the drilling of subsea production and injection wells and the installation of subsea equipment such as: Wet Christmas Tree (ANM), manifolds, pump adapter bases, separators, pipeline end terminal (PLET), pipe line end manifold (PLEM), pump adapter bases (BAB), production adapter bases (BAP), pump modules (MOBO), subsea separation units ( water / oil or gas / liquids), subsea heaters, electrical transformers, pig scraper launcher (line scraper), flowiines and risers between the wellhead and the stationary unit of production (UEP).

Heating modules when combined with pumping modules are called pumping and heating module (MBA). The UEP can be built and located on a boat, on a fixed platform or even on land. When these UEPs are built on ship hulls or semi-submersible hulls, having capacity for oil processing, storage and discharge, they are called Floating Production Storage Off Loading (FPSO). The race for technologies that will make it possible to produce oil at sea, off the coast and without the aid of large platforms inhabited by hundreds of employees, today involves the majority of oil companies. As exploration progresses to deeper and deeper water depths, the cost of the UEPs, risers, mooring and also the operating costs increase as well as the risk of the operation. Exporting oil from wells directly to land, called subsea to shore (also known as subsea to beach), still faces technological limitations.

An alternative is to drain oil to a fixed or floating production platform located in shallower waters midway across the continent, this system being known as subsea to near shore.

Another alternative is the use of simplified Stationary Units, with few functions, including those for the control and distribution of electricity, but without storage, handling or processing of oil.

Also the development of satellite fields and wells (large distance from UEP) requires lower cost solutions. They are small fields, 10, 30 or 50 kilometers apart, that do not pay the investment of a new platform, but that could become productive if interconnected to a platform positioned at a greater distance than usual: they are called tie backs As oil is produced, the oil reservoir generally tends to depressurize. In offshore conditions it is usual to inject water, usually from the sea, to avoid depressurization of the oil reservoir. Over time the wells produce a large amount of water. The fate of this water is always a problem, since for its disposal to the sea it must be rigorously treated. Re-injection into the producing reservoir, depending on water quality, is also a problem. Re-injection into a disposal reservoir (aquifer type) requires the drilling of costly submarine wells.

Producer wells are usually (a few kilometers) away from the production unit, requiring the supply of energy in the form of pressure and sometimes also temperature, so that fluids may be able to flow towards the production unit, usually with high flow rates to maintain the project's economic attractiveness.

Several artificial lifting methods are used to increase these flows. One of these methods uses pumps, such as submersible centrifugal pumps (BCS) installed at the bottom of oil producing wells and usually driven by electric motors, known as electrical submersible pumps (ESP). Under some conditions these pumps may be mounted inside modules installed on the sea floor. Such pumping modules can use various types of pumps, including BCS as well as multiphase pumps. The former (BCS) feature long and slender geometry as they are designed to be installed inside wells and the latter (multiphase) a compact geometry as they are usually installed on the seabed (outside the well). From US 4,900,433, it is already known that a BCS-like pump is installed inside a dummy built to accommodate a separation and pumping assembly, as well as to conduct oil flow. from the entrance of this well to the suction of the pump installed inside it. From Applicant's Brazilian application PI 0301255-7 and incorporated herein by reference in its entirety, it is known that it is possible to use a pumping module connected directly to subsea equipment such as a wellhead / ANM assembly. This module consists of a closed tubular body and a hydraulic connector, where said connector is coupled to the mandrel (Intermediate Flow Socket - TIF) of subsea equipment previously installed in the bottom. It is also known from US 6,419,458 and US 6,688,392 that it is possible to install a BCS-like motorcycle pump assembly, which is hydraulically connected to a dummy well, both to produce oil and to inject water or other fluid. in the oil reservoir. From Applicant's Brazilian Application PI 0400926-6 (and corresponding United States filing, US10 / 982,848) and also incorporated herein by reference, it is known that it is possible to install a pumping module housed within a lined hole (hollow pile) on the sea floor and coupled to a production adapter base (BAB). This hole is located a few dozen meters (away) from the wellhead. Applicant's Brazilian application PI 0404603-0 and also incorporated herein by reference fully describes the installation of a pumping module housed within a coated hole (hollow piling ), or in the water well itself in underground aquifer water collection and injection systems. Applicant's Brazilian patent application PI 0403295-0, also incorporated herein by reference, describes the installation of two or more pump assemblies in independent modules mounted on structures that are supported directly on the sea floor. Applicant's Brazilian Application PI 0500996-0, also incorporated herein by reference, describes the installation of a pumping module integrated with subsea equipment which may be ANM, manifold, PLET or other similar subsea equipment.

Several heating methods, including those described in U.S. Patent Nos. 4,716,960, 5,065818, 6,023,554 and 6,758,268 use electric heaters, generally installed inside the wells or on the surface, to provide heat to the oil and facilitate its flow.

Much of the installation and operating costs of subsea equipment are associated with interconnection architecture and installation facilities.

Currently the distance between submarine oil wells and the production unit is limited to a few kilometers. Such restriction or technological barrier is the result of pressure loss (pressure drop) and temperature loss during oil (petroleum) flow. Loss of pressure will result in reduced flow and therefore reduced oil production. With the loss of temperature, the oil becomes more viscous, increasing the pressure loss. And if the temperature falls below the crystallization onset temperature (TIAC) there will be deposits inside the ducts, causing them to clog.

In addition, the lower the temperature and the higher the pressure of multi-phase oil, gas and water mixtures, the greater the possibility of hydrate formation, which may also block the duct.

For the displacement (transport) of viscous fluids such as heavy oils, corei flow systems have been developed where a quantity of water is injected near the inner wall of the ducts to create a thin film of water to reduce the loss. (pressure loss i) and facilitate oil flow. The application of this technique for deep water production where temperatures are low and pressures high increases the risk of hydrate formation.

Thus, despite all available technologies for the production of hydrocarbons in an underwater environment, there remains a need in the art for an underwater, electric or hydrocarbon combustion heating module, integrated with other subsea equipment such as a pumping module, easy installation and retrieval for use in heating oil, injected water or water used in corei flow type systems, such system being described and claimed in the present application.

SUMMARY OF THE INVENTION

Broadly, the invention relates to a heating module, integrated with subsea equipment, for example pumping modules, in Skid-based, coated-hole-based, meter, ANM, manifold, separator, transformer architecture. electrical systems, pig launchers, PLETs, corei flow type systems, etc., used in the production of hydrocarbon fluids, such system facilitating the production and flow of petroleum hydrocarbons, even over long distances. The power source for the heating system may be electrical energy or underwater combustion of hydrocarbons (eg natural gas). The principle of electric heating can be resistive, inductive or a combination thereof.

Also part of the present invention is an innovative method of underwater storage and quick replacement of faulty (faulty) underwater modules through the use of simple vessels with cable operation.

Thus, to drain oil from subsea wells, which are located at large distances from production units, pump and heat modules (MBA) are used, where one or more MBA are installed along one or more pipelines or drainage lines to the unit. of production.

Thus, the invention provides an integrated (combined) heating module with other subsea equipment for fluid flow between the producing wells and the subsea production unit or between it and the mainland. The invention also provides an induction electric heating system, integrated with a subsea transformer with one or more output voltage, so that the number of subsea, electrical and hydraulic connections is optimized, and other equipment can be supplied with electrical power. . The invention further provides a four-way flow diverter adapter with one inlet and two outlets so that the inlet can be connected to an outlet chuck of a submarine equipment connection module, enabling the installation of any module, such as a heating module and the installation of the MCV on the other output of the adapter. The invention further provides a pump module combined heating module (MBA) system, allowing flow at greater distances and flow rates than usual, both in the well direction to the production unit as well as the reverse flow, which may be used for injection of water and other fluids. The invention also provides a system where the production unit may be installed farther (tens of kilometers) than usual, eventually on land, eliminating the need for an FPSO with high construction, installation and operation costs. The invention alternatively provides for the installation of a pump within a producing downhoie and the installation of external heating modules integrated in the MNA assembly or in seabed bases.

The invention also provides an innovative method of underwater storage and quick replacement of faulty modules utilizing simple, low cost vessels with cable operation. BRIEF DESCRIPTION OF DRAWINGS

The accompanying FIGURES 1A and 1B schematically show, for reference and comparison only, two temperature profile graphs along the duct of two MBA systems.

The accompanying FIGURES 2A and 2B show schematically, for reference and identification purposes only, the main components of a MOBO, object of Brazilian application PI04Q0926-6, combined with a heating system located at the top of the MOBO, forming an MBA.

The accompanying FIGURES 3A and 3B show schematically, for reference and identification purposes only, the main components of a MOBO, object of Brazilian application PI0400926-6, combined with a heating system, located within the MOBO itself, forming an MBA. FIGURE 4 The appendix shows schematically, for reference and identification purposes only, the main components of a MOBO, object of Brazilian application PI0400926-6, integrated with a heating system located inside the module, between the motor and the pump suction, forming an MBA. The accompanying FIGURE 5 schematically shows, for reference and identification only, an ANM assembly with an MA heating module integrated with the MCV thereof. The accompanying FIGURE 6 shows schematically, for reference and identification purposes only, the main equipment of a set comprising a Pump Adapter Base (BAB) and a pump module (MOBO) integrated with an independent heating module (MA). The attached FIGURE 7 schematically shows a flowchart of the configuration of Figure 6 of an MBA with the separate (independent) module heating system. The attached FIGURE 8 shows an integrated MBA with a manifold. The attached FIGURE 9 schematically shows a flow diverter adapter.

The accompanying FIGURE 10 schematically shows the sequence of a subsea module parking and replacement method. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS The invention therefore relates to a heating module, integrated with subsea equipment, for example: pumping modules, in skid type, lined hole supported base, meters, ANM , manifold, separators, launchers, PLETs, etc., used in the production of hydrocarbon fluids.

Such modules can be vertical or horizontal, installed and retrofitted by SondaIDrili pipe or Vessel / cable, housed wholly or partially in coated holes or externally above the sea floor, and mounted on skid-like structures, facilitating their recovery by cable or drill pipe.

BCS type pumping units have the particularity that the electric motor cooling is provided by the pumped fluid itself. For viscous fluid applications, this is a highly desirable feature, as system efficiency is improved with fluid heating and the consequent reduction in viscosity, part of the heat-dissipated energy being reused by oil heating. In this case the heating systems, when electric, may be located (arranged) upstream or downstream, or between the motor and the pump.

On the other hand, the BCS may still be located inside (bottom) of an oil well or housed inside an underwater pumping module installed on the sea floor in the various configurations proposed by patent applications PI 0301255-7, 04009266, and 0404603-0 of the Applicant, as cited above. The ideal electrical voltage used in pumps may not be the same as heating systems. Also, due to the large distances involved, it may be recommended to use a transmission voltage higher than the pump motor voltage. In both previous situations it will be necessary to use an underwater electric transformer to lower the electric voltage. Depending on the dimensions, the transformer can be accommodated in the heating module itself or mounted on an independent base resting on the sea floor. The interconnection between the transformer and the heating module and other subsea equipment that also require power will be through short power cables with electrical connectors at the ends, known as electrical jumpers.

A transformer can be integrated with an electric heater, constituting a single module or equipment, so that the transformer is used to lower or increase the voltage supply to any one or more subsea equipment and at the same time it is used to generate heat, heating the oil. Such a transformer module and subsea electric heater system may have more than one output voltage.

Regarding power supply via electric power cable, there may be a single power cable for the pump motor and the heating system, with or without use of a transformer. The power supply may also be individual, ie one cable for the pump and one for the heating system. In this case the current used for the heating system may be of alternating or direct current type, since direct current is more suitable for transmission over long distances (several kilometers), and works well with electric heating systems. The concept of electrical MBA demands high electrical powers, requiring the generation of large amounts of surface energy. One way of generating this energy is by burning part or all of the gas produced. This system becomes highly attractive in places where there is no consumer center for this gas. In this case, the gas produced could have four destinations: production of liquefied natural gas known as LNG for export to large consuming centers, re-injection to maintain reservoir pressure and to avoid gas flaring, simple flaring or power generation flaring. It can be converted into thermal energy to increase the oil recovery rate of the reservoir. LNG production is not widely applied because it requires large investments in transportation and storage infrastructure, and huge amounts of gas for economies of scale. Gas re-injection is mainly applicable to light oil reservoirs, where a gas cut is less likely to reach producing wells prematurely, impairing its productivity, with higher gas production at the expense of oil quantity. Injection requires high investments in high pressure compressors, subsea gas lines and injection wells. Simple (unused) gas flaring, due to the lack of a nearby consumer center, should be avoided for both environmental reasons and energy waste. Such energy may ultimately be used for heat generation to be supplied to the oil reservoir in order to improve recovery and productivity rates, especially in heavy oils. Simple burning has been a practice banned by many regulators. Sometimes this practice is only allowed in the testing and pilot design phase. Gas flaring for thermal energy generation has applicability for high viscosity heavy oil reservoirs. For terrestrial wells such thermal energy is transmitted by injection of water vapor generated by gas flaring. Injection may be continuous or intermittent. In offshore fields, the practice of steam injection is little used due to the difficulties of interconnecting UEP with the wells, through risers and isolated lines and also the difficulty of availability of good quality water for steam generation. In these cases, less effectively, thermal energy can be transmitted to the reservoir by injecting water from the sea and heated without full conversion to steam due to problems with salt deposits in the steam generator tubes (boiler) or generation of steam. steam locally (in situ) in the well itself.

When pumping units are equipped with seawater cooled motors, the heating systems can be located before or after the pumps, although their location before the pump has the advantage that the pump works with a warmer fluid and less viscous, improving its efficiency and increasing the flow to the same engine power value.

Another alternative for heating the oil produced is a combustion heating module, where heat is generated by the combustion of hydrocarbons carried out on the seabed, by the injection of gas and compressed air by independent lines into a subsea heater (furnace). performed the burning. Combustion gases can simply be released to the bottom of the sea to flow to the surface or injected into oil production lines to help lift the oil similar to gas lift.

Similarly, in subsea separation systems, for example hydrocarbon separation from water, the heating system may be located before or after separation. After separation, heating can take place either on the oil (hydrocarbon) outlet line and / or on the separate waterline if it is directed to an injection well in the oil reservoir itself. Heating water before injection It is a way of providing heat to heavy oil reservoirs by facilitating the mobility, drag, movement and production of the water and oil mixture.

Under certain conditions the water produced may not be suitable for re-injection into the oil producing reservoir. The main characteristics (properties) that affect the quality of water produced are: presence of solids and / or presence of oil. The presence of solids is highly harmful to formation and may cause blockage of the injector well. The presence of oil, although less harmful, can decrease injector well injectivity.

To overcome the above limitations, it is possible to capture, treat and inject seawater into the oil producing reservoir. On the other hand, the water produced can be injected into a reservoir other than the producer, usually shallower and lower pressure, facilitating the re-injection. As the re-injection reservoir is not the oil reservoir, injection at pressures above the fracture pressure is possible, since the risks are much lower in case of fracture with communication to the seabed.

Usually Flotation Production Storage and Offloading (FPSO) type production systems have capacity (volume) for storing a few days of production. From time to time it is relieved (discharged) through an off loading system for shuttle tanks responsible for transporting oil to offshore oil terminals. The distances of these terminals vary from tens, hundreds, even thousands of kilometers. These distances reflect the location of the producing pole or province and the consuming center. In the Brazilian case, practically most of the oil produced is consumed or placed on the domestic market, thus a system for direct flow to land and hence for refineries by terrestrial pipelines becomes more attractive.

In order for the produced oil or the injected water to reach the destination with an economical flow rate, it is necessary to use pumps that will increase the energy through a pressure increase. When the starting point is too far from the finishing point, a large amount of energy must be supplied to the fluid, not only in the form of pressure but also in heat (heating).

More than one pumping and heating module (MBA) can be installed in series along a flow duct, increasing the energy transferred to the oil flow, as well as increasing the possible gap between the producing well and the UEP, which may be located dozens of kilometers away and may be in shallow water or even on land.

Such power may be supplied by two or more modules, installed at a single point or distributed at two or more points along the path of the fluid conducting duct.

In the specific case of direct oil production to land between large distances, as the source of electricity is usually on the land side, the adoption of at least two pumping and heating sets is most appropriate. In this way, a first pumping is performed with a pump inside the well or by a pumping module installed near its head. And subsequent pumping is performed along the pipeline path.

Depending on the oil characteristics and the physical conditions of pressure and flow temperature, it may be necessary in addition to the pressure supply, heat supply, in which case these modules will be of type MBA. The use of two MBA, rather than just one near the wellhead, but with the same total installed power, the MBA being distributed along the production duct, leads to a more appropriate temperature profile as in the first module it is sufficient energy to maintain the temperature safely above TIAC. In the second heating point sufficient energy is transmitted to keep the fluid back above the TIAC.

Pig-pass cleaning operations hinder production, that is, there will be a decrease in flow during such operation, and the risk of clogging due to the dragging of large amounts of deposited material. A more distributed temperature profile decreases the amount of material deposited over time and hence the number of pig passages.

In addition to lifting methods for increased flow, secondary recovery methods are common, such as: injecting water into the oil sump to maintain pressure to prevent depletion of the oil sump. Initially little water is produced. Over time, some of the injected water mixed with the reservoir water itself is produced. Depending on the type of oil emulsions may form which most often cause an increase in the viscosity of the mixture. Submarine water separation units are currently being installed to minimize runoff to the production unit. Water can be either a favorable or unfavorable element for flow, depending on the type of oil as well as how it is in the mixture, impairing the flow. When water is free-form, it favors flow by reducing viscosity; emulsified water increases the viscosity of the mixture. Heavy oils are easier for emulsion formation.

For injector wells with heads close to the subsea water / oil separation system, in certain situations it is advantageous to heat the separated water by means of an MBA system prior to water re-injection. Produced and discharged oil may still undergo some sort of underwater water separation to reduce the volume of liquid discharged to the UEP. Separate water can be re-injected through pumps. If the produced oil is heavy type there is interest in providing hydraulic energy in the form of pressure to the injected water, as well as thermal energy in order to improve the oil mobility and flow within the oil reservoir. Thus, for separate water injection into the oil reservoir it is possible to install one or more MBA at the separator outlet to provide hydraulic as well as thermal energy to the reservoir.

Water / liquid separation equipment, combined with pumping, can be designed and constructed with slender geometry to be housed within a well used for water disposal. Such an arrangement facilitates installation, operation, maintenance intervention and reinstallation.

Underwater heating systems may also be applied in combination with corei flow type flow systems used for the flow of highly viscous liquids such as heavy oils. The characteristic of corei flow systems is to use a film of water close to the inner surface of the conductive duct (pipe) in order to reduce the pressure drop and facilitate the flow. The application of this technique in an underwater environment is difficult due to the risk of hydrate formation in mixtures that have gas and water under pressure, low temperature conditions. In this way the water used for corei flow can be preheated with subsea heating module systems.

Under certain conditions the water produced may not be suitable for re-injection into the oil producing reservoir. The main characteristics (properties) that affect the quality of water produced are: presence of solids and / or presence of oil. The presence of solids is highly harmful to formation and may cause blockage of the injector well. The presence of oil, although less harmful, can decrease injector well injectivity.

To overcome the above limitations, it is possible to capture, treat and inject seawater into the oil producing reservoir. On the other hand, the water produced can be injected into a reservoir other than the producer, usually shallower and lower pressure, facilitating the re-injection. As the re-injection reservoir is not the oil reservoir, injection at pressures above the fracture pressure is possible, since the risks are much lower in case of fracture with communication to the seabed.

MBAs can be integrated with subsea equipment such as: ANM, manifolds, Pump Adapter Bases (BAB), separators, pig launchers, corei flow systems, etc. It is also possible to install heating modules individually or in combination with other subsea equipment such as: ANM, PLET, manifold, flowlines, etc.

Such modules can be vertical or horizontal, installed and retrofitted by SondalDrilIpipe or Vessel / Cable.

The modules are housed wholly or partially in coated holes or externally above the sea floor in skid bases.

Although some of the embodiments relate to the technique for integrating a heating system with subsea equipment, including a pumping system in a modular architecture, it is easy for one expert to deduce other possibilities for integration with other subsea systems not specified herein. request.

More particularly, in one possible embodiment the present invention provides a modular subsea system that provides potential energy (pressure) and thermal energy (temperature) to the petroleum produced.

Much of the installation and operating costs of subsea equipment are associated with their interconnection architecture and ease of installation and retrieval for maintenance. The use of integrated systems that reduce and simplify underwater interconnections between equipment and also facilitate their recovery and reinstallation is highly desirable.

Thus, one embodiment of the present invention contemplates the combination of pumping or re-pumping systems with oil heating systems in one or more modules comprising an MBA in an architecture or arrangement to facilitate installation of said module in an underwater environment. .

Another embodiment of the invention contemplates combining (integrating) MBA systems with other subsea equipment such as splitters, pig launchers, electrical transformers, etc., to further optimize the interconnections between them. It is important that these subsea pumping, and / or heating, and / or eventual separation equipment are constructed in such a way as to facilitate their installation, operation and recovery for maintenance and reinstallation.

A further embodiment of the invention is a modular system consisting of a pumping or heating module integrated with other subsea equipment.

In equipment that combines the pumping and heating functions, the heating devices may be arranged or positioned in various ways with respect to the pumping unit. The present modular system comprises various embodiments, which will be further detailed in the various Figures accompanying the present application.

Because the MBA in the present invention is located outside the oil well, it can be installed or retrofitted either by a threaded pipe riser (also known as a drip pipe riser) or by a vessel (operation). cable). In both cases there is significant savings as, in the event of a failure of the MBA assembly, it will not be necessary to make a long intervention (tens of days) in the producing well, with high costs of intervention probe and a prolonged production shutdown. . The concept of the invention is applicable to both producer wells and injector wells, including groundwater capture and injection systems in hydrocarbon reservoirs, similar to the systems described in Brazilian application PI 0404603-0.

Another advantage of the present system is that it can be applied not only to new wells but also to existing wells. The invention will be described hereinafter by reference to the accompanying Figures. In the Figures the same numerical references will be used to designate equal or similar parts. Figure 1A schematically shows a graph where the distance from the wellhead to the FPSO is plotted on the D axis, and the temperature inside the duct, T axis. Curve 1 shows the temperature profile of a system with only one MBA close to head of the producing well that is interconnected with a UEP (FPSO). Curve 2 represents the crystal onset temperature (TIAC) of a particular type of oil. Figure 1B schematically shows a graph where the distance from the wellhead to the FPSO is plotted on the D axis, and the temperature inside the duct, T axis. Curve 1 shows the temperature profile of a system with an MBA near the head. from the producing well and another halfway between the well and the UEP (FPSO). Curve 2 represents the crystal onset temperature (TIAC) of the same type of oil as Figure 1A.

From the graphs it can be seen that for the same amount of energy supplied by the systems of Figures 1A and 1B to the fluid (petroleum), the graph shown in Figure 1B shows a better temperature profile distribution, generating less losses to the environment. In addition, because the average temperature of the graph in Figure 1B is higher than that of the graph in Figure 1A, there will be less paraffin deposition and the flow rate of a flow line cleaning device (pig) will also be lower, may in some cases be waived.

Figures 2A and 2B show schematically, for reference and identification purposes only, the main components of a MOBO pumping module (10), object of the Brazilian application PI0400926-6, combined with a heating system (11) housed within a control module. heating (12) located on top of the MOBO (10), forming an MBA. Such heating module (12) can be recovered and reinstalled individually by unlocking the connector (13) or together with MOBO (10) by unlocking the hydraulic connector (14).

A motor (17) and pump (16) assembly are housed in the pumping module (10). The hydraulic flow of oil through the heating system (11) can be implemented in two ways. In the first, the oil after crossing the MOBO (10) is directed to the heating system (11) and from it to the UEP (not shown in the Figure). In this case, the heating takes place after the pumping. In the second mode, not shown in the Figure, the flow is reversed to first pass the heating system (11) and then directed to the MOBO (10). In this case, the heating takes place before the pumping. The heating system (11) is fed by the power cable (19), similarly the pumping module (10) is fed by the power cable (18). Also shown at the top of the module (10) is a subsea electrical transformer (15) which should be used when the pump and heater voltage values differ. This transformer (15) may be located as shown, or alternatively on a base (not shown) resting on the sea floor. The transformer arrangement (15) at the top of the module (10) is also applicable to the configurations of Figures 3 and 4 described below. Figure 3 shows schematically, for reference and identification purposes only, the main components of a MOBO (10), object of Brazilian application PI0400926-6, combined with a heating system (11) located inside the module (10) itself, of said system heats both the suction and discharge oil of the pump (16). A single module (10), which houses a motor (17) / pump assembly (16) and a heating system (11), makes up an MBA. Figure 4 shows schematically, for reference and identification only, the main components of a MOBO (10), object of the Brazilian order PI0400926-6, integrated with a heating system (11) located between the motor (17) and the suction of the pump (16) forming an MBA. Figure 5 schematically shows, for reference and identification only, an ANM assembly (20) with a heating system (11) integrated with the MCV (21). This configuration allows an in-pit installation of a BCS (not shown) combined with a heating system (11) installed on the MCV vertical connection module (21). Installation of the system (11) on the MCV (21) does not require any modification to the standard ANM assembly (20) except for the modification of the MCV (21) itself which will communicate with the system (11) through two holes, input and output. flow of oil to be heated. In this case, the system (11) is downstream of the BCS (not shown) installed at the bottom of the producing well (22). This type of architecture can be applied to any subsea equipment equipped with MCV (21). Figure 6 shows schematically, for reference and identification purposes only, the main equipment of a set comprising a Pump Adapter Base (BAB) (30) and a pump module (MOBO) (10) subject to patent application PI0400926-6 . It additionally shows an independent heating module (MA) (12) integrated into the BAB assembly (30) and where said MA may be upstream or downstream of the MOBO flow (10). The heating module (12) and the pumping module (10) are installed in independent and interconnected capsules so that their installation and recovery can be performed together or individually. Figure 7 schematically shows a flowchart of the configuration of Figure 6, where a heating system (11) is housed in a separate module (12) and independent of the pump module (MOBO) (10). In the event of failure of the pump module (10) or the heating system (11), the bypass valve (23) is opened and the shutoff valves (24) are closed to allow their removal. modules. Figure 8 shows a pumping module (10) combined with a heating system (11), in one of the configurations shown in Figures 2,3 or 4, integrated with a manifold (40). Figure 9 schematically shows a diverter adapter (35).

Such a device allows for the installation of subsea modules in general and can be installed on an output or input mandrel (36) of subsea equipment such as: ANM, manifold, etc., so that it is possible to divert flow (38) to any module (37), for example pump (10) and heating system (11), and interconnect the flow return (35) with a new mandrel to which a flow line MCV (21) will be connected.

Such a device allows the coupling of subsea modules to already installed equipment or new equipment without constructive alteration, maintaining the standardization.

It also allows the installation of other types of modules, such as: meters (flow, temperature, sand detection, etc.). It is also possible to install a module bypass valve (37), not shown in the Figure, directly interconnecting the inlet flow (38) with the outlet flow (35). Also shown are guide funnels (34) for guiding the diverter adapter coupling (35) to the mandrel (36) and also guiding the MCV coupling (21) with the diverter (31) through the MVC connector (33). A mandrel (39) adapts a module (37) to the adapter (31).

Another aspect of the invention is a method for stocking and replacing (installing) subsea modules. The failure (defect) of subsea modules, such as: pumping modules, heating modules, pumping and heating modules, etc .; requires replacement of them. Large submarine modules, tens of meters, usually require the use of a probe for mounting and dismounting. In the event of their failure there will be a difficulty in the immediate mobilization of a rigged vessel, which is scarcer and expensive. Sometimes it will take tens of days for spare parts to be transported ashore, and the availability of a probe for module recovery and replacement of defective components.

This repair (replacement) of these modules is time consuming, as it requires: availability and displacement (navigation) to the rigged vessel rental, transportation (shipping) of components to be replaced, mobilization (shipping) of specialized assembly personnel. removal, disassembly, component replacement, assembly, and finally reinstallation of the repaired module.

During all this time, the oil well will be stationary or will produce a lower than usual flow rate. To minimize such production losses, it is attractive to store complete (extra) modules at the bottom of the sea in order to expedite the replacement of failed modules.

One or more reserve modules will be stationed at the bottom of the sea in bases, clad holes or hollow piles (torpedo piles). In this way it is possible to remove the failed submarine module, guard (parking) in a specially designed vacant base or hole and replace it with a previously parked spare submarine module. Such operation can be performed by cable, through a lower cost vessel, exempting the use of marine rig.

With the removal of the defective module the main equipment will be able to receive another similar module and in perfect working condition. Such a spare module is parked at the bottom of the sea, in a base or in a hole. This enables immediate replacement using a lower cost vessel.

In order to ensure adequate storage conditions for undersea modules on the seabed in parking areas and to prevent exposure to seawater under aggressive saltwater conditions, the undersea module can be filled with less corrosive fluids, eg water with inhibitor corrosion, diesel, nitrogen, etc. In addition, module connection points, such as hydraulic and electrical connectors, can be shielded to prevent contact with seawater, proliferation of organisms and deposits on the module.

After removal and parking of the faulty (defective) module on a seabed basis, it will be later recovered in a scheduled operation by any available marine rig or vessel for surface or ground disassembly and replacement of defective components. After the repair it will be lowered again and parked at the bottom of the sea, becoming the spare module.

A single module parked at the bottom of the sea may serve as a backup to replace one or more operating modules. If there are a large number of modules in operation, it is possible to have more than one module parked to ensure prompt replacement in case of failure.

With this method of repair it is possible to optimize the use of marine probes, as the defective module can be repaired within a schedule where it will be executed during the period when the probe is most available for this type of operation, for example: maintenance. BOP, awaiting sea conditions, etc.

Such a parking and replacement method can best be seen from Figure 10.

One or more wells or ANMs (20), producer or injector, are interconnected to a subsea pumping module (10). The marine floor is provided with at least two coated holes (61) and (62) so that in the first hole (61) a spare module (63) is installed in perfect working condition, while the second hole (62) is available to receive (accommodate) any defective module removed (10), where it will be parked awaiting subsequent removal to the surface for repair.

Such coated parking holes 61 and 62 are located equidistant from the pumping modules in operation. In case of failure of any of the pumping modules, only the activation of a boat with ROV and winch not shown in the picture is required for cable operation, where the faulty module (10) is disconnected and hoisted a few tens of meters. . The boat moves to the parking hole (62), depositing the faulty module (10) therein. The cable is then connected to the spare module (63) by lifting it a few dozen meters. The boat navigates back to the installation of the spare module (63) in its base of operation (30). The removed faulty module (10) provisionally parked in the bore (62) will subsequently be removed to the surface in a scheduled operation using more sophisticated vessels or even marine probes. By using this technique the production downtime of module 10 due to failure thereof is substantially reduced.

The concepts of the present invention, under certain conditions, contribute to the elimination or simplification of offshore production platforms, as they enable the flow of hydrocarbons at greater distances than currently practiced.

Although the present invention has been described with respect to some of its embodiments, it is obvious to one skilled in the art that various changes, combinations and modifications are possible without departing from the scope of the present invention, which is determined by the appended claims.

Claims (12)

1. Subsea hydrocarbon heating module, comprising a heating system (11) housed within said heating module (12) combined with a MOBO pump module (10), and wherein said heating (12) is located on top of said MOBO (10), the subsea module being adapted to direct oil production from one or more wells to a long distance or onshore UEP, Module according to Claim 1, characterized in that the heating module (12) is individually recovered and reinstalled by unlocking a connector (13); Module according to Claim 1, characterized in that the heating module (12) is recovered and reinstalled together with the MOBO (10) by unlocking a hydraulic connector (14); Module according to Claim 1, characterized in that the hydraulic flow of oil through the heating system (11) is adapted to cause the oil to first pass through the MOBO (10) and then to the system. heating (11). Module according to claim 1, characterized in that the hydraulic flow of oil through the heating system (11) is adapted to cause the oil to pass through the heating system (11) first and then to be directed to the oil. the MOBO (10), Module according to Claim 1, characterized in that a power cable (19} supplies the heating system (11). Module according to Claim 1, characterized in that a power cable (18) feeds the pumping module (10); Module according to Claim 1, characterized in that the pump module (10) is integrated with a heating system (11) located between a motor (17) and the pump suction (16). Module according to Claim 1, characterized in that the pumping module (10) and the heating system (11) are integrated with a manifestoid (40). A method for subsea storage and module replacement as defined in any one of claims 1 to 9, characterized in that it comprises 'for one or more wells (20), producer or injector' interconnected with a subsea pumping module (10); providing the seabed with at least two coated holes (61) and (62) so that a perfectly functioning spare module (63) is installed in the first hole (61) while the second hole (62) is available to receive (accommodate) any faulty module removed (10), where it will be parked awaiting subsequent removal to the surface for repair. Method according to claim 10, characterized in that the coated parking holes (61) and (62) are located equidistant from the pumping modules in operation. Method according to claim 10, characterized in that in case of failure of any of the pumping modules (10) the replacement procedure of said failed module comprises the steps of; a) drive a boat with ROV and winch for cable operation; b) disconnect the faulty module (10) and hoist it a few dozen meters; c) move the boat to the parking hole (62), depositing the faulty module (10) therein; d) connect the cable to the spare module (63) by lifting it a few tens of meters; and e) navigating the return boat to the spare module installation (63) on its operating base (30).