WO2021168525A1

WO2021168525A1 - System and method for offshore gas production with a single-phase flow to shore

Info

Publication number: WO2021168525A1
Application number: PCT/BR2021/050076
Authority: WO
Inventors: Roberto Rodrigues; Guilherme MIRANDA PATERNOST
Original assignee: Petróleo Brasileiro S.A. - Petrobras
Priority date: 2020-02-28
Filing date: 2021-02-19
Publication date: 2021-09-02
Also published as: BR102020004027A2

Abstract

The present invention relates to an undersea system for offshore gas production in deep water with separation and re-injection of the water produced into a shallow aquifer using a simplified injection well, and flow of the dry gas through a single gas line connected directly to the onshore production unit (subsea to shore), with no need for an offshore production unit, in order to reduce CAPEX and OPEX costs, increase flow rates and the recovery factor of an offshore gas field when compared to the production system without liquid separation. The dry gas preferably flows under its own pressure, with reduced risk of hydrate formation and lower quantities of inhibitor, with no need for higher flow rates to reduce the risk of slugging, it being possible to use greater diameters that reduce the back pressure at the heads of producers, increasing the volumes produced and the recovery factor. The invention also reduces the risk of hydrate formation in the gas line during stoppages by operating in a single-phase mode with close to 100% gas.

Description

"OFFSHORE GAS PRODUCTION SYSTEM AND METHOD SINGLE-PHASE DRAINAGE TO EARTH"

Field of Invention

[0001] The present invention is related to the production and guarantee of the flow of subsea gas wells in offshore fields far from the coast. More particularly, the present invention is related to a system and method for single-phase gas flow, which enables the use of a single larger diameter pipeline, reducing back pressure at the head of producing wells for the purpose of increasing production and the recovery factor of an offshore gas field.

Description of the State of the Art

[0002] To enable the economic production of offshore gas fields, in deep waters and far from the coast, arrangements of production systems without an offshore production unit (platform) have been sought. Such arrangements, called direct production to shore (subsea to shore), collect and combine the volumes produced from a group of subsea wells, flowing the total production through one or two pipelines. Usually the flow occurs without separating the liquid from the gas, presenting several limitations, such as: risk of hydrate, difficulty in dragging and eventual accumulation of liquid, which can generate instabilities and undesirable slugs for the separation and processing plant, located on land, in addition to to reduce the flow produced.

[0003] In the production of gas fields at sea, as the reservoirs are produced their pressure decreases, reducing the production potential and worsening the conditions for carrying liquids.

[0004] Along with gas, liquid is also produced, being a mixture of condensed hydrocarbons and water. In scenarios of dry gas reservoirs, that is, with a high percentage of methane, the amount of condensed hydrocarbons is minimal. However, the amount of water can be significant, reaching tens or hundreds of m ³ per day. [0005] To avoid large accumulation of liquid in gas pipelines with multiphase flow, higher flow velocities are used, with smaller diameters. Both the higher velocity and higher average fluid density due to the liquid cause higher back pressure at the wellhead, reducing produced volumes and the field's recovery factor.

[0006] To mitigate such limitations, sometimes two gas pipelines are used, which also add the advantage of facilitating the passage of a pig to remove these liquids accumulated in the line. However, in addition to the higher costs of installing two gas pipelines, there are production losses during the passage of the pigs, in addition to an imbalance between the amount of liquid drained in each pipeline.

[0007] A problem inherent to gas production at great depths concerns the risk of obstruction of pipelines by formation of hydrates, resulting from the direct contact of gas and water under conditions of high pressure and low temperature.

[0008] To circumvent such risks, hydrate inhibitors are usually used that require long-length piping to transport large volumes of inhibitor (MEG) to the injection points on the seabed. In the case of gas production, the use of MEG, which can be regenerated, stands out. Sometimes methanol and ethanol can also be used, but without regeneration.

[0009] Usually, the order of magnitude of volume of inhibitor required is in the ratio of 1 to 1, that is, for each liter of water, a liter of inhibitor is needed. This increases the liquid volume of the pipeline's multiphase flow, increasing the risks of liquid accumulation and slugs and consequently the frequency of pig passage.

[0010] Some studies of the production of gas fields in deep waters, with high gas and liquid ratios, have suggested the use of in Une separators to separate the liquid from the gas. [0011] In this sense a new concept of technology has been proposed and developed, known as "pseudo dry gas Systems" very well described in the work OTC 28949 "Long Gas Tiebacks - Pseudo Dry Gas Systems". This concept uses gas-liquid separators when along the pipeline (in Une), where the separated liquid is collected and drained, in a pipeline parallel to the pipeline, to the onshore production unit.

[0012] Despite the merits of such systems, they have some limitations such as: they need a parallel line along the entire pipeline, the use of a set of separators, a long-length line to transport large volumes of inhibitor ( MEG), in addition to a pump to drain the liquid.

[0013] In this way, there is still great interest in developing innovative solutions that mitigate the risks of hydrates, which enable the single-phase flow through a single large diameter pipeline to reduce the back pressure at the wellhead, and which dispenses with the use of large volumes of hydrate inhibitors without compromising the robustness of the design. [0014] It should be noted that the single-phase flow is less sensitive to the relief of the seabed, since unevennesses of elevation along the path will not be points of accumulation of liquid, generating instabilities, back pressures and risks of large slugs that can destabilize the unit of terrestrial production.

[0015] The multiphase flow demands an ascending pipe, avoiding low points (valleys) in the route, which can accumulate large amounts of liquid, generating head losses, instability and slugs.

[0016] Document W02005088071 A1 refers to the recovery of helium or methane gas, which is mixed with water at the bottom of the sea or ocean and, in particular, to a procedure and apparatus for its extraction, where in a The first operation is the rise, from the seabed, of a mixture of methane gas and water to a process unit at sea level. Then, due to the pressure reducing action of the mixture, as well as the increase in temperature, the separation of gas from sea water is obtained. Subsequently, the suction of free gas from the upper side of the process unit takes place, and finally, the suction of water and its discharge back into the sea takes place. The document also shows that the gas/liquid separation compartment can be at sea or on land. The in-water separation site is only effective when there is a greater distance from the coast, as an intermediate compression station between the separation and the shore is required. The mixture is collected and sent to a submerged separation platform, with subsequent delivery of the gas to the onshore production unit and discharge of water from the platform directly into the sea, unlike the invention that injects the water into a shallow aquifer. Although the document also deals with a gas/water separation process pumping to the onshore unit, it uses an intermediate compression station between the separation site and the onshore unit, unlike the present invention, which uses a direct connection.

[0017] The document US20170037720A1 discloses a system and method of processing natural gas, produced from a subsea well. The system includes subsea processing to receive natural gas, separate free and condensable liquids comprising water and optionally liquid hydrocarbons, and produce a single-phase dry gas. It has a subsea processing unit that receives natural gas from the well, separating free and condensable liquids, compressing water and optionally, liquid hydrocarbons and producing a single-phase gas. The fluids are then transported by risers to a surface production facility with a processing system located therein to process the separated free and condensable liquids in the subsea system. A pipeline then transports the single-phase gas to the onshore production unit. The single-phase dry gas produced in the subsea processing system is transported to an onshore production facility via a subsea pipeline. The subsea system operates at high pressure and the surface system operates at low pressure. Hydrocarbon liquids processed in surface production facilities can be combined with single-phase dry gas to produce a dense dry phase for transport through the subsea pipeline. The document also makes reference to a method of managing hydrates and corrosion in a subsea production system. Unlike the invention that uses the fluid pressure itself to reduce the risk of hydrate and slugs, the document reveals the use of high pressure in the subsea processing system in addition to not sending the gas directly to the onshore unit.

[0018] The document WO2015048186A1 discloses an automated system to extract gas from an underground aquifer and methods such as gas/liquid separation and reinjection of the liquid into an aquifer. The system consists of compressors, filtration units, sensors to measure parameters and flow controllers that regulate the flow of gas and liquid and coordinate the operation of the system to produce gas and introduce the fluid or fluid vapor into an aquifer. The process consists of producing gas, performing gas/liquid separation, conditioning the gas in a container for a period of time that allows the gas to separate from the liquid, gas compression, distribution, fluid treatment and injection of the fluid into an aquifer. Maintaining the fluid in an anaerobic state is desirable to prevent the growth of bacteria in the fluid during processing to prevent the introduction of algae and bacteria into the aquifer when the fluid is reintroduced into the aquifer. Despite showing that there is injection of fluid into an aquifer after separation occurs, it is not possible to verify in the document the flow of gas directly to an onshore production unit. Furthermore, the document discloses a storage tank for gas/liquid separation, which differs from the invention that uses a subsea separator with a depressurization system. [0019] As will be further detailed below, the present invention aims to solve the problems of the prior art described above, in a practical and efficient way.

Brief Description of the Invention

[0020] The present invention deals with a subsea offshore gas production system, in deep waters, with separation and reinjection of produced water into a reservoir, for example a shallow aquifer, through a simplified injection well or with well exploitation dry exploration, without a production column and flow of dry gas through a single pipeline, directly interconnected with the onshore production unit (subsea to shore), without the need for an offshore production unit, in order to reduce CAPEX and OPEX, to increase the flow rate and the recovery factor of an offshore gas field, compared to a production system without liquid separation. The dry gas preferentially flows with its own pressure, with less risk of hydrate and a smaller amount of inhibitor, without the need for higher flow velocities to reduce the risk of slugs, and it is possible to use larger diameters that reduce the back pressure at the head of the producing wells, increasing the volumes produced and the recovery factor. The invention also provides a reduction in the risk of hydrate in the pipeline during shutdowns by operating in a single-phase regime with almost 100% gas.

Goals

[0021] The present invention aims to provide a gas flow system based on a single pipeline, with liquid phase separation using a single separation train and injection of the same preferably into a shallow aquifer through a disposal well.

[0022] The present invention aims to dispose of liquid in a shallow aquifer through a simple disposal well.

[0023] The present invention aims to prevent contaminants from being released to the bottom of the sea. [0024] The present invention aims to flow the dry gas through a single pipeline, directly interconnected with the onshore production unit, without the need for an offshore production unit.

[0025] The present invention aims to reduce CAPEX and OPEX costs.

[0026] The present invention aims to increase the flow rates and the recovery factor of an offshore gas field, if compared to the production system without liquid separation.

[0027] The present invention aims to provide operational methods for producing gas by a single pipeline, safely, minimizing hydrate risks.

[0028] These and other objectives will be achieved by the object of the present invention.

Brief Description of Drawings

[0029] The present invention will be described in more detail below, with reference to the attached figures which, in a schematic and not limiting of the inventive scope, represent examples thereof. In the drawings, there are:

- Figure 1 schematically illustrating a gas production system according to a first embodiment of the present invention, comprising a set of gas producing wells coupled to a single injection line;

- Figure 2 illustrating a hydrate dissolution system integrated to the gas liquid subsea separator;

- Figure 3 illustrating an embodiment where the separated liquid is drained to the onshore production unit;

- Figure 4 illustrating an embodiment where the separated liquid is stored in a monobuoy;

- Figure 5 schematically illustrates an embodiment where the separator is a vessel for gravitational separation and the injection pump is mounted on a skid. Detailed Description of the Invention

[0030] Preliminarily, it should be noted that the description that follows will depart from preferred embodiments of the invention. As will be apparent to anyone skilled in the art, however, the invention is not limited to these particular embodiments.

[0031] In a first embodiment of the present invention, illustrated in the schematic view of figure 1, one or more gas wells (Pg1) (Pg2) are interconnected through production lines (9, 10), to a liquid separator of gas (2), eg a VASPS type separator, Vertical Annular Separation and Pumping System, or another type of gravity separator. The separated liquid, composed mainly of produced water, is admitted by the pump (3) through the piping (11) and injected into an injection well (Pi) through the discharge piping (14). The dry gas taken from the top of the separator (2) is sent through the pipeline (1) to a production unit (5) located on land. One of the lines integrated in the structure of an electrohydraulic control umbilical (8), IPU - Integrated Production Umbilical, injects pig gel through an injection system (4) of pig gel in the pipeline (1). To facilitate understanding, the elements are also illustrated: surface compressor (6) and land pipeline (7) and sea surface (19).

[0032] A scraper (pig), rigid or gel, can be used periodically to give greater assurance that any liquid is removed from the pipeline. [0033] Optionally, a cartridge-type pig underwater launcher (13) can be added to the system giving greater robustness and operational flexibility.

[0034] Optionally, the water may, instead of being injected into the injector well (Pi), be drained to the seabed or to a reservoir or even to a shallow aquifer (15), however this procedure requires approval of competent environmental agency.

[0035] Figure 2 illustrates an optional embodiment where a wet gas compressor (20) can be used for eventual depressurization of lines and subsea equipment to mitigate hydrates. The compressor depressurizes the separator through the compressor suction line (21). All fluid removed is injected into the waste pit (Pi) through the compressor discharge line (22). Several shut-off valves (24) allow you to select which piping will be depressurized.

[0036] Optionally, one or more interfaces similar to the depressurization interface (23) for connection with depressurization tools operated by ROV, allow additional depressurizations and contingencies through service vessels, providing greater robustness to the system. [0037] Figure 3 illustrates an embodiment where the separated liquid is pumped and drained to the onshore production unit (5) through a long pipe (10a) of smaller diameter, with likely parallel to the pipeline (1).

[0038] Figure 4 illustrates an embodiment where the separated liquid is stored in a monobuoy (16). The elements are still indicated: mooring lines (17) of the monobuoy (16) and offloading and relief vessel (18). Optionally, the monobuoy (16) can also host renewable energy generation systems, such as wind turbine (26) and solar panels (27). Although not illustrated in the figures, the monobuoy (16) can also host other utilities such as: gas power generation, remote control system, etc. [0039] Figure 5 schematically illustrates an embodiment where the separator (2) is a vessel for gravitational separation and the injection pump (3) is mounted on a Skid (25). Optionally, it is possible to connect a subsea compressor (28) at the separator outlet (2), in order to reduce the back pressure at the wellhead and also to send the gas to more distant places, tens and even hundreds of kilometers.

[0040] The present invention further provides a method for Offshore gas production with reduction of back pressure at the head of producer wells, comprising the steps of:

- Produce one or more gas wells; - Collect and gather the volumes produced;

- Separate the liquid from the gas;

- Reinject the liquid produced;

- Mix hydrate inhibitor to the gas flow;

- Single-phase flow of gas through a pipeline;

- Receive and process the gas on land;

- Compress the treated gas;

- Flow the treated gas through a land pipeline for consumption. [0041] Optionally and in addition, the method of the present invention comprises the additional step of periodically pigging to remove any liquid accumulated in the pipeline, measuring the volumes of liquid removed in pigging operations, optimizing the frequency of pig passage, injecting inhibitor of hydrate at the ends of the subsea pipeline, inject hydrate inhibitor into the production lines and Christmas trees of each well.

[0042] Therefore, it is noteworthy that numerous technical advantages are obtained through the present invention, since it: a. It provides a subsea gas production system in deep waters, with separation and reinjection of produced water, and dry gas flow through a single pipeline (1) directly interconnected with an onshore production unit (5); in order to increase the flow and recovery factor of the reservoir compared to a production system without liquid separation; and b. It provides a more robust flow method, by reducing the risk of hydrate in the pipeline (1), facilitating the depressurization of the lines and reducing the need for pig passage, significantly reducing production losses and consumption of a hydrate-inhibiting product; ç. It provides a gas production system with a gas-liquid separation system with the additional function of dissolving the hydrate remotely in subsea pipelines, equipment and pipeline, without the need to mobilize a vessel or offshore probe; and d. It provides a gas production system directly to land with a single pipeline (1), without the need for an offshore production unit, significantly reducing the complexity of offshore installations resulting in a reduction in construction, installation, operation and maintenance costs (CAPEX and OPEX ); and is. It allows an operation with less risk to the environment, since the water produced is reinjected, reducing the consumption of hydrate inhibiting chemicals; and f. Mitigates hydrate risks in the pipeline (1) during stoppages as it operates in a single-phase regime, with almost 100% gas; and g. It does not present technological obstacles with regard to the equipment used, since the system according to the present invention comprises the integration of components and established technologies.

[0043] Numerous variations focusing on the scope of protection of this application are permitted. Thus, it is reinforced the fact that the present invention is not limited to the particular configurations and embodiments described above.

Claims

1- OFFSHORE GAS PRODUCTION SYSTEM SINGLE-PHASE DRAINED TO EARTH, characterized by comprising: at least one gas well (Pg1/Pg2); and a gas/liquid separator (2); and an injection pump (3) of produced liquid; and a discharge well (Pi) connected to a reservoir or a shallow aquifer (15); and a pipeline (1) with single-phase flow.

2- DRAINAGE OFFSHORE GAS PRODUCTION SYSTEM

SINGLE-PHASE FOR EARTH, according to claim 1, characterized in that the separator (2) performs the separation between gas and liquid, where the gas will be sent to a pipeline (1) and the liquid sent to a disposal well (Pi) and injected in a reservoir (15) through an injection pump (3).

3- DRAINAGE OFFSHORE GAS PRODUCTION SYSTEM

SINGLE-PHASE FOR GROUND, according to claim 2, characterized in that the dry gas removed from the top of the separator (2) is sent through the pipeline (1) to a production unit (5) located on land.

4- SUBSEA GAS PRODUCTION SYSTEM, according to claim 1, characterized in that it optionally comprises an electrohydraulic umbilical (8), equipped with a rigid steel pipe, for injecting pig gel into the pipeline (1).

5- DRAINAGE OFFSHORE GAS PRODUCTION SYSTEM

SINGLE-PHASE FOR EARTH, according to claim 1, characterized in that it comprises a hydrate dissolution system integrated to the gas/liquid separator (2).

6- DRAINAGE OFFSHORE GAS PRODUCTION SYSTEM

SINGLE-PHASE FOR EARTH, according to claim 1, characterized in that it optionally comprises a cartridge-type pig launcher (13). 7- DRAINAGE OFFSHORE GAS PRODUCTION SYSTEM

SINGLE-PHASE FOR GROUND, according to claim 1, characterized in that the liquid coming from the separator (2) is pumped to a production unit on land (5) through the long pipe (10a).

8- DRAINAGE OFFSHORE GAS PRODUCTION METHOD

SINGLE-PHASE FOR EARTH, using the system as defined in claim 1, said method characterized by comprising the steps of: a - Producing one or more gas wells; b - Collect and measure the volumes produced; c - Separate the liquid from the gas; d - Reinject the liquid produced; and - Mixing hydrate inhibitor to the gas flow; f - Single-phase flow of gas through a pipeline; g - Receive and process the gas on land; h - Compress the treated gas; i - Flow the treated gas through a land pipeline for consumption.

9- DRAINAGE OFFSHORE GAS PRODUCTION METHOD

SINGLE-PHASE FOR EARTH, according to claim 8, characterized in that it optionally comprises the additional steps: a) A scraper (pig), rigid or gel, is periodically launched to remove the liquid from the pipeline (1); b) measure the volumes of liquid removed in the pigging operations; c) optimize the pig pass frequency; d) Inject hydrate inhibitor at the ends of the subsea pipeline; e) Inject hydrate inhibitor in the production lines (9, 10) and Christmas trees of each well.

10- DRAINAGE OFFSHORE GAS PRODUCTION METHOD

SINGLE-PHASE FOR GROUND, according to claim 8, characterized in that the liquid coming from the separator (2) is pumped to a monobuoy (16) equipped with storage capacity for the produced liquid collected periodically for an offloading and relief vessel (18).