Underwater oil production. Innovative technologies for underwater hydrocarbon production on the Arctic shelf

The subsea production complex consists of several wells equipped with subsea X-mas tree, control system, gas collection pipelines, all located on the seabed. Gas from the wells is supplied to the manifold (a collection point of sorts) and then delivered to the shore via the main gas pipeline to the complex gas treatment plant.

Subsea production equipment, located at the bottom of the Sea of ​​Okhotsk without platforms and other surface structures, makes it possible to produce gas under ice, in difficult climatic conditions, excluding the influence natural phenomena. This avoids many of the risks inherent in working in adverse natural and climatic conditions.

Similar technologies have already been used in other countries, for example, in Norway at the Snøvit and Ormen Lange fields, but in Russia they will be applied for the first time at the Kirinskoye field. Subsea production technologies are reliable and allow industrial activities to be carried out with minimal negative impact on the ecological system of the region.

wellhead equipment

The field development project provides for 7 wells. Subsea X-mas tree type "Christmas tree" allows you to control the flow of gas from the well. The anti-trawl protective structure protects the X-mas tree from mechanical impact.

Weight with protection	141 t
Dimensions	23x23x10 m

Manifold

The gas from the wells goes to the manifold (collection point). The device consists of several pipelines fixed on one base, designed for high pressure and connected according to a certain scheme. The manifold distributes gas, monoethylene glycol (MEG), chemicals, and subsea control signals.

Tee

The pipeline tee is designed to connect medium wells to a line that is connected to a manifold.

terminal device

The terminal device of the pipeline is designed to connect the extreme wells under water to a line that is connected to the manifold.

Monoethylene glycol (MEG) pipeline

The pipeline from the GTP to the manifold is supplied with monoethylene glycol, which is necessary to prevent crystallization. From the manifold, MEG is fed into the well through an infield umbilical.

Hose cable

The main umbilical is laid along the seabed and connects the manifold to the control platform of the subsea production complex. The umbilical transmits control commands from the control room to the subsea equipment of the field.

Infield umbilicals connect the manifold to the wellhead X-mas tree.

gas pipeline

The gas pipeline connects the field and the integrated gas treatment unit (GTP). Through it, the reservoir mixture of gas, condensate and water is supplied from the field to the GTP.

Underwater Robot ROV

Performs underwater installation of equipment. It has 2 manipulator arms and has a position stabilization system.

The invention relates to the oil and gas industry, in particular to facilities for offshore hydrocarbon fields, mainly located on the continental shelf. The device comprises a drilling rig with a drive, a platform deck, a crane, a tender rig, reinforced concrete piles, a wellbore, a set of equipment installed on a platform for collecting, treating and transporting oil and gas, risers, point moorings and a supporting structure of a hydraulic engineering reinforced concrete structure. buried deep in the reservoir. Two of the reinforced concrete piles are made hollow inside and connected in the lower part by an arcuate bridge having an inner diameter commensurate with the inner diameters of the first and second reinforced concrete piles. The first pile is provided below sea level, at the installation site of the offshore fixed platform, with water intake openings. The inner walls of the first hollow reinforced concrete pile are provided with guides made in the form of a triangle and located in the axial direction towards the bottom of the reservoir. At the junction of the first hollow reinforced concrete pile with the ground, a hydraulic unit blade is installed, which is installed in a waterproof container on the foundation slab and adjacent to the first reinforced concrete pile. The second pile in the upper part is provided with a hole located at a mark above sea level, the diameter of the inner surface of which decreases towards the drain. The reliability of the operation of the offshore platform is increased. 3 ill.

The invention relates to the oil and gas industry, and more specifically to facilities for offshore hydrocarbon fields, mainly located on the continental shelf of the Arctic Ocean.

In accordance with the new Rules for the classification, construction and equipment of floating oil and gas complexes, including the rules for the construction and equipment of underwater production complexes (see, for example, N. Reshetov. The Arctic dictates the rules // Marine Business of the North-West. 2009, No. 1 (14) , p.43), facilities for offshore hydrocarbon fields are not only floating drilling rigs, offshore fixed platforms, offshore ice-resistant fixed platforms, but also offshore underwater pipelines, underwater production facilities, risers, point berths for offloading hydrocarbons, as well as floating facilities, carrying out the preparation, processing, storage and shipment of hydrocarbon products.

The main type of offshore platforms for oil and gas production are platforms made in the form of a structure consisting of one or more reinforced concrete shells buried deep into the reservoir (see, for example, R.I. Vyakhirev, B.A. Nikitin, D.A. Mirzoev, Construction and development of offshore oil and gas fields, Moscow, Academy of Mining Sciences, 1999, p.122.

The construction of such structures is carried out both from the ice cover and from the surface of the water. Such structures are used for the development of the continental shelf.

The following designs of offshore platforms are known: semi-submersible floating drilling rig "Uralmash 6000/200", self-elevating ice-resistant floating drilling rig SPBU 6500/10-30, two-support structure of a hydraulic reinforced concrete structure buried deep into the reservoir, gravity reinforced concrete platform, artificial island structure with concrete strengthening of slopes , an artificial island structure with gentle unreinforced slopes , an artificial island structure with a metal cylindrical frame .

Offshore platforms are used (depending on the location of the field) at depths of 6-35, 35-60, 100, 150, 200-250, 260-350 m (Shtokman field). Abroad at depths up to 300-600 m.

Distances from the offshore field to the coast also have different lengths. The main underwater pipeline from the Shtokman field has a length of 635 km to the coast of the Kola Peninsula.

When developing oil and gas deposits located under the seabed, the peculiarities of natural-climatic, hydrological and mining-geological conditions are taken into account in connection with the need to choose a method for their development and the corresponding type of offshore fishing.

Hydrometeorological factors are the main ones when choosing the type of offshore oil and gas facility (OOGS). One of the main factors in choosing the type of ice-resistant structures is the ice regime, which is characterized by a set of parameters (thickness, porosity, salinity, speed and area of ​​ice formations, etc.).

To determine the design of the surface part of the MNGS, information is needed on the possibility of its icing in order to provide for measures to combat this phenomenon in the project.

These circumstances require a reliable power supply of the MNGS.

The power supply of the oil and gas treatment complex is carried out by a centralized supply of electricity through an underwater cable or power line or using an autonomous power plant installed on a stationary offshore platform.

When using autonomous power sources, gas is used as fuel, and liquid fuel is used only as a backup.

In the climatic conditions of the Arctic Ocean and remoteness from stationary industrial energy sources, the problem of providing the power necessary at face value cannot always be provided, which forces the use of a significant number of autonomous power plants operating on different principles (diesel generators, etc.).

The objective of this technical proposal is to improve the reliability of MNGS operation by providing power supply to MNGS located on the continental shelf, mainly in hard-to-reach regions.

The problem is solved due to the fact that the offshore stationary platform, consisting of a drilling rig with a drive, a platform deck, a crane, a tender installation, reinforced concrete piles, a wellbore, a power supply device, a set of equipment installed on the platform for collecting, preparing and transporting oil and gas, including facilities for offshore hydrocarbon field development: an offshore underwater pipeline, an underwater production complex, risers, point berths for offloading hydrocarbons - and representing a supporting structure of a hydraulic reinforced concrete structure buried deep into a reservoir, differs from the prototype in that two of the reinforced concrete piles are made hollow inside and connected in the lower part to each other by an arc-shaped jumper having an inner diameter commensurate with the inner diameters of the first and second reinforced concrete piles, the first reinforced concrete pile is provided below sea level, at the installation site of the marine stationary platform, water intake openings, while the inner walls of the first hollow reinforced concrete pile are provided with guides made in the form of a triangle and located in the axial direction towards the bottom of the reservoir, at the junction of the first hollow reinforced concrete pile with the ground, the impeller of the hydraulic unit is installed, which is installed in a waterproof container on the foundation slab and adjacent to the first reinforced concrete pile, the second hollow pile in the upper part is provided with a hole located at a mark above sea level, the diameter of the inner surface of which decreases towards the drain.

The differences of the proposed technical solution are that two of the reinforced concrete piles are made hollow inside and connected in the lower part to each other by an arcuate jumper having an inner diameter commensurate with the inner diameters of the first and second reinforced concrete piles, the first reinforced concrete pile is provided below sea level, in place installation of an offshore stationary platform, water intake holes, while the inner walls of the first hollow reinforced concrete pile are equipped with guides made in the form of a triangle and located in the axial direction towards the bottom of the reservoir, at the junction of the first hollow reinforced concrete pile with the ground, a hydraulic unit impeller is installed, which is installed in waterproof container on the foundation slab and adjacent to the first reinforced concrete pile, the second hollow pile in the upper part is provided with a hole located at a mark above sea level, the diameter of the inner surface of which decreases towards the drain.

The set of distinguishing features of the proposed technical solution makes it possible to provide MNGS with a stable autonomous power supply in hard-to-reach regions.

The essence of the invention is illustrated by drawings.

Fig.1. General form MNGS. MNGS consists of an offshore fixed platform, which includes a drilling rig with a drive 1, a platform deck 2, a crane 3, a tender rig 4, an ice field 5, reinforced concrete piles 6, a wellbore 7. The MNGS also includes power supply devices, a set of equipment installed on platform for collection, preparation and transportation of hydrocarbons, offshore underwater pipeline, underwater production complex, risers, point moorings for offloading hydrocarbons.

Fig.2. Pile construction. Two reinforced concrete piles 6 are made hollow inside, pile 8 and pile 9, and are connected in the lower part between each other by an arcuate jumper 10, having an inner diameter commensurate with the inner diameters of the first 8 and second 9 reinforced concrete piles, the first reinforced concrete pile 8 is provided with water intakes below sea level. holes 11 and 12, while the inner walls of the hollow reinforced concrete pile 8 are provided with guides 13, made in the form of a triangle, located in the axial direction towards the bottom of the reservoir 14, at the junction of the first hollow reinforced concrete pile 8 with the soil of the bottom of the reservoir 14, a turbine impeller is installed 15 of the hydraulic unit 16 installed on the foundation slab 17 of the waterproof container 18 adjacent to the reinforced concrete pile 8. The second hollow reinforced concrete pile 9 is provided with a hole 19 in the upper part, located above sea level 20 or ice field 5. The inner diameter of the reinforced concrete pile 9 decreases to the side plum.

Fig.3. Structural scheme hydraulic unit 16. Structural diagram of the hydraulic unit 16 includes: turbine impeller 15, guide vanes 21, turbine bearing 22, jack brakes 23, generator stator 24, generator rotor 25, generator bearing and thrust bearing baths 26 and 27, respectively, generator bearing 28, thrust bearing segments 29, thrust bearing mirror 30, turbine oil line 31, process water line 32, distilled water tank 33, oil pressure unit 34, high pressure air supply line 35, air line low pressure 36.

The hydraulic unit 16 is a hydro generator made in the form of a horizontal capsule hydro generator, the analogue of which is the hydro generators described in the sources of information: 1. Patent of the Russian Federation No. 228532. 2. Hydropower. Ed. V.I. Obrezkov. M., Energoizdat, 1988. - 512 p., p.301.

An analogue of the foundation plate 17 is the foundation plate given in the description of the patent of the Russian Federation No. 2261956.

The specific type of hydro generator is selected based on the depth of the reservoir.

The device works as follows.

Outboard water enters through the intake holes 11 and 12 into the cavity of the pile 8, where through the guides 14, made in the form of a triangle and located in the axial direction towards the bottom of the reservoir 14, the laminar flow is converted into a turbulent flow. The turbulent flow reaches the blades 21 of the guide apparatus, setting them in rotational motion, and accordingly the entire mechanical system of the hydraulic unit is started, and then the electrical system.

Further, the turbulent flow through the arcuate jumper 10 enters the second pile 9, in which the water flow, reaching the hole 19, merges onto the surface of the reservoir or enters the water supply system, articulated with the hole 19, which can be used to meet the technical needs of the MNGS.

When using the proposed technical solution, there is no need to build transmission lines in hard-to-reach areas, for example, in the Arctic region.

Sources of information

1. R. I. Vyakhirev, B. A. Nikitin, D. A. Mirzoev. Arrangement and development of offshore oil and gas fields. M., Academy of Mining Sciences. - 1999.

Claim

An offshore fixed platform for the production of hydrocarbons, consisting of a drilling rig with a drive, a platform deck, a crane, a tender rig, reinforced concrete piles, a wellbore, a power supply device, a set of equipment installed on the platform for collecting, treating and transporting oil and gas and including facilities offshore hydrocarbon field: an offshore underwater pipeline, an underwater production complex, risers, point berths for offloading hydrocarbons and representing a supporting structure of a hydraulic reinforced concrete structure buried deep into a reservoir, characterized in that two of the reinforced concrete piles are made hollow inside and are connected in the lower part between is an arcuate jumper having an inner diameter commensurate with the inner diameters of the first and second reinforced concrete piles, the first reinforced concrete pile is provided below sea level, at the installation site of the offshore stationary platform, with water intake holes pits, while the inner walls of the first hollow reinforced concrete pile are equipped with guides made in the form of a triangle and located in the axial direction towards the bottom of the reservoir, at the junction of the first hollow reinforced concrete pile with the ground, a hydraulic unit blade is installed, which is installed in a waterproof container on the foundation slab and adjacent to the first reinforced concrete pile, the second hollow pile in the upper part is provided with a hole located at a mark above sea level, the diameter of the inner surface of which decreases towards the drain.

The imposition of sanctions three years ago deprived Russian companies opportunities to use Western equipment and technologies for field development. This was an impetus for the domestic industry and the IT sector - Russia has its own unique developments that are already being tested. How import substitution is carried out in the fuel and energy complex, whether hacker attacks are terrible for the industry, why it is not worth laying pipes throughout the Russian Federation as part of the gasification program, said Deputy Energy Minister Kirill Molodtsov in an interview with RIA Novosti.

How is the work on import substitution of equipment for oil and gas industry, including for work on the shelf?

- IN last years there is a gradual reorientation of Russian oil and gas companies to place orders for domestic machine-building capacities.

For offshore production, we have identified about 20 priority tasks for the near future. Currently, domestic samples of shut-off valves intended for the transport of oil and gas are being actively introduced, equipment for drilling directional wells has been developed.

On the basis of prototypes that have already been created, we plan to provide oil production with Russian rotary-controlled systems by 2019, and oil refining with high-quality additives by 2022.

Speaking in detail, out of 600 elements that are somehow involved in offshore production from the bottom to the coast, about 300 need to be replaced. Of these 300, about 50 elements can be called especially critical.

To work on the creation of Russian samples of offshore equipment, a mechanism of research and development work (R&D) is provided. In the period 2017-2019, 2.7 billion rubles were allocated for the implementation of eight R&D, including in the field of underwater production complexes.

Thus, by 2021-2022 we can present a prototype of our own subsea production technologies. This is difficult, because such equipment is subject to increased requirements in terms of environmental and technological safety. But there are first successes, there are people who really deal with this issue and have every chance of achieving the desired result.

In addition, there are technologies related to geology. These are 2D, 3D seismic and others. Here, too, we are lagging behind to some extent, and perhaps not so much lagging behind as we think we are still lagging behind.

For example, in 2016, R&D began in a number of areas of exploration — projects on a gel-filled spit, positioning systems, bottom seismic stations, seismic streamers, unification of equipment for the drilling complex.

We will complete the implementation of most of these projects in 2017, but already now we can talk about the availability of equipment samples undergoing field tests.

- At the same time, many Russian companies prefer to use foreign technologies and equipment.

- If you look at the experience of, say, China, then in their internal waters on their shelf they carry out seismic exploration exclusively by Chinese companies. And we sometimes manage, in the presence of our own developments and our own ships, to attract the same Chinese companies, saying that it is cheaper.

- Is it correct?

- I don't think so. We need to evaluate what result we will achieve in the end.

For me, the creation of offshore production technologies is a higher priority than just increasing production volumes, which we can get in the coming years. Because technology is needed to solve strategic problems.

- How is the development and implementation of Russian software for the oil and gas industry going?

- Software in general is developing quite well, there are well-known brands. From an industry point of view, I would say that our colleagues, including us, are not improving to some extent.

For many, using an existing one is always easier and easier than switching to something new. Therefore, we need to reverse the situation when our users are afraid and do not want to switch to new products developed by Russian programmers.

To do this, it is necessary to constantly inform companies about what is happening, what is being done. For example, in the fall, the first event of its kind will be held - the Russian Energy Week, where the Russian Ministry of Energy tried to bring together all sectors of the fuel and energy complex: oil and gas, energy efficiency technologies, electric power, coal, innovation, and so on. about innovation, including software, we will talk live, discuss.

Recently, Rosneft, Bashneft and other companies around the world reported hacker attack. Does the Ministry of Energy plan to take any countermeasures to protect the industry?

— There are state doctrines of energy and information security. These documents will have to be supplemented and amended to reflect the new realities.

We will look at how the system should be localized and controlled autonomously. The main thing is to avoid consequences that may affect the provision of life. We know how to create autonomous control systems in shipbuilding, for example. Let's create it here too. Perhaps this will be due to the introduction of new technologies with autonomous control systems. Let's do this.

- Is there an assessment of the damage from the last attack?

Didn't notice any damage. In any case, we did not find a single change in the flow of information in the industry. Accordingly, all companies that somehow got into such circumstances, apparently, were ready for them, which characterizes them well. It turns out that they can predict the situation, which is important.

- Returning to the topic of the Arctic shelf, when can new hydrocarbon production projects appear?

- Gazprom and Rosneft are already working on the shelf, the emergence of new projects is a question economic efficiency. In terms of production, our companies are backed by reserves. Currently, hydrocarbon production on our shelf is not large, it does not exceed 5% of the total Russian production.

At the same time, the Arctic shelf contains presumably significant oil reserves - more than 15% of all Russian ones, so the potential of the region is very high. However, one must understand that the costs of developing Arctic waters are much higher than those of developing other offshore fields. And in this sense, for companies today, the shelf is more of a challenge than a need. But the funds that are currently being spent on the development of the shelf will definitely pay off in the medium term.

At the same time, the oilmen have obligations. They received licenses that are limited in terms. The state says: we have given you a shelf, please, develop it. So the work is progressing.

It can be stated that the development of the Arctic shelf deposits is carried out in accordance with license obligations, moreover, the plans of subsoil users are ahead of them. In April, drilling was launched on the shelf of the Laptev Sea within the Khatanga area. Also this year, exploratory drilling will continue in the waters of the Barents, Kara and Black Seas.

Now there is a lot of talk about the situation with the gasification of Russian regions. Still, is it possible to provide gas to all settlements in the country?

— Gasification of Russian regions is one of the most ambitious activities of the Ministry of Energy in the domestic market. From 2005 to 2016, the level of gasification in the country increased from 53.3% to 67.2%. Over the past 12 years, Gazprom has built about 2.5 thousand inter-settlement gas pipelines with a length of more than 28 thousand kilometers.

Conditions have been created for gasification of more than 3.7 thousand settlements (an average of about 300 settlements annually) and 5 thousand boiler houses, as well as about 815 thousand households and apartments.

At the same time, laying pipes everywhere is illogical. In my understanding, approximately 15% of settlements may have difficulties with pipeline gas for several reasons.

For example, in our country there are several thousand settlements with less than ten people. By no means do I want to say that such settlements will remain without gas. Gas is our asset, which we must first of all use to create our own favorable living conditions. Therefore, settlements should be gasified either with pipeline gas or with the help of alternative sources. To create the conditions for this is our task.

I would like to remind you that until 2020, and maybe a little further, for example, until the creation of the EurAsEC single gas market, there will be state regulation of gas prices. But at the same time, there is a price for an alternative gas - LPG (liquefied hydrocarbon gas - ed.), which should also be supplied to the population. It is possible to derive the cost of a unit of calorific value for the needs of the population and, accordingly, to understand what obligations the state can take on in terms of providing the population with this gas. This is the problem we are trying to solve now.

We have our own initiative, although some of our colleagues call it an anachronism, the legislative regulation of the task for LPG producers to supply gas to the population for domestic needs. The draft law has already been discussed, including public discussion. Moreover, it seems to me that even the Ministry of Economic Development has heard our position that our task is, first of all, to provide the population with gas, and it does not matter whether pipeline, liquefied, compressed or LPG.

What is the situation with the gas transportation tariff for independent producers? FAS removed this issue from the agenda for the board meeting. Is it possible that this tariff will not be indexed for the second year in a row?

- The Ministry of Energy proposed an approach to the upper limit of indexation, then - the decision of the government.

- Did the Ministry of Energy instruct Gazprom to work out the possibility for Rosneft to export gas?

- We received the order of the President. The position of the Ministry of Energy was prepared and reported. I have not yet seen an updated request from Rosneft.

- What are the main tasks of the Ministry of Energy in the oil and gas industry for the second half of 2017?

— Completion of work on the preparation of two master schemes for the development of the oil and gas industries for the period up to 2035.

B common system for oil and gas production in offshore oil and gas fields usually includes the following items:

one or more platforms from which production wells are drilled,

· pipelines connecting the platform to the shore;

Onshore installations for processing and storage of oil,

loading devices

A drilling rig is a complex technical structure designed for offshore oil and gas production.

Coastal deposits often continue on the part of the mainland located under water, which is called the shelf. Its borders are the coast and the so-called edge - a clearly defined ledge, beyond which the depth rapidly increases. Usually the depth of the sea above the crest is 100-200 meters, but sometimes it reaches up to 500 meters, and even up to one and a half kilometers, for example, in the southern part of the Sea of ​​\u200b\u200bOkhotsk or off the coast of New Zealand. Different technologies are used depending on the depth. In shallow water, fortified "islands" are usually built, from which drilling is carried out. This is how oil has long been extracted from the Caspian fields in the Baku region. The use of such a method, especially in cold waters, is often associated with the risk of damage to oil-producing "islands" by floating ice. For example, in 1953, a large ice mass that broke away from the shore destroyed about half of the oil wells in the Caspian Sea. Less commonly used technology is when the desired area is edged with dams and water is pumped out of the resulting pit. At a sea depth of up to 30 meters, concrete and metal overpasses were previously built, on which equipment was placed. The flyover was connected to the land or was an artificial island. Subsequently, this technology has lost its relevance.

If the field is located close to land, it makes sense to drill an inclined well from the shore. One of the most interesting modern developments is remote control of horizontal drilling. Specialists control the passage of the well from the shore. The accuracy of the process is so high that you can get to the desired point from a distance of several kilometers. In February 2008, Exxon Mobil Corporation set a world record for drilling such wells as part of the Sakhalin-1 project. The length of the wellbore here was 11,680 meters. Drilling was carried out first in a vertical and then in a horizontal direction under the seabed at the Chayvo field, 8-11 kilometers from the coast. The deeper the water, the more sophisticated technologies are applied. At depths up to 40 meters, stationary platforms are built (Fig. 4), but if the depth reaches 80 meters, floating drilling rigs (Fig. 4) equipped with supports are used. Up to 150-200 meters, semi-submersible platforms operate (Fig. 4.5), which are held in place with anchors or a complex dynamic stabilization system. And drilling ships are subject to drilling at much greater sea depths. Most of the "wells-record holders" were carried out in the Gulf of Mexico - more than 15 wells were drilled at a depth exceeding one and a half kilometers. The absolute record for deep water drilling was set in 2004 when Transocean and ChevronTexaco's Discoverer Deel Seas drillship began drilling a well in the Gulf of Mexico (Alaminos Canyon Block 951) at a sea depth of 3,053 meters.

In the northern seas, which are characterized by difficult conditions, stationary platforms are often built, which are held at the bottom due to the huge mass of the base. Hollow "pillars" rise up from the base, in which the extracted oil or equipment can be stored. First, the structure is towed to its destination, flooded, and then, right into the sea, the upper part is built on. The plant on which such structures are built is comparable in area to a small city. Drilling rigs on large modern platforms can be moved to drill as many wells as needed. The task of the designers of such platforms is to install the maximum of high-tech equipment in the minimum area, which makes this task similar to designing a spaceship. To cope with frost, ice, high waves, drilling equipment can be installed right on the bottom. The development of these technologies is extremely important for countries with a vast continental shelf.

Interesting facts The Norwegian platform "Troll-A", a bright "representative" of the family of large northern platforms, reaches 472 m in height and weighs 656,000 tons. (Fig. 6)

The Americans consider 1896 to be the start date of the offshore oil field, and its pioneer is the oilman Williams from California, who drilled wells from the embankment he built.

In 1949, 42 km from the Absheron Peninsula, on the overpasses built to extract oil from the bottom of the Caspian Sea, a whole village called Oil Rocks was built. Employees of the enterprise lived in it for weeks. The Oil Rocks Trestle can be seen in one of the James Bond films - “The world is not enough.” The need to maintain the underwater equipment of drilling platforms significantly influenced the development of deep-sea diving equipment. To quickly shut down a well emergency- for example, if a storm prevents the drilling ship from staying in place, a kind of plug called a "preventer" is used. The length of such preventers reaches 18 m, and the weight is 150 tons. The beginning of the active development of the offshore shelf was facilitated by the global oil crisis that erupted in the 70s of the last century.

After the embargo was announced by the OPEC countries, there was an urgent need for alternative sources of oil supplies. The development of technologies also contributed to the development of the shelf, which by that time had reached such a level that would allow drilling at significant sea depths.

The Groningen gas field, discovered off the coast of Holland in 1959, not only became the starting point in the development of the North Sea shelf, but also gave the name to a new economic term. Economists called the Groningen effect (or Dutch disease) a significant appreciation of the national currency, which occurred as a result of an increase in gas exports and had a negative impact on other export-import industries.

Let us consider in more detail the technologies for drilling wells in water areas and the types of drilling rigs.

There are the following methods of drilling wells in water areas (Fig. 8):

1. from offshore fixed platforms;

2. gravity offshore stationary platforms;

3. Jack-up drilling rigs;

4. semi-submersible drilling rigs;

5. drilling ships.

An offshore fixed platform is a drilling base resting on the bottom of the water area and rising above sea level. Since at the end of the operation of the well, the MSP remains at the site of construction, the scheme for drilling an offshore well, in contrast to the scheme for constructing a land well, provides for the presence of a riser column that isolates the well from the water column and connects the underwater wellhead with the drilling site of the offshore stationary platform. Wellhead equipment (preventors, casing string heads, a device for draining flushing fluid from the well to the cleaning systems) is also mounted on the MSP.

Four or five tugs are required to tow the platform to the well site. Usually, other auxiliary vessels (port tractors, escort vessels, etc.) also participate in the towing of the MRP. In good weather, the average towing speed is 1.5 - 2.0 kt/h.

Gravity offshore fixed platform is a drilling base made of reinforced concrete and steel. It is built in deep-water bays and then delivered by tugboats to the point of drilling production and exploration wells. The GMSP is intended not only for drilling wells, but also for the extraction and storage of black gold before it is shipped by tankers to the place of processing. The platform has a large weight, so no additional devices are required to hold it at the drilling point.

After the development of the field, all wells are mothballed, the unit is disconnected from the wellheads, separated from the seabed and transported to a new point within the given area or to another region of drilling and oil and gas production. This is the advantage of the HMSP over the MSP, which, after the development of the field, remains in the sea forever.

A self-elevating floating drilling rig has a sufficient buoyancy margin, which is of great importance for its transportation to the drilling site along with drilling equipment, tools and the necessary supply of consumables. At the drilling site, with the help of special lifting mechanisms and supports, the jack-up rig is installed on the seabed. The body of the installation is raised above sea level to a height inaccessible to sea waves. In terms of the method of installing preventer devices and the method of connecting the drilling site with the underwater wellhead, the jack-up rig is similar to the MSP. To ensure the reliability of well operation, casing strings are suspended under the rotor table. Upon completion of drilling and after the development of the exploration well, liquidation bridges are installed and all casing strings are cut below sea level.

A semi-submersible floating drilling rig consists of a hull that includes the actual drilling platform with equipment and pontoons connected to the platform by stabilizing columns. In the working position at the drilling point, the pontoons are filled with the estimated amount of sea water and submerged to the estimated depth under water; in this case, the effect of waves on the platform is reduced. Since the SSDR is subject to rolling, it is impossible to rigidly connect it to the underwater wellhead using a riser (riser). Therefore, in order to prevent the destruction of the ligament of the mouth - SSBU, the riser column is provided with a telescopic connection with a sealing assembly and airtight swivel joints of the FOC. with a floating facility and subsea wellhead blowout prevention equipment The tightness of the moving elements of the riser string must ensure the isolation of the well from sea water and the safety of operations under acceptable operating conditions.

The MFDR is delivered to the drilling site by tugboats and kept on it by an anchor system during the entire period of drilling and well testing. Upon completion of its construction, the SSDR is removed from the drilling point and distilled to a new location

During the construction of deep offshore oil and gas wells, a drilling ship is used, on which all drilling and auxiliary equipment is mounted and the necessary supply of consumables is located. its speed reaches 13 knots / h (24 km / h). Above the drilling point, the vessel is held by dynamic system positioning, which includes five thrusters and two lead screws that are constantly in operation

BOP subsea equipment is installed on the seabed after the BS is placed at the drilling point, it is connected to the wellhead using a riser with a diverter, two swivel joints and a telescopic joint to compensate for vertical and horizontal movements of the drilling vessel during the well construction process.

The main factor influencing the choice of the type of floating drilling equipment is the depth of the sea at the drilling site. Until 1970, jack-up drilling rigs were used to drill wells at depths of 15--75 m, at present - up to 120 m or more. -300 m and more.

Drilling ships, due to their higher maneuverability and speed of movement, greater autonomy compared to the SSDR, are used when drilling prospecting and exploration wells in remote areas at water depths of up to 1500 m or more. The large stocks of consumables available on the vessels, designed for 100 days of operation of the unit, ensure successful drilling of wells, and the high speed of the vessel's movement ensures their quick relocation from a drilled well to a new point. In contrast to the MODU for the BS, there are large limitations in operation, depending on the sea state. Thus, when drilling, the heaving of drilling ships is allowed up to 3.6 m, and for the MODU - up to 5 m. 20--30% of the wave height. Thus, drilling of wells with MFDR is carried out at a significantly higher sea state than when drilling with BS. The disadvantages of a semi-submersible floating drilling rig include a low speed of movement from a drilled well to a new point. A new direction in underwater oil production is the creation of underwater production complexes (Fig. 9), which provide normal atmospheric conditions for the work of operators. Equipment and materials (cement, clay, pipes, aggregates, etc.) are delivered to drilling platforms by supply vessels. Decompression chambers are also installed on them and necessary equipment for diving and a number of auxiliary works. The produced oil is transported to the shore using offshore pipelines, which are laid on the high seas with the help of specialized pipe-laying vessels. Along with pipelines, systems with offshore berths are used. Oil is delivered to the berth through an underwater pipeline and then through flexible hoses or risers to tankers.

Explanations for Figure 9:

1 -- cable to control the drilling rig from the ship; 2 -- guide funnel for core pipes; 3 -- spotlight; 4 - moving underwater television installation; 5 -- hydraulic jacks for leveling the drilling base; 6 - a device for monitoring the installation of the drilling base horizontally; 7 -- power drive; 8 -- mud pump; 9 - shop with drill pipes; 10 -- Supply hose

The history of the development of underwater technologies in the world and on the Russian shelf is briefly considered. The seas of Russia are characterized by a long seasonal ice cover, which prevents continuous development these technologies or leads to the lack of their application. The main problem is related to ensuring the reliability of the application of subsea technologies, since maintenance and repair of subsea equipment in ice conditions is difficult and costly. The article proposes an algorithm for assessing the reliability of subsea technologies and defines the requirements for subsea equipment for use in Russia: design with duplication of standard components, proper testing and strict quality control during manufacture. The development of a new generation of subsea equipment for Russia should be aimed at improving the technologies for gas compression, treatment and disposal of formation waters, monitoring the state and control of production and transportation parameters of well products, carrying out technological operations by autonomous means, power supply, communications and control. The advantages of developing offshore fields with subsea wellheads are shown, the main of which is the sequential commissioning, which gives accelerated production. A three-stage methodology for the development and development of subsea fields is presented and the main factors are identified: minimization of drilling operations and financial costs, rational placement of equipment.

Keywords: offshore oil and gas production, underwater production complex, readiness of technologies, reliability, underwater oil and gas separation, compressor, condition monitoring.

UDC 622.323+324
D.V. Lyugai, Doctor of Technical Sciences, Gazprom VNIIGAZ LLC (Moscow, RF)
M.N. Mansurov, Doctor of Technical Sciences, Prof., Gazprom VNIIGAZ LLC, M_Mansurov@vniigaz.gazprom.ru

Literature:

API RP 17N Recommended Practice for Subsea Production System Reliability and Technical Risk Management [ Electronic resource]. Access mode: http://nd.gostinfo.ru/document/4523527.aspx

DNV-RP-A203 Recommended Practice. Technology Qualification [Electronic resource]. Access mode: http://rules.dnvgl.com/docs/pdf/DNV/codes/docs/2013-07/RP-A203.pdf (accessed 06/01/2018).

Mokshaev T.A., Grekov S.V. Application experience and prospects for the development of systems for underwater separation of oil and gas // Vesti gazovoy nauki: Nauch.-tekhn. Sat. 2015. No. 2 (22). pp. 69–73.

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Currently, oil and gas fields have been discovered on the Russian Arctic shelf and the shelf of the Far Eastern seas, where the combination of water depths and ice conditions does not allow the use of traditional hydrocarbon production technologies using fixed or floating platforms. Their development requires the creation of special underwater complexes. Nomenclature of underwater technical means, manufactured in the world and providing oil and gas production, is very wide. The article discusses the gaps and shortcomings in the development of such technologies in order to apply them in the specific conditions of the Russian shelf. They are mainly due to reliability and operations to ensure it: maintenance and repair of subsea equipment, since in ice conditions these operations are difficult and costly.

The first well with an underwater location of the mouth was drilled in 1943 on the lake. Erie (USA) at a sea depth of 11.5 m. In 1961, Cameron developed and manufactured the first industrial underwater Christmas tree for a well in the Gulf of Mexico. The main motive for the development of offshore oil production in the world was the oil crisis of the 1970s. because of the embargo imposed by the OPEC countries on the supply of "black gold" to Western countries. Such restrictions forced American and European oil companies to look for alternative sources of crude oil through the creation of new technologies that made it possible to drill offshore wells at great depths and the development of subsea hydrocarbon production technologies.

The first subsea production complex (SPM) control system was installed in 1963, and in 1979 a subsea system with multiplex electrohydraulic control appeared. Progress in developing MPCs during 1980–2015 was marked by the appearance of horizontal underwater X-mas trees, new control systems, including those with full electric drive.

Today, no more than 10 companies in the world produce subsea equipment for the production of hydrocarbons, but there are more than 130 offshore fields where technological processes are used for the production of hydrocarbons on the seabed. The geography of distribution of underwater production is extensive: the shelves of the North and Mediterranean seas, India, Southeast Asia, Australia, West Africa, North and South America. In Russia, the first production complexes were installed on the Sakhalin shelf in 2013 as part of the development of the Kirinskoye field.

FEATURES OF UNDERWATER DEVELOPMENT

The development of offshore fields with subsea wellheads, although quite complicated, has a number of advantages over traditional methods of surface equipment of wellheads. The main advantage lies in the possibility of putting the offshore field into operation in stages, which in practice leads to an accelerated receipt of the first production.

It is possible to drill several wells from a drilling ship, equip their mouths with appropriate underwater fittings and put them into operation much faster than installing an expensive stationary platform for drilling directional wells from it. In addition, the underwater development method makes it possible to identify some geological, physical and operational parameters of deposits at an earlier stage of development.

The general methodology for designing the development and construction of subsea fields essentially corresponds to the traditional schemes used for onshore and offshore fields with platform facilities. It includes three stages: analysis of the characteristics of the deposit and its operating conditions; substantiation of the principles/concepts for the development of deposits and the arrangement of the field, which vary depending on the region, the features of the organization of design, construction and operation of the field, etc.; analysis and optimization of technological processes, location of wells, field facilities, etc.

At the same time, a distinctive feature of the design of subsea fields is the identification and verification of the determining factors influencing the choice of design solutions. For example, it is known that low temperatures require the use of special materials for underwater structures, which increase their cost, but sea water temperatures at depths of more than 30–50 m are practically the same in all regions. Temperatures for transportation and storage of equipment in the Arctic are usually below –40…–50 °С. But is it necessary to transport and store, as well as test subsea systems at such extreme temperatures, increasing the cost of construction?

As part of the Arctic Development Roadmap project, key topics were identified and systematized, the solution of which, according to the authors of the project, is necessary for the development of oil and gas resources in the Arctic Ocean. According to this document, hydrocarbon transport technologies, seabed dredging and trenching, modeling and training are classified as significant factors influencing future development, and protection is classified as potentially unavoidable interference. environment. In our opinion, such assessments are not entirely convincing.

When choosing a field development solution, the determining factor is to minimize drilling operations and financial costs by optimizing the number and designs of wells, as well as the rational placement of equipment on the seabed. The functional requirements for installation and operation shall be verified, including transport, storage and testing conditions, as well as requirements for simultaneous operations (eg drilling and installation, drilling and production).

The advantage of a subsea wellhead system is the protection of all equipment installed at the bottom from external weather conditions. It is known that above-water fixed platforms pose a significant navigational hazard, while such a hazard is practically absent when equipment is installed underwater; the fire hazard is also eliminated.

At the same time, a significant disadvantage of systems with an underwater location of the mouth is the difficulty of access to wellhead equipment, especially in the presence of ice cover and the need for frequent repairs of wells. Thus, according to Statoil, one of the leaders in the field of underwater field development technologies, a comparison of statistical indicators of production efficiency for 2010-2012. during the platform and underwater development of the North Sea fields along the entire chain from the well to the platform showed that the operating efficiency of dry wells (on platforms) is 91.8%, and for subsea wells - 86.5%, i.e. the efficiency of the platform production at the fields is 5.3% higher.

Increased production losses in fields with MPC are mainly associated with risers and field pipelines, leading to unplanned production losses due to the need for repair and restoration services (3.7%). The statistics of unplanned production losses at MPC is shown in fig. one.

Obviously, for the seas of Russia, characterized by a long ice regime and the relative inaccessibility of wellheads during this period, the operating factor of subsea wells may be significantly lower.

APPLICATION OF NEW TECHNOLOGIES

When developing offshore fields and justifying layouts for subsea production equipment, it is very important to take into account the specific conditions of the region (for example, the Arctic) and identify the applicability of existing system solutions or identify gaps in the development / lack of technologies to provide design solutions.

There are two types of gaps in the development of technologies: concepts that can be improved by new technologies, but proven technologies exist; concepts that are completely dependent on new technologies, since such technologies do not exist.

The technology readiness level is determined according to API RP 17N (see table). As a rule, many oil and gas operators declare their readiness new technology for implementation in the fields upon completion of the TRL 4 and TRL 5 development stages.

The problem of ensuring reliability is one of the most important in the application of subsea technology, since the inspection of subsea equipment is difficult, and its maintenance and (or) replacement is costly. In addition, the failure of underwater equipment directly affects the state of the environment. Finally, subsea equipment must ensure the continuity of production and return on capital investment.

According to FMC Technologies, the reliability of new technologies can be assessed according to the scheme shown in Fig. 2, which is based on the methodology developed by the Norwegian Qualification Society (Det Norske Veritas) .

For the use of subsea technologies in icy seas, it is important to ensure that maintenance methods for subsea equipment components are acceptable for inspection, repair, or replacement.

In this regard, it is necessary to lay in the subsea systems the principle of partial redundancy, which would ensure reliability and be a guarantee of the continuity of production. Therefore, modular systems must be designed to duplicate standard components, properly tested, and manufactured under strict quality control.

In any system, there may be unique components intended only for a given field. They are not extracted and serve during the entire period of field development. In such a situation, two approaches are possible: to ensure high reliability of these components of the subsea system; design systems in such a way that in case of failure of some components, their functions can be taken over by other components. Therefore, when solving problems of ensuring the reliability of subsea systems, it is necessary to combine creative ingenuity with the careful application of new ideas, and the nature of the maintenance of subsea systems, along with the results of their cost-benefit analysis, must be taken into account when deciding on the application of subsea technology.

Considering the development of technologies for underwater preparation of well production, it should be noted that initially, only the task of oil production was set before the underwater equipment. In the first projects, only gas was separated from liquid hydrocarbons under water, after which the latter were pumped to the surface by a pump, and the gas was lifted under its own pressure. At the same time, the tasks of using the residual potential of deposits by extending the period of effective operation, reducing the cost of life cycle fields and increase in production led to the active development of technologies for underwater preparation of well products.

The paper considers in detail the world experience in the use and prospects for the development of systems for underwater separation of oil and gas. According to the placement of technological equipment on the seabed in close proximity to the wellheads, it makes it possible to more effectively develop the field, in particular: to maintain the pressure at the wellhead necessary for the production of heavy oil; increase the pressure at the inlet to the infield gathering system for fields with low reservoir pressure; reduce the risks associated with hydrate formation in the collection system; to ensure efficient oil production with an increase in the level of water cut through the use of oil-water separators; more flexible approach to the design of the topsides of offshore platforms by placing part of the technological process on the seabed; significantly reduce operating costs by selecting the optimal booster equipment (for example, using single-phase pumps instead of multi-phase ones).

Subsea compression technologies are used in gas fields with long distances to the coast or existing platforms and provide: reduced capital and operating costs; increase in the gas recovery factor of the formation; uninterrupted flow and elimination of emissions and discharges to the sea.

The increase in the gas recovery factor at the Ormen Lange field with the use of subsea compression is shown in fig. 3.

The first subsea pump and compressor station was developed by Kvaerner in 1989. Based on the manufacturing work in 2001-2003. demo 2000 compressor by Aker Solutions in 2004–2012. The Ormen Lange pilot station was designed and manufactured and passed technology and construction qualifications, as well as pool trials. Based on the results of pilot tests, by 2016 a full-scale compressor station with a capacity of 58 MW was manufactured, including four parallel compression lines, similar to the pilot model, with a total capacity of 70 million m3/day, and installed at the Ormen Lange field at a distance of 120 km from the coast and at a depth sea ​​900 m.

In 2015, at the Asgard field, located at a distance of 40 km from the technological platform and at a sea depth of ~300 m, a subsea compressor station with a capacity of 23 MW and a capacity of 21 million m pressure compared to expected and early water breakthrough in well Z, as well as the need to eliminate dynamic instability in pipelines.

In addition to these two projects, Statoil has implemented a third program involving the use of a subsea wet gas compressor station at the Gullfaks production field, which was discovered in 1978 and has been in operation since 1986. In this project, a different principle was used than in the systems for the Asgard and Ormen Lange fields, namely, a multi-phase compressor technology that does not require high performance: two wet gas compressors with a capacity of 5 MW, with a capacity of 12 million m3 of gas per day. The goal of the project was to increase production at the Gullfaks field by injecting gas into the well to increase pressure on the oil-bearing horizons and recover an additional 22 million barrels of oil. But just a month after installation in 2015, the world's first subsea wet gas compressor, HOFIM, was removed from the field due to a leak.

Nevertheless, the experience of using subsea compression technologies in the Ormen Lange, Asgard and Gullfaks fields has revealed the advantages of subsea compression, which are as follows: creating more safe conditions operation of fishing facilities (without the presence of people); prevention of fluid accumulation in the pipeline by increasing the pumping speed; a significant reduction in investment and operating costs compared to the gas compression option on the platform; increasing the efficiency of compression due to the location of the compressor closer to the wells; the possibility of developing fields with low reservoir pressure, low reservoir permeability and complex fluid properties.

Although the complexes of underwater gas compression in the future will make it possible to abandon surface infrastructure facilities, modern technologies have energy restrictions. They make it possible to transmit power consumption of 20-30 MW over a distance of up to 50 km, and power of 10-20 MW - up to 250 km.

Aker Solutions, the world leader in subsea compression, has created a new Compact GasBooster™ subsea compact compressor with small overall dimensions (5.5 x 5.0 x 8.0 m), high efficiency components, low weight, simplified design and is developing the following areas improvement of compressor stations: the use of highly efficient centrifugal compressors that allow the presence of a liquid phase in the compressed gas; the most compact solutions leading to a reduction in the weight and cost of an underwater compressor station (SCS); the possibility of expanding the boundaries of application of underwater compression technologies - at any depth of the sea and at a wide range of gas pressures; improvement of real-time monitoring systems for the status and operational parameters of the SKS, ensuring reliable and safe operation of subsea compression systems.

CONCLUSION

prospects further development of underwater technologies are associated with the problems of developing fields in the Arctic seas, maximizing oil and gas recovery through the creation of a complete underwater development of fields.

The development of a new generation of equipment should be aimed at improving underwater technologies in the field of: gas compression; re-injection of associated gas; purification and disposal of formation waters; control of production parameters and transportation of well products; monitoring the state of operational characteristics of underwater equipment; carrying out technological operations by autonomous means; energy supply, communications and control.

Level of the technology ready

	Development stage development stage	Technology Description Description of technology
	Unproven Idea	Preliminary plan. Analysis or tests not performed Preliminary plan. Analysis or tests are not performed
	Analytically proven idea Analytically proven idea	Functionality proven by calculation, reference to general characteristics existing technologies or tested on individual components and/or subsystems. This concept may not meet all requirements at this level, but demonstrates basic functionality and the potential to meet requirements with additional testing. Functionality is proven by calculation, by referring to the general characteristics of existing technologies or it is tested on individual components and (or) subsystems. This concept may not meet all the requirements at this level, but demonstrates the basic functionality and the potential for compliance with the requirements for additional tests
	Physically Proven Concept Physically proven concept	Conceptual solution or new characteristics of the solution, confirmed by the model or tests in the laboratory. The system reveals the ability to function in a "real" environment with simulation key parameters environment Conceptual solution or new characteristics of a solution, confirmed by a model or tests in the laboratory. The system reveals the ability to function in a “real” environment with the imitation of key environmental parameters
	Prototype test prototype testing	Prototype built in real scale and tested for compliance specifications in a limited range of operating conditions to demonstrate its functionality Prototype is being created on a real scale and subjected to testing for compliance with specifications in a limited range of operating conditions to demonstrate its functionality
	Field trials	An experimental full-scale sample is created and tested according to the program for compliance technical requirements under simulated or actual environmental conditions Test full-scale sample is created and tested according to the program for compliance with technical requirements under imitation or actual environmental conditions
	Tests at the level of integration into the system Integration level testing	Prototype full-scale prototype built and integrated into production system with full interface and compliance testing Test full-scale sample is created and integrated into the operational system with a full interface and tests for compliance with technical requirements
	System installation Installation of the system	A full-scale prototype is built and integrated into the intended operational system with a full interface and compliance testing in the intended natural environment, where it performs successfully for ≥10% of the intended life Test full-scale sample is created and integrated into the intended operational system with a full interface and tests for compliance with technical requirements in the proposed natural environment and successfully works for ≥10% of the expected service life
	Proven Technology proven technology	The production unit is integrated into the production system and successfully operates for ≥10% of the expected life Production unit is integrated into the production system and successfully works for ≥10% of the expected service life