Business plan for the development of the Yegoryevsk building stone deposit. Calculation plan Field plan

An oil field has a fairly long life cycle. It can take several decades from the discovery of an oil deposit to the production of the first oil. The entire process of developing an oil field can be divided into five main stages.

SEARCH AND EXPLORATION

1 Discovery of oil fields

Oil and gas lie in rocks - reservoirs, usually at considerable depths
To detect oil deposits in rock formations, seismic surveys are carried out. Research allows us to obtain images of deep layers of rocks, in which experienced specialists identify potentially productive structures
To make sure that there is oil in the identified rock structures, exploratory wells are drilled

2 Oil field reserve assessment

When the discovery of a deposit is confirmed, a geological model is built, which is a set of all available data. Special software allows you to visualize this data in 3D. A digital geological model of a field is needed to:

Estimate initial and recoverable oil (and gas) reserves
Develop an optimal field development project (number and location of wells, oil production levels, etc.)

For a better assessment of reserves, appraisal wells are drilled. And drilling exploration wells helps clarify the size and structure of the deposit.

At this stage, an economic assessment is made of the feasibility of developing the field based on the forecast levels of oil production and the expected costs of its development. If the expected economic indicators meet the oil company's criteria, then it begins to develop it.

MINING OF OIL AND GAS

3 Preparation for field development

For the purpose of optimal development of the oil field, a Development Project (Technological Development Scheme) and a Field Development Project are being developed. The projects include:

Required number and location of wells
The optimal way to develop a field
Types and costs of equipment and facilities required
Oil collection and treatment system
Environmental measures

The development of drilling technologies and the introduction of directional wells into practice makes it possible to locate wellheads in so-called “clusters”. One pad can have from two to two dozen wells. The cluster arrangement of wells makes it possible to reduce the impact on the environment and optimize the costs of field development.

4 Mining of oil and gas

The period during which oil reserves can be recovered is 15 - 30 years, and in some cases can reach 50 years or more (for giant fields).

The field development period consists of several stages:

Rising production stage
Stabilization of production at the maximum level (plateau)
Falling production stage
Final period

The development of oil production technologies, carrying out geological and technical measures (GTM), and the use of enhanced oil recovery (EOR) methods can significantly extend the profitable period of field development.

5 Liquidation

Once the level of oil production falls below profitable levels, development of the field is stopped and the license is returned to government agencies.

During development oil deposits are distinguished into four stages:

I-increasing oil production;

II- stabilization of oil production;

III - falling oil production;

IV - late stage of deposit exploitation.

At the first stage, the increase in oil production volumes is ensured mainly by the introduction into development of new production wells under conditions of high reservoir pressures. Typically, during this period, anhydrous oil is produced, and the reservoir pressure also decreases slightly.

The second stage - stabilization of oil production - begins after drilling the main well stock. During this period, oil production first increases slightly and then begins to slowly decline. An increase in oil production is achieved: 1) by thickening the well pattern; 2) increasing the injection of water or gas into the formation to maintain reservoir pressure; 3) carrying out work to influence the bottomhole zones of wells and increase the permeability of the formation, etc.

The developers' task is to extend the second stage as much as possible. During this period of oil reservoir development, water appears in the well production.

The third stage - declining oil production - is characterized by a decrease in oil production, an increase in water cut in well production and a large drop in reservoir pressure. At this stage, the problem of slowing down the rate of decline in oil production is solved using the methods used in the second stage, as well as by thickening the water injected into the reservoir.

During the first three stages, a selection of 80...90 should be carried out % industrial oil reserves.

The fourth stage - the late stage of reservoir exploitation - is characterized by relatively low volumes of oil withdrawal and large water withdrawals. It can last quite a long time - as long as oil production remains profitable. During this period, secondary oil production methods are widely used to extract the remaining film oil from the reservoir.

When developing a gas reservoir, the fourth stage is called the final period. It ends when the pressure at the wellhead is less than 0.3 MPa.

2. Methods of operating wells.

There are several types of well operation:

Fountain

Gas lift

Deep and others

The operation of production wells means their use in technological processes of lifting formation products (oil, condensate, gas, water) from the formation to the surface.

Methods of operating wells and periods of their use are justified in project documents for field development and are implemented by oil and gas producing organizations according to plans for geological and technical activities.

Wells should be operated only if they contain pumping and compressor pipes. The depth of descent and standard sizes of well production equipment are established by plans for putting wells into operation or plans for carrying out repair work in accordance with technological and technical calculations in accordance with current regulatory and technical documents.

A development project is a comprehensive document that is a program of actions for the development of a field.

The initial material for drawing up the project is information about the structure of the field, the number of layers and interlayers, the size and configuration of deposits, the properties of reservoirs and the oil, gas and water saturating them.

Using this data, reserves of oil, gas and condensate are determined. For example, the total geological oil reserves of individual deposits are calculated by multiplying the oil-bearing area by the effective petroleum-saturated formation thickness, effective porosity, petroleum ratio, oil density in surface conditions and the reciprocal of the oil volumetric coefficient in reservoir conditions. After this, commercial (or recoverable) oil reserves are found by multiplying the value of total geological reserves by the oil recovery coefficient.

After approval of reserves, a comprehensive design of field development is carried out. In this case, the results of trial operation of exploration wells are used, during which their productivity, reservoir pressure are determined, the operating modes of deposits, the position of water-oil (gas-water) and gas-oil contacts are studied, etc.

In the design phase, a field development system is selected, which includes determining the required number and placement of wells, the sequence of their commissioning, information about the methods and technological regimes of well operation, recommendations for regulating the balance of reservoir energy in deposits.

The number of wells must ensure the planned production of oil, gas and condensate for the period under review.

Wells are placed evenly and unevenly across the deposit area. In this case, two types of uniformity and non-uniformity are distinguished: geometric and hydro-gas-dynamic. Wells are geometrically evenly placed at the nodes of regular conditional grids (three-, four-, pentagonal and hexagonal) applied to the area of the deposit. Hydrogasdynamically uniform is the placement of wells when each has equal reserves of oil (gas, condensate) in the area of their drainage.

The well placement scheme is selected taking into account the shape and size of the deposit, its geological structure, filtration characteristics, etc.

The sequence of putting wells into operation depends on many factors: the production plan, the pace of construction of field facilities, the availability of drilling rigs, etc. “Condensing” and “creeping*” well drilling schemes are used. In the first case, wells are first drilled along a sparse grid, over the entire area of the deposit, and then they are “thickened”, i.e. drilling new wells between existing ones. In the second, all project wells are initially drilled, but in separate areas of the deposit. And only subsequently are additional wells drilled in other areas.

The “thickening” scheme is used when drilling and developing large fields with a complex geological structure of productive formations, and the “creeping” scheme is used in fields with complex terrain.

The method of operating wells is selected depending on what is being produced (gas or oil), the magnitude of reservoir pressure, the depth and thickness of the productive formation, the viscosity of the reservoir fluid and a number of other factors.

Establishing technological operating modes for production wells comes down to planning the rate of oil (gas, condensate) extraction. Well operating modes change over time depending on the state of reservoir development (position of the oil-bearing gas oil contour, water cut in wells, technical condition of the production casing, method of well operation, etc.).

Recommendations for regulating the balance of reservoir energy in deposits should contain information on methods of maintaining reservoir pressure (by flooding or gas injection into the reservoir) and on the volume of injection of working agents.

The selected development system must ensure the highest coefficients of oil, gas, and condensate recovery, protection of subsoil and the environment at minimum reduced costs.

A natural source of raw materials (oil, gas) is a deposit. Access to it is provided through many wells. When designing and developing oil fields, the following groups of production wells are distinguished:

Mining;

Pressure;

Special.

Production wells, having fountain, pumping or gas-lift equipment and are intended for the production of oil, petroleum gas and associated water. Depending on the method of lifting the liquid, production wells are divided into flowing, gas-lift and pumping wells.

With the fountain method, liquid and gas rise along the wellbore from the bottom to the surface only under the influence of reservoir energy possessed by the oil reservoir. This method is the most economical, as it is typical for newly discovered, energy-depleted deposits. By maintaining reservoir pressure by injecting water or gas into the reservoir, in some cases it is possible to significantly extend the period of well flow.

If the wells cannot flow, then they are transferred to mechanized methods of oil production.

In the gas-lift production method, compressed (hydrocarbon) gas or, very rarely, air, i.e., is supplied (or pumped using compressors) into a well to lift oil to the surface. supply expansion energy of the compressed gas.

In pumping wells, liquid is lifted to the surface using pumps lowered into the well - rod pumps (SSN) or submersible pumps (ESP). Other methods of operating wells are also used in the fields.

Injection wells are designed to influence productive formations by injecting water, gas and other working agents into them. In accordance with the adopted impact system, injection wells can be peripheral, peripheral and intracircuit. During the development process, production wells can be transferred to the number of injection wells in order to transfer injection, create additional and develop existing cutting lines, and organize focal flooding. The design of these wells, together with the equipment used, must ensure the safety of the injection process and compliance with subsoil protection requirements. Some injection wells can be temporarily used as production wells.

The reserve well stock is provided for the purpose of involving in the development of individual lenses, pinch-out zones and stagnant zones that are not involved in the development of wells of the main stock within the contour of their location. The number of reserve wells is justified in the design documents, taking into account the nature and degree of heterogeneity of productive formations (their intermittency), the density of the network of wells in the main stock, etc.

Observation and piezometric wells serve as controls and are intended for:

Observations for periodic monitoring of changes in the position of water-concentrating oil and gas-condensing oil, gas-water condensate, changes in oil-water-gas saturation of the formation during the development of the deposit;

Piezometric - for systematic changes in reservoir pressure in the boundary area, in the gas cap and in the oil zone of the reservoir.

The number and location of monitoring wells are determined in the development design documents.

Evaluation wells are drilled in fields (deposits) that are being developed or are being prepared for trial production in order to clarify the parameters and operating conditions of the formations, identify and clarify the boundaries of isolated productive fields, and assess the production of oil reserves in individual sections of the deposit within the contour of category A+B+C reserves.

Special wells are intended for the extraction of process water, the discharge of produced water, underground gas storage, and the elimination of open fountains.

Water intake wells are intended for water supply when drilling wells, as well as systems for maintaining reservoir pressure during development.

Absorption wells designed for pumping produced water from developed fields into absorbent formations.

Wells - backups are provided to replace production and injection wells that were actually abandoned due to aging (physical wear) or for technical reasons (as a result of accidents during operation). The number, placement and order of commissioning of backup wells, as proposed by oil and gas production departments, are justified by technical and economic calculations in projects and refined development projects and as an exception in technological schemes, taking into account the possible production of oil from backup wells in multi-layer fields - taking into account the possible use instead of them return wells from underlying objects.

Mothballed wells- not functioning due to the inexpediency or impossibility of their operation (regardless of their purpose), the conservation of which is formalized in accordance with the current provisions.

The operating well stock is divided into wells that are in operation (operating), those that are undergoing major repairs after operation and awaiting major repairs, those that are under development and development after drilling.

Wells in operation (operating) include wells that produced products in the last month of the reporting period, regardless of the number of days of their operation in this month.

The stock of wells in operation (operating) includes wells that produce production, wells that were stopped for the purpose of regulating development or experimental work, as well as wells that are undergoing scheduled preventive maintenance (idle, stopped in the last month of the reporting period from among those that produced production in this month).

Wells undergoing major repairs after operation include wells that have been retired from operation and where repair work was being carried out at the end of the reporting month. Wells awaiting major repairs include wells that have been idle for a calendar month.

Control questions:

1. How many stages is field development divided into?

2. What is meant by the operation of production wells?

3. What is a development project?

4. What parameters does the method of operation depend on?

Literature

1. Askerov M.M., Suleymanov A.B. Well repair: Reference, manual. -: Nedra, 1993.

2. Angelopulo O.K., Podgornov V.M., Avakov B.E. Drilling fluids for difficult conditions. - M.: Nedra, 1988.

3. Brown SI. Oil, gas and ergonomics. - M: Nedra, 1988.

4. Brown SI. Occupational safety in drilling. - M: Nedra, 1981.

5. Bulatov A.I., Avetisov A.G. Drilling Engineer's Handbook: In 3 volumes: 2nd ed., revised. and additional - M: Nedra, 1993-1995. - T. 1-3.

6. Bulatov A.I. Formation and operation of cement stone in a well, Nedra, 1990.

7. Varlamov P.S. Multi-cycle formation testers. - M: Nedra, 1982.

8. Gorodnov V.D. Physico-chemical methods for preventing complications in drilling. 2nd ed., revised. and additional - M: Nedra, 1984.

9. Geological and technological research of wells / L.M. Chekalin, A.S. Moiseenko, A.F. Shakirov and others - M: Nedra, 1993.

10. Geological and technological research during the drilling process. RD 39-0147716-102-87. VNIIPromgeofizika, 1987.

Subject: Methods of operating oil and gas wells.

Plan 1. Fountain method of operation.

2. Flowing conditions and possible methods for its extension.

Ministry Education and Science of the Republic of Kazakhstan

Faculty of Finance and Economics

Department of Economics and Management

D
discipline: Evaluation of oil and gas projects

SRS No. 1

Subject: Development plan for the strategically important Kashagan field on the Caspian Sea shelf

Performed:

3rd year special education student "Economy"

Batyrgalieva Zarina

ID: 08BD03185

Checked:

Estekova G.B.

Almaty, 2010

Over the past 30 years, trends have emerged in which global GDP is growing by an average of 3.3% per year, while global demand for oil as the main source of hydrocarbons is growing by an average of 1% per year. The lag in hydrocarbon consumption from GDP growth is associated with resource conservation processes, mainly in developed countries. At the same time, the share of developing countries in GDP production and hydrocarbon consumption is constantly increasing. In this case, the problems of hydrocarbon supply are expected to become increasingly aggravated.

The territorial proximity of such largest and dynamically developing countries as Russia and China opens up broad prospects for the export of Kazakhstani hydrocarbons. To ensure access to their market, it is necessary to develop and improve the system of main pipelines.

Estimates by international experts show that if current trends continue, all the world's proven oil reserves will only last for 40-50 years. The addition of KSKM oil resources to the world's proven reserves is a determining factor in global energy strategies. Kazakhstan must be ready for a flexible combination of strategies for systematically transferring oil production to the Caspian Sea and speeding up individual promising projects. And one of the most promising projects is the Kashagan field.

Named after a 19th-century Kazakh poet born in the Mangistau region, the Kashagan field is one of the world's largest discoveries of the last 40 years. Belongs to the Caspian oil and gas province.

The Kashagan field is located in the Kazakhstan sector of the Caspian Sea and covers a surface area of approximately 75 x 45 kilometers. The reservoir lies at a depth of about 4,200 meters below the seabed in the northern part of the Caspian Sea.

Kashagan, as a high-amplitude, reef uplift in the subsalt Paleozoic complex of the Northern Caspian Sea, was discovered by seismic exploration by Soviet geophysicists in the period 1988-1991. on the marine continuation of the Karaton-Tengiz uplift zone.

Subsequently, it was confirmed by studies of Western geophysical companies working on behalf of the government of Kazakhstan. The Kashagan, Korogly and Nubar massifs were initially identified in its composition in the period 1995-1999. were named Kashagan Eastern, Western and Southwestern, respectively.

The dimensions of Eastern Kashagan along a closed isohypse - 5000 m are 40 (10/25) km, area - 930 km², uplift amplitude - 1300 m. The predicted OWC is carried out at an absolute elevation of 4800 m, the height of the massive fractured reservoir reaches 1100 m, the oil-bearing area is 650 km², average oil-saturated thickness - 550 m.

Western Kashagan borders Eastern Kashagan along a submeridional structural scarp, which may be associated with a tectonic disturbance. The dimensions of the reef uplift along a closed stratoisohypse - 5000 m are 40 * 10 km, area - 490 km², amplitude - 900 m. The OWC is assumed to be common to both uplifts and is carried out at an absolute elevation of 4800 m, trap height - 700 m, oil content area - 340 km² , average oil-saturated thickness - 350 m.

Southwestern Kashagan is located somewhat to the side (south) of the main massif. The uplift along a closed stratoisohypse - 5400 m, has dimensions of 97 km, area - 47 km², amplitude - 500 m. The OWC is predicted at an absolute elevation of 5300 m, oil-bearing area - 33 km², average oil-saturated thickness - 200 m.

Kashagan's oil reserves range widely from 1.5 to 10.5 billion tons. Of these, the Eastern accounts for from 1.1 to 8 billion tons, the Western - up to 2.5 billion tons and the South-Western - 150 million tons.

Kashagan's geological reserves are estimated at 4.8 billion tons of oil according to Kazakh geologists.

According to the project operator, total oil reserves amount to 38 billion barrels or 6 billion tons, of which about 10 billion barrels are recoverable. Kashagan has large natural gas reserves of more than 1 trillion. cube meters.

Partner companies in the Kashagan project: Eni, KMG Kashagan B.V. (a subsidiary of Kazmunaigas), Total, ExxonMobil, Royal Dutch Shell each have a 16.81% stake, ConocoPhillips - 8.4%, Inpex - 7.56%.

The project operator was appointed in 2001 by partners: Eni, and created the company Agip KCO. Project participants are working on the creation of a joint operating company, North Caspian Operating Company (NCOC), which will replace AgipKCO and a number of agent companies as a single operator.

The Kazakh government and the international consortium for the development of the North Caspian project (including the Kashagan field) agreed to postpone the start of oil production from 2011 to the end of 2012.

Oil production volumes at Kashagan should reach 50 million tons per year by the end of the next decade. Oil production at Kashagan, according to ENI calculations, should reach 75 million tons per year in 2019. With Kashagan, Kazakhstan will enter the Top 5 world oil producers.

In order to increase oil recovery and reduce H3S content, the consortium is preparing to use several onshore and offshore installations in Karabatan to inject natural gas into the reservoir, and an oil pipeline and a gas pipeline will be built to Karabatan.

Development of the Kashagan field in the harsh marine conditions of the Northern Caspian Sea presents a unique combination of technological and supply chain difficulties. These challenges involve ensuring production safety, engineering, logistics and environmental issues, making this project one of the largest and most complex industry projects in the world.

The field is characterized by high reservoir pressure of up to 850 atmospheres. High-quality oil -46° API, but with a high gas factor, hydrogen sulfide and mercaptan content.

Kashagan was announced in the summer of 2000 based on the results of drilling the first well, Vostok-1 (East Kashagan-1). Its daily flow rate was 600 m³ of oil and 200 thousand m³ of gas. The second well (Zapad-1) was drilled in Western Kashagan in May 2001, 40 km from the first. It showed a daily flow rate of 540 m3 of oil and 215 thousand m3 of gas.

For the development and assessment of Kashagan, 2 artificial islands were built, 6 exploration and 6 appraisal wells were drilled (Vostok-1, Vostok-2, Vostok-3, Vostok-4, Vostok-5, Zapad-1.

Due to the shallow waters and cold winters of the Northern Caspian Sea, the use of traditional drilling and production technologies, such as reinforced concrete structures or jack-up platforms installed on the seabed, is not possible.

To provide protection from harsh winter conditions and ice movements, offshore structures are installed on artificial islands. Two types of islands are envisaged: small “drilling” islands without personnel and large “islands with technological complexes” (ETK) with service personnel.

Hydrocarbons will be pumped through pipelines from the drilling islands to the ETC. On the ETC islands there will be technological installations for extracting the liquid phase (oil and water) from raw gas, installations for gas injection and energy systems.

In Phase I, approximately half of the total volume of gas produced will be injected back into the reservoir. The recovered fluids and raw gas will be supplied through a pipeline to the shore at the Bolashak oil and gas processing plant in the Atyrau region, where it is planned to treat the oil to commercial quality. Some gas volumes will be sent back to the offshore complex for use in power generation, while some of the gas will satisfy similar needs of the onshore complex.

There are a number of technical difficulties in the Kashagan development strategy:

The Kashagan reservoir lies at a depth of about 4,200 meters below the seabed and has high pressure (initial reservoir pressure 770 bar). The reservoir is characterized by a high content of high-sulfur gas.

The low level of salinity caused by the influx of fresh water from the Volga, combined with shallow waters and winter temperatures as low as -30C, results in the Northern Caspian being covered in ice for approximately five months of the year. Ice movements and the formation of grooves from the movement of ice on the seabed represent serious limitations for construction work.

The Northern Caspian Sea is a very sensitive ecological area and habitat for a diverse range of flora and fauna, including some rare species. NCOC considers environmental responsibility a top priority. We work diligently and diligently to prevent and minimize as much as possible any environmental impacts that may arise from our operations.

The Northern Caspian region is an area where the supply of equipment important for the project is fraught with certain difficulties. Logistical difficulties are compounded by restrictions on access along water transport routes, such as the Volga-Don Canal and the Baltic Sea-Volga water transport system, which, due to thick ice cover, are open to navigation for only about six months a year.

I would like to note the export strategy of this project. The current plan for exporting post-completion products involves the use of existing pipeline and railway systems.

The western route of the CPC pipeline (pipeline from Atyrau to Novorossiysk along the Black Sea coast), the northern route from Atyrau to Samara (connection to the Russian Transneft system) and the eastern route (Atyrau to Alashankou) provide connections to existing export transportation systems.

The possible south-eastern route depends on the development of the Kazakhstan Caspian Transportation System (KCTS), which could transport oil from West Eskene, where the Bolashak plant is located, to the new Kuryk terminal. The oil could then be transported by tanker to a new terminal near Baku, where it would be pumped into the Baku-Tbilisi-Ceyhan (BTC) pipeline system or other pipelines to reach international markets.
All possible export routes are currently being explored.

This project takes into account safety and environmental protection. Since the formation of the first consortium in 1993, numerous environmental protection programs have been developed and implemented throughout oilfield operations on land and offshore. For example, Agip KCO engaged local companies to carry out environmental impact assessments (EIA) of its activities, including the construction of onshore and offshore structures, trunk pipelines and onshore export pipelines. A program was initiated to finance scientific research in the field of biological diversity of the Caspian region. Twenty air quality monitoring stations were built in the Atyrau region. Soil surveys and monitoring of the state of bird and seal populations are carried out annually. In 2008, a map of environmentally sensitive zones of the North Caspian region was published, created, among other things, on the basis of data collected by the consortium.

There are also problems with sulfur disposal. The Kashagan field contains approximately 52 trillion cubic feet of associated gas, much of which will be reinjected into the reservoir at offshore facilities to improve oil recovery. During Stage 1 (Pilot Development Stage), not all associated gas will be reinjected into the reservoir at offshore facilities. Part of it will be sent to an onshore integrated oil and gas processing facility, where the gas will be desulfurized, which will then be used as fuel gas to generate electricity for onshore and offshore operations, while part of it will be sold on the market as a commodity gas. Phase 1 is expected to produce an average of 1.1 million tons of sulfur per year from sour gas purification.
Although the consortium plans to sell the entire volume of sulfur produced, there may be a need for temporary storage of sulfur. Sulfur produced at the Bolashak Unitary Plant and Gas Plant will be stored in closed conditions, isolated from the environment. Liquid sulfur will be poured into sealed containers equipped with sensors. Before sale, the sulfur will be converted into pastellized form, which will avoid the formation of sulfur dust during crushing.

In addition to responsible production operations, program participants assume social and environmental responsibilities, the implementation of which will benefit the citizens of Kazakhstan in the long term. Fulfilling these obligations requires close cooperation with state and local authorities, local communities and initiative groups

In the period from 2006 to 2009. more than US$5.3 billion was spent on local goods and services. In 2009, local goods and services accounted for 35% of the company's total expenses.

In 2009, during the period of maximum activity for the construction of Pilot Development Stage facilities, more than 40,000 people were employed in the project in Kazakhstan. More than 80% of the workers were citizens of Kazakhstan - an exceptional indicator for projects of this scale.

Infrastructure and social impact projects are important components of NCOC's corporate and social responsibility. According to the SRPSK, a significant part of the capital investment in the development of the field goes to the construction of social infrastructure facilities in the fields of education, healthcare, sports and culture.

Funds are evenly distributed between Atyrau and Mangistau regions, where production operations under the SRPSK are carried out.

Since 1998, 126 projects have been completed in close cooperation with local authorities, 60 projects in the Atyrau region and 66 in the Mangistau region.

In total, 78 million US dollars were spent in the Atyrau region and 113 million US dollars in the Mangistau region.

In addition, under the 2009 Sponsorship and Charity Program, NCOC and Agip KCO supported more than one hundred initiatives in the fields of culture, healthcare, education and sports. Among them are advanced training for doctors and teachers, seminars on intercultural education and environmental literacy in schools, inviting leading Russian surgeons to operate on Atyrau children, purchasing musical instruments for an Aktau school and purchasing medical equipment and ambulances for a hospital in Tupkaragan.

Health and labor protection plays an important role. Participants in this project will conduct systematic risk management in order to continuously improve the system of health, labor and environmental protection and reach the level of world leaders in this indicator. All this is carried out in accordance with the requirements of the Production Sharing Agreement for the Northern Caspian Sea, Kazakh and international legislation, existing industry standards and corporate directives.

All participants of the SRPSK undertake to:

Promote the introduction of HSE principles into the company culture, where all employees and service providers have a shared responsibility for implementing these principles, and lead by example.

Develop systems that allow for a systematic assessment of risks in the field of HSE at all stages of the company’s activities and to effectively control these risks.

Develop and certify a HSE management system and constantly inform Agent companies, the Authorized Body, and all interested parties about the state of affairs in the HSE area for the purpose of continuous improvement.

Select business partners based on their ability to meet their HSE obligations.

Implement systems and procedures that allow for an immediate and effective response in the event of unplanned and unwanted events, and regularly review them.

Raise the level of awareness of the personal responsibility of all company employees in preventing the risks of accidents, damage to health and the environment.

Carry out joint work with government bodies of the Republic of Kazakhstan and all interested parties in order to develop regulations and standards aimed at increasing the level of safety of company employees and environmental protection.

Apply a constructive approach to its activities, based on dialogue with stakeholders and the public and aimed at achieving recognition of the company's activities by the local community through the implementation of social programs.

Sponsorship and philanthropy projects are aimed at ensuring economic sustainability and improving well-being, supporting health, education, culture and cultural heritage, sports, and assisting low-income individuals who are eligible to receive such support, as well as being consistent with NCOC's strategic goals for sustainable development. The implementation of the sponsorship and charity program is entrusted to Agip KCO.

In particular, projects involve the participants' own contributions and must also demonstrate to the public their long-term sustainability. Support for political or religious organizations is excluded, projects cannot create unfair conditions for market competition, or negatively affect environmental stability and/or natural ecosystems. Projects are typically developed by local governments, NGOs or community representatives, but may also be initiated by NCOC or its Agents as proactive measures to support local communities.

Bibliography:

State program for the development of the Kazakhstan sector of the Caspian Sea

6.1. The standards of this section contain the basic requirements for the layout of the master plan and fire safety for designed and reconstructed buildings and structures of the oil industry, and individual requirements are given in the relevant sections of these Standards.

In addition to the regulatory requirements of these Standards, when designing fire protection of facilities, it is necessary to be guided by the following documents:

“Master plans for industrial enterprises”;
“Fire safety standards for the design of buildings and structures”;
“Industrial buildings of industrial enterprises”;
“Gas supply. Internal and external devices";
“Structures of industrial enterprises”;
“Auxiliary buildings and premises of industrial enterprises”;
“Rules for the construction of electrical installations (PUE)”;
"Water supply. External networks and structures";
"Warehouses of oil and petroleum products";
"Main pipelines";
"Car service enterprises";
“Sanitary standards for the design of industrial enterprises.”

a) REQUIREMENTS FOR THE MASTER PLAN

6.2. It is necessary to develop a master plan for the field based on the data of the technological scheme (project) for the development of the oil field, taking into account the development schemes of the oil industry and the location of productive forces in economic regions and union republics.

6.3. The general plan of the field is drawn up on maps of land users, usually on a scale of 1:25000, taking into account the requirements of the Fundamentals of land, water and other legislation of the USSR and union republics, in two stages:

preliminary - as part of the supporting materials for the act of selecting sites and routes;
final - after approval of the act of selecting sites and routes in the prescribed manner, taking into account the comments of all land users.

6.4. The master plan scheme should provide for the placement on the territory of the field of wellheads of oil, gas, injection and other single wells, well clusters, gas stations, booster pump stations, control systems, UPS, pumping stations, VRP, compressor stations, substations and other facilities, as well as engineering communications (roads, oil - and gas pipelines, water pipelines, power lines, communications, telemechanics, cathodic protection, etc.), providing technological and production processes for the collection and transportation of oil well products, taking into account the existing transport connections in the area of the capacities of the central processing plant, oil refinery, gas processing plant, refinery, the direction of external transport of oil, gas and water, sources of supply of electricity, heat, water, air, etc.

6.5. When developing a master plan diagram, it is necessary to consider:

brigade and field form of organizing the exploitation of fields in accordance with the “Regulations on the oil production brigade ...” of the Ministry of Petroleum Industry;
possibility of expansion and reconstruction of technological systems;
carrying out technical measures to intensify production processes of oil and gas production, collection, and transportation.

6.6. The master plan of enterprises, facilities, buildings and structures for field development should be designed in accordance with the requirements of the standards “Master plans of industrial enterprises” and others specified in the general part of this section, as well as the requirements of these Standards.

Planning decisions of the master plan must be developed taking into account the technological zoning of installations, blocks, buildings and structures.

The placement of production and auxiliary buildings and structures in zones must be done according to their functional and technological purpose and taking into account their explosion, explosion and fire hazards.

6.7. Access and on-site railways and roads to objects, buildings and structures should be designed in accordance with the requirements of the standards “1520 mm gauge railways”, “Highways”, “Instructions for the design of highways for oil fields of Western Siberia” of the Ministry of Petroleum Industry.

6.8. The dimensions of sites for the construction of enterprises, buildings and structures are determined from the conditions for the placement of technological structures, auxiliary structures and utilities, taking into account the requirements of fire safety and sanitary standards.

The building density of enterprises and individual facilities must correspond to the values specified in the standards “Master Plans of Industrial Enterprises”. The areas of oil and gas well sites must be accepted in accordance with the “Land Allocation Standards for Oil and Gas Wells” of the Ministry of Petroleum Industry.

The width of the land strip for the construction of linear structures should be no more than specified: in the “Land Allocation Norms for Main Pipelines”, “Land Allocation Norms for Communication Lines”, “Land Allocation Norms for Electric Networks with Voltage 0.4 - 500 kV”, “Norms land allocation for highways."

6.9. CPS sites, production service bases (PSB), NGDU, UBR, URB, bases of technological transport departments (UTD) and special equipment, pipe and tool bases and other buildings and structures for auxiliary purposes for servicing the oil field (CDNG, helipads, etc.) , as well as rotational camps can be located both on the territory of the field and outside it.

6.10. When locating enterprises, facilities, buildings and structures for oil production on coastal sections of rivers and other bodies of water, the planning marks of construction sites should be taken at least 0.5 m above the calculated highest water horizon, taking into account the backwater and slope of the watercourse with the probability of exceeding it:

for structures in which the production process is directly related to the extraction of oil from the subsoil (oil and gas wellheads, metering installations) - once every 25 years;
for central pumping stations, booster stations, gas compressor stations, separation plants, oil treatment plants, oil pumping stations, pumping stations and electrical substations - once every 50 years.

6.11. Oil field development facilities should be located from neighboring enterprises at the distances specified in Table 19, taking into account the possibility of cooperation with these enterprises in the construction of utility networks and highways.

6.12. When developing a master plan for enterprises, buildings and structures for field development, distances from technological installations and structures to switchgear, transformer substations, instrumentation and control units and operator rooms must be determined in accordance with the requirements of PUE-76, section VII, taking into account the density of combustible gas in relation to the air density determined technological calculation in the project.

6.13. The shortest distances between buildings and structures of oil field development facilities should be taken according to table. 20, and from buildings and structures to underground oil and gas pipelines - according to table. 21.

6.14. The shortest distances between buildings and structures located on the central station should be taken according to table. 22.

6.15. The distance from oil traps, settling ponds and other sewage system structures to auxiliary and industrial buildings and structures not related to the maintenance of treatment facilities should be taken according to table. 22.

The shortest distances between buildings and sewerage system structures should be taken according to table. 23.

6.16. The shortest distances from warehouse buildings, sheds of open areas for storing cylinders with oxygen, acetylene, nitrogen and chlorine to buildings and structures with production categories A, B, C, E should be at least 50 m, to other production and auxiliary buildings should not be less:

when the number of cylinders is less than 400 pcs. - 20 m;
with the number of cylinders from 400 to 1200 pcs. - 25 m.

The total capacity of warehouses for storing cylinders should not exceed 1200 units, including no more than 400 cylinders filled with flammable gases.

Notes: 1. The indicated number of cylinders is given for one cylinder with a capacity of 50 liters; with a smaller cylinder capacity, a recalculation must be made.

2. Joint storage of flammable gas cylinders and oxygen cylinders is not permitted.

6.17. Distances from fire heating devices (furnaces for heating oil, petroleum products, gas, water and anhydride), located outside the building, to other technological devices, buildings and structures of the workshop or installation that include the furnace, as well as to overpasses, with the exception of technological pipelines connecting fire heating devices with other technological devices must be no less than those indicated in table. 24.

6.18. The distances indicated in the tables are determined by:

a) between production, utility and auxiliary buildings, installations, tanks and equipment - in the clear between external walls or structure structures (excluding metal stairs);

b) for technological racks and pipelines laid without racks - to the outermost pipeline;

c) for on-site railway tracks - to the axis of the nearest railway track;

d) for on-site roads - to the edge of the roadway;

e) for flare installations - up to the axis of the flare barrel;

f) when reconstructing existing enterprises or technological installations, if it is impossible to strictly comply with technical conditions without large material costs, in agreement with the organization approving the project, deviations in terms of gaps are allowed within the limits of up to 10%.

6.19. It is recommended to place external technological installations on the side of the blank wall of the industrial building.

In the case of placing open installations with production categories A, B, E on both sides of the building with which they are connected (or one installation between two buildings), they must be located at a distance of at least 8 m from it - with a blank wall, at least 12 m - with a wall with window openings, regardless of the area occupied by buildings and installations. The second installation or building must be located taking into account the requirements of clause 2.90.

It is allowed to place an overpass for the pipelines of this installation between the outdoor installation and the building.

6.20. The distance from industrial buildings to emergency or drainage tanks is taken as for process equipment located outside the building.

6.21. A ground emergency (drainage) tank intended for draining flammable liquids and gases from furnaces should be fenced with a fireproof wall or embankment at least 0.5 m high and placed at a distance of at least 15 m from the furnace site.

The underground emergency (drainage) tank must be located at a distance of at least 9 m from the furnace site, separately or together with other drainage tanks (on the same site).

6.22. The territories of central processing stations, oil treatment facilities, tank farms, flammable liquids and gas liquids warehouses, CPS, UPS and KS must have a 2 m high fence with a 4.5 m wide gate.

The distance from the fence to facilities with production facilities of categories A, B, C and E must be at least 5 m.

On the outside, along the border of the oil treatment facility, tank farms and warehouses of flammable liquids and flammable liquids, a 10 m wide strip should be provided, free from ground networks.

6.23. The area around the booster pump flare pipe must be fenced with an earthen rampart 0.7 m high, with a radius of 15 m.

The area around the flare shaft of the booster station technological structures with a height of 30 m or more must be fenced with a 1.6 m high fence made of barbed wire.

The distance from the flare shaft to the fence, as well as between the flare shafts, should be taken according to the thermal engineering calculation data, but not less than 30 m.

The area around the candle for gas discharge at compressor stations, well clusters, and single gas wells is not fenced.

6.24. The placement of gas condensate containers (separators, fire arresters and other equipment), as well as the construction of wells, pits and other recesses within the fencing of the area around the flare is not allowed.

6.25. Aboveground laying of gas pipelines from installations to the flare pipe should be provided on fireproof supports.

6.26. The area at the mouth of a single or cluster of wells should be fenced with an earthen rampart 1 m high with an edge width at the top of the rampart of 0.5 m.

6.27. A well cluster site with more than 8 wells must have at least two entrances located at different ends along its long side.

6.28. An open drainage system should be designed at facility sites. On land plots not occupied by buildings and structures, the natural topography should be preserved and vertical planning should be provided only in cases where it is necessary to drain surface water and lay utility networks.

6.29. For landscaping areas of open technological installations, only lawns should be designed.

6.30. On-site engineering networks and communications should be designed as a single system with their placement in designated technical strips (corridors).

6.31. The method of laying utility networks (ground, above-ground or underground) should be taken into account the requirements of the relevant sections of these Standards.

6.32. It is allowed to lay gas pipelines, oil pipelines, oil product pipelines and inhibitor pipelines in one trench. The distances between them should be taken based on the conditions of their installation, repair and maintenance.

The distances between process pipelines laid in the ground and buildings and structures are determined from the conditions of ease of installation, operation and repair of pipelines.

6.33. The distance from the place of water intake (reception wells) from reservoirs must be at least:

to buildings of I and II degree of fire resistance - 10 m;
to buildings of III, IV and V degrees of fire resistance and to open warehouses of combustible materials - 30 m;
to buildings and structures with production categories A, B, C, E for fire danger - 20 m;
to tanks with flammable liquids - 40 m;
to tanks with flammable liquids and liquefied flammable gases - 60 m.

6.34. Reception wells of reservoirs and wells with hydrants should be located at a distance of no more than 2 m from the sides of highways, and if they are located at a distance of more than 2 m, they should have entrances to them with an area of at least 12x12 m.

6.35. Fire tanks or reservoirs should be placed in such a way that they serve objects located within the radius of:

if there are car pumps - 200 m;
if there are motor pumps - 100 - 150 m, depending on the type of motor pump.

To increase the service radius, it is allowed to lay dead-end pipelines from tanks or reservoirs with a length of no more than 200 m and taking into account the requirements of clause 6.58 of these Standards.

6.36. Roads at the sites of central collection and treatment points for oil, gas and water should be designed with shoulders raised above the level surface of the adjacent territory by at least 0.3 m. If this requirement cannot be met, roads should be designed in such a way that spilled oil products cannot get on the road (installation of ditches, etc.).

6.37. Within the boundaries of on-site highways, it is allowed to lay fire-fighting water supply networks, communications, alarms, outdoor lighting and power electrical cables.

The organization was founded in December 2005. The project operator is KarakudukMunai LLP. LUKOIL's partner in the project is Sinopec (50%). The development of the deposit is carried out in accordance with the subsoil use contract signed on September 18, 1995. The contract period is 25 years. The Karakuduk deposit is located in the Mangistau region, 360 km from Aktau. Residual recoverable hydrocarbon reserves – 11 million tons. Production in 2011 – 1.4 million tons of oil (LUKOIL’s share – 0.7 million tons) and 150 million cubic meters of gas (LUKOIL’s share – 75 million cubic meters). Investments since the beginning of the project (since 2006) - more than 400 million dollars in the share of LUKOIL. The total number of employees is about 500 people, of which 97% are citizens of the Republic of Kazakhstan. LUKOIL plans to invest up to $0.1 billion in its share until 2020 in the development of the project.

Proven oil and gas reserves (shared by LUKOIL Overseas)
	million barrels
	bcm
Oil and gas	million barrels n. e.
Commercial production for the year (in the share of LUKOIL Overseas)
	million barrels

Oil and gas	million barrels n. e.
Share of LUKOIL Overseas in the project*
Project participants
Project operator	Karakudukmunai LLP
Operating stock of production wells
Average daily flow rate of 1 well
Average daily flow rate of 1 new well

GENERAL INFORMATION ABOUT THE DEPOSIT

Geographically, the Karakuduk field is located in the southwestern part of the Ustyurt plateau. Administratively it belongs to the Mangystau district of the Mangystau region of the Republic of Kazakhstan.

The nearest settlement is the Sai-Utes railway station, located 60 km to the southeast. Beineu station is located 160 km from the field. The distance to the regional center of Aktau is 365 km.

Orographically, the work area is a desert plain. The absolute elevations of the relief surface range from +180 m to +200 m. The work area is characterized by a sharply continental climate with hot, dry summers and cold winters. The hottest month of summer is July with a maximum temperature of up to +45 o C. In winter, the minimum temperature reaches -30-35 o C. The average annual precipitation is 100-170 mm. The area is characterized by strong winds that turn into dust storms. In accordance with SNiP 2.01.07.85, the field area in terms of wind pressure belongs to the III area (up to 15 m/s). In summer, winds predominate from the north-west direction, in winter - from north-east. The snow cover in the work area is uneven. The thickness in the most submerged low-lying areas reaches 1-5 m.

The flora and fauna of the area is poor and is represented by species typical of semi-desert zones. The area is characterized by sparse grass and shrub vegetation: camel thorn, wormwood, and solyanka. The fauna is represented by rodents, reptiles (turtles, lizards, snakes) and arachnids.

There are no natural water sources in the work area. Currently, the sources of water supply for the deposit of drinking water, for technical needs and fire-fighting needs, are Volga water from the Astrakhan-Mangyshlak main water pipeline, as well as special water intake wells up to 1100 m deep for Albsenomanian deposits.

The work area is practically uninhabited. 30 km east of the Karakuduk field there is the Makat – Mangyshlak railway line, along which the existing oil and gas pipelines Uzen-Atyrau – Samara and “Central Asia – Center” are laid, as well as the high-voltage power line Beineu – Uzen. Communication between the fishery and populated areas is carried out by motor transport.

GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF THE DEPOSIT

3.1. Characteristics of the geological structure

Lithological and stratigraphic characteristics of the section

As a result of prospecting, exploration and production drilling at the Karakuduk field, a layer of Meso-Cenozoic sediments with a maximum thickness of 3662 m (well 20), ranging from Triassic to Neogene-Quaternary inclusive, was exposed.

Below is a description of the exposed section of the deposit.

Triassic system - T. Variegated terrigenous strata of Triassic age are represented by interbedded sandstones, siltstones, mudstones and mudstone-like clays, colored in various shades of gray, brown to greenish-gray. The minimum exposed Triassic thickness is noted in well 145 (29 m) and the maximum in well 20 (242 m).

Jurassic system - J. A sequence of Jurassic deposits lies on the underlying Triassic rocks with stratigraphic and angular unconformity.

The Jurassic section is presented in the volume of the lower, middle and upper sections.

Lower section – J 1. The Lower Jurassic section is lithologically composed of interbedded sandstones, siltstones, clays and mudstones. The sandstone is light gray with a greenish tint, fine-grained, poorly sorted, strongly cemented. Clays and siltstones are dark gray with a greenish tint. The mudstones are dark gray with OPO inclusions. Regionally, the Yu-XIII horizon is confined to Lower Jurassic deposits. The thickness of the Lower Jurassic deposits ranges from 120-127m.

Middle section – J 2. The Middle Jurassic sequence is represented by all three stages: Bathonian, Bajocian and Aalenian.

Aalenian Stage - J 2 a. Sediments of Aalenian age overlie the underlying ones with stratigraphic and angular unconformity and are represented by alternating sandstones, clays and, less commonly, siltstones. Sandstones and siltstones are colored in gray and light gray tones; clays are characterized by a darker color. Regionally, horizons Yu–XI, Yu–XII are confined to this stratigraphic interval. The thickness is more than 100m.

Bajocian Stage - J 2nd century. Sandstones are gray and light gray, fine-grained, strongly cemented, non-calcareous, micaceous. Siltstones are light gray, fine-grained, micaceous, clayey, with inclusions of charred plant remains. The clays are dark gray, black, and dense in places. Productive horizons Yu-VI- Yu-X are confined to deposits of this age. The thickness is about 462m.

Bathonian Stage - J 2 bt. Lithologically they are represented by sandstones, siltstones, interbedded with clays. In the lower part of the section, the proportion of sandstones increases with thin layers of siltstones and clays. Productive horizons Yu-III- Yu-V are confined to the sediments of the Bathonian stage. The thickness varies from 114.8 m to 160.7 m.

Upper section - J 3. The Upper Jurassic deposits conformably overlie the underlying ones and are represented by three stages: Callovian, Oxfordian and Volgian. The lower boundary is drawn along the roof of the clay pack, which is clearly visible in all wells.

Callovian stage - J 3 k. The Callovian stage is represented by interlayering of clays, sandstones and siltstones. According to the lithological features of the stage, three members are distinguished: the upper and middle are clayey with a thickness of 20-30 m, and the lower is an alternation of sandstone and siltstone layers with clay interlayers. The productive horizons Yu-I and Yu-II are confined to the lower member of the Callovian stage. The thickness ranges from 103.2m to 156m.

Oxfordian-Volgian stage – J 3 ox-v. The deposits of the Oxfordian stage are represented by clays and marls with rare interlayers of sandstones and siltstones, and some differentiation is observed: the lower part is clayey, the upper part is marly.

The rocks are gray, light gray, sometimes dark gray, and have a greenish tint.

The Volgian section is a sequence of clayey limestones with interlayers of dolomites, marls and clays. Limestones are often fissured and porous, massive, sandy, clayey, with uneven fractures and a matte sheen. The clays are silty, gray, calcareous, often with inclusions of faunal remains. Dolomites are gray, dark gray, cryptocrystalline, clayey in places, with uneven fractures and a matte sheen. The thickness of the rocks ranges from 179m to 231.3m.

Cretaceous system - K. The deposits of the Cretaceous system are represented in the volume of the lower and upper sections. The section was divided into tiers using logging materials and comparison with neighboring areas.

Lower section – K 1. Lower Cretaceous deposits are composed of rocks of the Neocomian overstage, Aptian and Albian stages.

Neocomian superstage – K 1 ps. The underlying Volgian sediments are conformably overlain by the Neocomian interval, which unites three stages: Valanginian, Hauterivian, Barremian.

The section is lithologically composed of sandstones, clays, limestones and dolomites. The sandstones are fine-grained, light gray, polymictic, with carbonate and clayey cement.

At the level of the Hauterivian interval, the section is mainly represented by clays and marls, and only at the top can a sand horizon be traced. Barremian deposits are distinguished in the section by the variegated color of the rocks and are lithologically composed of clays with interlayers of sandstones and siltstones. Throughout the Neocomian section, the presence of units of silty-sandy rocks is observed. The thickness of the Neocomian overstage sediments ranges from 523.5 m to 577 m.

Aptian stage – K 1 a. Sediments of this age overlap the underlying ones with erosion, having a clear lithological boundary with them. In the lower part the section is composed predominantly of clayey rocks with rare interlayers of sands, sandstones, and siltstones, and in the upper part there is a uniform alternation of clayey and sandy rocks. The thickness varies from 68.7 m to 129.5 m.

Albian Stage – K 1 al. The section consists of interbedded sands, sandstones and clays. The structural and textural features of the rocks do not differ from the underlying ones. The thickness varies from 558.5 m to 640 m.

Upper section – K 2. The upper section is represented by Cenomanian and Turonian-Senonian deposits.

Cenomanian stage – K 2 s. The deposits of the Cenomanian stage are represented by clays alternating with siltstones and sandstones. In lithological appearance and composition, rocks of this age do not differ from Albian deposits. Thickness ranges from 157m to 204m.

Turonian-Senonian undivided complex – K 2 t-cn. At the bottom of the described complex there is a Turonian stage composed of clays, sandstones, limestones, and chalk-like marls, which are a good reference point.

Higher up the section lie deposits of the Santonian, Campanian, and Maastrichtian stages, united in the Senonian overstage, represented lithologically by a thick layer of interbedded marls, chalk, chalk-like limestones and carbonate clays.

The thickness of the sediments of the Turonian-Senonian complex varies from 342m to 369m.

Paleogene system - R. Paleogene deposits are represented by white limestones, greenish-marly strata and pink siltstone clays. Thickness varies from 498m to 533m.

Neogene-Quaternary systems – N-Q. Neogene-Quaternary deposits are composed predominantly of carbonate-clayey rocks of light gray, green and brown color and limestone - shell rocks. The upper part of the section is made of continental sediments and conglomerates. The thickness of the sediments varies from 38 m to 68 m.

3.2. Tectonics

According to tectonic zoning, the Karakuduk field is located within the Arystanov tectonic stage, which is part of the North Ustyurt system of troughs and uplifts of the western part of the Turan plate

According to the materials of seismic exploration work MOGT-3D (2007), carried out by JSC Bashneftegeofizika, the Karakuduk structure along reflecting horizon III is a brachyanticlinal fold of sublatitudinal strike with dimensions of 9x6.5 km along a closed isohypse minus 2195 m, with an amplitude of 40 m. The angles of incidence of the wings increase with depth: in the Turonian - fractions of a degree, in the Lower Cretaceous -1-2˚. The structure along reflector V represents an anticlinal fold, broken by numerous faults, perhaps some of them of a non-tectonic nature. All major faults described later in the text can be traced along this reflecting horizon. The fold of submeridional strike consists of two arches, outlined by an isohypsum minus 3440 m, identified in the area of wells 260-283-266-172-163-262 and 216-218-215. Along the isohypsum minus 3480 m, the fold has dimensions of 7.4 x 4.9 km and an amplitude of 40 m.

The uplift on structural maps along Jurassic productive horizons has an almost isometric shape, complicated by a series of faults dividing the structure into several blocks. The most basic fault is the F 1 fault in the east, which can be traced throughout the productive section and divides the structure into two blocks: central (I) and eastern (II). Block II is lowered relative to block I with an increase in the displacement amplitude from south to north from 10 to 35 m. Fault F1 is inclined and shifts with depth from west to east. This violation was confirmed by drilling well 191, where part of the Jurassic sediments of about 15 m at the level of the productive horizon Yu-IVA is missing.

Disruption F 2 was carried out in the area of wells 143, 14 and cuts off the central block (I) from the southern block (III). The justification for carrying out this violation was not only the seismic basis, but also the results of well testing. For example, from among the base wells, next to well 143 there is well 222, where oil was obtained during testing of the Yu-I horizon, and water was obtained in well 143.

Description of work