The main graphic document in the calculation of reserves is the calculation plan. Estimated plans (Fig. 3) are compiled on the basis of a structural map along the top of productive reservoirs or the nearest benchmark located no more than 10 m above or below the top of the reservoir. External and internal contours are plotted on the map oil- and gas content, boundaries of reserves categories.

The boundaries and area of ​​calculation of oil and gas reserves of each category are colored in a certain color:

Rice. 3. An example of a deposit calculation plan.

1 - oil; 2 - water: 3 - oil and water;

Wells: 4 - producing, 5 - exploratory, 6 - mothballed, 7 - liquidated, 8 - not flowing; 9 - isohypses of the reservoir surface, m;

Oil-bearing contours: 10 - external, 11 - internal; 12 - boundary of lithofacies replacement of reservoirs; 13 categories of reserves;

Numerals at the wells: numerator - well number, denominator - absolute elevation of the reservoir top, m.

All wells drilled as of the date of calculation of reserves are also applied to the calculation plan (with an exact indication of the position of the mouths, the points of intersection of the roof of the corresponding productive formation by them):

Exploration;

Mining;

Mothballed in anticipation of the organization of fishing;

Pressure and observation;

Those who gave anhydrous oil, oil with water, gas, gas with condensate, gas with condensate and water and water;

Under trial;

Untested, with specification oil-, gas- and water-saturation of formations - collectors according to the interpretation of materials of geophysical surveys of wells;

Liquidated, indicating the reasons for liquidation;

Revealed a layer composed of impermeable rocks.

For tested wells, the following are indicated: depth and absolute marks of the roof and bottom of the reservoir, absolute marks of perforation intervals, initial and current oil production rates, gas and water, choke diameter, depression, duration of operation, date of occurrence of water and its percentage in the produced product. When testing two or more layers together, their indices are indicated. Debits oil And gas should be measured when the wells are operating on the same chokes.

For production wells, the following are given: the date of commissioning, initial and current flow rates and reservoir pressure, the amount of oil produced, gas, condensate and water, the date of the start of watering and the percentage of water in the produced products as of the date of reserves calculation. At in large numbers wells, this information is placed in the table on the calculation plan or on the sheet attached to it. In addition, the calculation plan contains a table indicating the values ​​of the calculated parameters adopted by the authors, the calculated reserves, their categories, the values ​​of the parameters adopted by the decision of the State Reserves Committee of the Russian Federation, the date on which the reserves were calculated.

When recalculating reserves, the boundaries of the categories of reserves approved during the previous calculation should be plotted on the calculation plans, as well as the wells drilled after the previous calculation of reserves should be highlighted.

Calculation of reserves of oil, gas, condensate and components contained in them is carried out separately for gas, oil,. gas-oil, water-oil and gas-oil-water zones by types of reservoirs for each layer of the deposit and the field as a whole with a mandatory assessment of the prospects of the entire field.

Stocks of components contained in oil and gas, which are of industrial importance, are calculated within the limits of reserves calculation oil and gas.

When calculating reserves, the calculation parameters are measured in the following units: thickness in meters; pressure in megapascals (accurate to tenths of a unit); area in thousands square meters; the density of oil, condensate and water in grams per cubic centimeter, and gas - in kilograms per cubic meter (with an accuracy of thousandths of a unit); coefficients of porosity and oil and gas saturation in fractions of a unit, rounded to hundredths; recovery factors oil and condensate in fractions of a unit rounded to thousandths.

Reserves of oil, condensate, ethane, propane, butanes, sulfur and metals are calculated in thousands of tons, gas - in millions cubic meters, helium and argon - in thousands of cubic meters.

The average values ​​of the parameters and the results of the calculation of reserves are given in tabular form.

The organization was founded in December 2005. The project operator is KarakudukMunay 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 18.09.1995. The term of the contract is 25 years. The Karakuduk field is located in the Mangistau region, 360 km from the city of 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. Total population employees - about 500 people, of which citizens of the Republic of Kazakhstan - 97%. LUKOIL plans to invest up to 0.1 billion dollars in the development of the project until 2020.

1. GENERAL INFORMATION ABOUT THE DEPOSIT

Geographically, the Karakuduk deposit 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. Beyneu station is located 160 km from the deposit. The distance to the regional center Aktau is 365 km.

Orographically, the study area is a desert plain. The absolute elevations of the relief surface range from +180 m to +200 m. The study 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. winter period the minimum temperature reaches -30-35 o C. The average annual rainfall is 100-170 mm. The area is characterized by strong winds dust storms. In accordance with SNiP 2.01.07.85, the area of ​​the deposit in terms of wind pressure belongs to the III area (up to 15 m/s). Summer is dominated by NW winds directions, in winter - N-E. 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 region is poor and is represented by species typical of semi-desert zones. Rare herbaceous and shrubby vegetation is characteristic: camel thorn, wormwood, saltwort. The fauna is represented by rodents, reptiles (turtles, lizards, snakes) and arachnids.

There are no natural water sources in the work area. At present, the sources of water supply for the field drinking water, for technical needs and firefighting needs is the Volga water from the main water pipeline "Astrakhan-Mangyshlak", as well as special water intake wells up to 1100 m deep for Albsenomanian deposits.

The area of ​​work is practically uninhabited. 30 km east of the Karakuduk field, the Makat-Mangyshlak railway passes, along which the operating oil and gas pipelines Uzen-Atyrau-Samara and Central Asia-Center are laid, as well as the Beineu-Uzen high-voltage power line. Communication between the fishery and settlements carried out by vehicles.

1. 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 exploration and production drilling at the Karakuduk field, a stratum of Meso-Cenozoic deposits with a maximum thickness of 3662 m (well 20), ranging from Triassic to Neogene-Quaternary inclusive, was discovered.

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

Triassic system - T. The variegated terrigenous sequence of the Triassic age is represented by intercalation of sandstones, siltstones, mudstones and mudstone-like clays, colored in various shades of gray, brown to greenish-gray. The minimum thickness of the Triassic was recorded in well 145 (29 m) and the maximum in well 20 (242 m).

Jurassic system - J. With stratigraphic and angular unconformity, the underlying rocks of the Triassic are overlain by a sequence of Jurassic deposits.

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

Lower section - J 1. The Lower Jurassic section is lithologically complicated by intercalation of sandstones, siltstones, clays, and mudstones. The sandstone is light gray with a greenish tinge, fine-grained, poorly sorted, strongly cemented. Clays and siltstones are dark gray with a greenish tint. Argillites are dark gray with ORO inclusions. Regionally, the Yu-XIII horizon is confined to the Lower Jurassic deposits. The thickness of the Lower Jurassic deposits varies between 120-127m.

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

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

Bajocian Stage - J 2 c. 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. Clays are dark gray, black, dense in places. The productive horizons Yu-VI-Yu-X are confined to deposits of this age. The thickness is about 462m.

Bathian Stage - J 2 vt. 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 114.8m to 160.7m.

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

Callovian stage - J 3 k. The Callovian stage is represented by intercalation of clays, sandstones and siltstones. According to lithological features, three packs are distinguished in the composition of the stage: the upper and middle ones are clayey with a thickness of 20-30 m, and the lower one is an alternation of sandstone and siltstone layers with clay interlayers. The productive horizons Yu-I and Yu-II are confined to the lower unit 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, while some differentiation is observed: the lower part is clayey, the upper part is marly.

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

The section of the Volgian time is a stratum of argillaceous limestones with interlayers of dolomites, marls and clays. Limestones are often fissured and porous, massive, sandy, clayey, with uneven fracture and 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 fracture and matte luster. The thickness of the rocks ranges from 179m to 231.3m.

Cretaceous system - K. Deposits of the Cretaceous system are presented in the volume of the lower and upper sections. The division of the section into tiers was made on the basis of logging data and comparison with neighboring areas.

The lower section is K 1. Lower Cretaceous deposits are composed of rocks of the Neocomian superstage, Aptian and Albian stages.

Neocomian superstage - K 1 ps. The underlying Volgian deposits conformably overlie the thickness of 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, marls, and only at the top is a horizon of sands. The Barrem deposits are distinguished in the section by the variegated color of the rocks and are lithologically composed of clays with interbeds of sandstones and siltstones. Throughout the section of the Neocomian age, there are members of silty-sandy rocks. The thickness of the deposits of the Neocomian superstage ranges from 523.5 m to 577 m.

Aptian stage - K 1 a. Deposits of this age overlap the underlying ones with erosion, having a clear lithological boundary with them. In the lower part, the section is composed mainly 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. In terms of structural and textural features, 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. Sediments of the Cenomanian stage are represented by clays alternating with siltstones and sandstones. In terms of lithological appearance and composition, the rocks of this age do not differ from the Albian deposits. The thickness ranges from 157m to 204m.

Turonian-Senonian undivided complex - K 2 t-cn. In the lower part of the described complex, the Turonian stage is distinguished, composed of clays, sandstones, limestones, chalk-like marls, which are a good benchmark.

Above the section, there are deposits of the Santonian, Campanian, Maastrichtian stages, united in the Senonian superstage, represented in lithological terms by a thick layer of interbedded marls, chalk, chalk-like limestones and carbonate clays.

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

Paleogene system - R. Paleogene deposits are represented by white limestones, greenish-marl strata and pink silty clays. The thickness varies from 498m to 533m.

Neogene-Quaternary systems - N-Q. Neogene-Quaternary deposits are composed mainly of carbonate-argillaceous rocks of light gray, green and brown color and limestones - shell rocks. The upper part of the section is filled with continental sediments and conglomerates. The thickness of the deposits varies from 38 m to 68 m.

3.2. Tectonics

According to tectonic zoning, the Karakuduk deposit is located within the Arystan tectonic stage, which is part of the North Ustyurt system of troughs and uplifts of the western part of the Turan Plate

Based on the materials of seismic surveys MOGT-3D (2007) conducted by OJSC Bashneftegeofizika, the Karakuduk structure along the reflecting horizon III represents a brachianticline fold of sublatitudinal strike with dimensions of 9x6.5 km along a closed isohypse minus 2195m, with an amplitude of 40m. The angles of incidence of the wings increase with depth: in the Turonet - fractions of a degree, in the Lower Cretaceous -1-2˚. The structure along reflector V is an anticline broken by numerous faults, possibly some of which are non-tectonic. All major faults described below are traced along this reflector. The N-striking fold consists of two arches, contoured by isohypse minus 3440 m, identified in the area of ​​wells 260-283-266-172-163-262 and 216-218-215. According to the isohypse minus 3480m, the fold has dimensions of 7.4x4.9km and an amplitude of 40m.

The uplift on the structural maps along the Jurassic productive horizons has an almost isometric shape, complicated by a series of faults that divide the structure into several blocks. The most basic disturbance is the F 1 disturbance in the east, which is 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. The fault F 1 is inclined and shifts from west to east with depth. This violation was confirmed by drilling well 191, where part of the Jurassic deposits of about 15 m at the level of the Yu-IVA productive horizon is absent.

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

Description of work

The organization was founded in December 2005. The project operator is KarakudukMunay 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 18.09.1995. The term of the contract is 25 years. The Karakuduk field is located in the Mangistau region, 360 km from the city of 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).

Ministry Education and Science of the Republic of Kazakhstan

Faculty of Finance and Economics

Department of Economics and Management

D
discipline: Oil and gas project evaluation

SRS №1

Topic: Plan for the development of the strategically important Kashagan field on the shelf of the Caspian Sea

Performed:

3rd year 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 at an average of 3.3% per year, while world demand for oil as the main source of hydrocarbons is growing at 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 the production of GDP and in the consumption of hydrocarbons is constantly increasing. In this case, an increasing aggravation of the problems of hydrocarbon supply is expected.

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

Estimates by international experts show that if current trends continue, all the world's proven oil reserves will last only 40-50 years. The addition of KSCM oil resources to the world's proven reserves is a defining factor in global energy strategies. Kazakhstan should be ready for a flexible combination of strategies for the systematic transfer of oil production to the Caspian Sea and forcing certain 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 in the last 40 years. Refers to the Caspian oil and gas province.

The Kashagan field is located in the Kazakh 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, was discovered by Soviet geophysicists during 1988-1991 by prospecting seismic work. on the sea 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 originally identified in its composition in the period 1995-1999. received the names Kashagan East, West and South-West, respectively.

The dimensions of East Kashagan according to the closed isohypse - 5000 m are 40 (10/25) km, area - 930 km², uplift amplitude - 1300 m. km², average oil-saturated thickness - 550 m.

Kashagan West borders on East Kashagan along a submeridional structural ledge, which is possibly associated with tectonic disturbance. The dimensions of the reef uplift along the closed stratoisohypse - 5000 m are 40 * 10 km, the area is 490 km², the amplitude is 900 m. , the average oil-saturated thickness is 350 m.

Southwestern Kashagan is located somewhat away (to the south) from the main massif. The uplift along the closed stratoisohypse - 5400 m has dimensions of 97 km, area - 47 km², amplitude - 500 m.

Oil reserves of Kashagan fluctuate within a wide range of 1.5 - 10.5 billion tons. Of these, from 1.1 to 8 billion tons fall on the Eastern, up to 2.5 billion tons on the Western and 150 million tons on the South-West.

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

According to the project operator, total oil reserves are 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 cubic meters. 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%.

Appointed as the project operator in 2001 by partners: Eni, and created the Agip KCO company. The 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) have agreed to postpone the start of oil production from 2011 to the end of 2012.

Oil production at Kashagan should be up to 50 million tons per year by the end of the next decade. Oil production at Kashagan, according to ENI, in 2019 should reach 75 million tons per year. With Kashagan, Kazakhstan will enter the Top 5 of the world's 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, an oil pipeline and a gas pipeline with Karabatan will be built.

The development of the Kashagan field in the harsh offshore conditions of the North Caspian presents a unique combination of technological and supply chain challenges. These complexities are associated with ensuring production safety, solving engineering, logistical and environmental problems, which makes this project one of the largest and most complex industry projects in the world.

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

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

For the development and evaluation 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 shallow water and cold winters in the Northern Caspian, 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 shifts, offshore structures are installed on artificial islands. Two types of islands are envisaged: small "drilling" islands without personnel and large "islands with technological complexes" (ETC) with service personnel.

Hydrocarbons will be pumped through pipelines from the drilling islands to the ETC. The ETC islands will host process units for extracting the liquid phase (oil and water) from raw gas, gas injection units and energy systems.

In Stage I, approximately half of all gas produced will be injected back into the reservoir. The extracted fluids and sour gas will be pipelined ashore to the Bolashak OPF in the Atyrau region, where it is planned to treat the oil to commercial quality. Some volumes of gas will be sent back to the offshore complex for use in power generation, while some of the gas will meet similar needs of the onshore complex.

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

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


The low level of mineralization caused by the influx of fresh water from the Volga, combined with shallow water and winter temperatures down to -30C, causes the Northern Caspian to be covered with ice for about five months of the year. Ice shifts and the formation of furrows from the movement of ice on the seabed are serious restrictions on construction work.

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

The North Caspian region is an area where the supply of equipment important for the project is associated with certain difficulties. Logistical difficulties are exacerbated by access restrictions on 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 for navigation for about six months a year.

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

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 Russian system Transneft) and the eastern route (Atyrau to Alashankou) provide a connection to existing export transportation systems.

A possible southeast route depends on the development of the Kazakhstan Caspian Transportation System (KCTS), which could transport oil from Eskene West, where the Bolashak plant is located, to the new Kuryk terminal. The oil can then be transported by tanker to new terminal near Baku, where it would be injected 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 security environment. Since the formation of the first consortium in 1993, many environmental protection programs have been developed and implemented during the onshore and offshore oilfield operations. For example, Agip KCO attracted local companies to perform an environmental impact assessment (EIA) of its activities, including the construction of onshore and offshore facilities, main 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 research and monitoring of the state of the population of birds and seals are carried out annually. In 2008, a map of ecologically sensitive areas of the North Caspian region was published, which was created, among other things, on the basis of data collected by the consortium.

There are also problems with the disposal of sulfur. The Kashagan field contains about 52 trillion cubic feet of associated gas, most of which will be reinjected into the reservoir at offshore facilities to increase the oil recovery factor. In Stage 1 (Pilot Development), not all associated gas will be re-injected into the reservoir at offshore facilities. Part of it will be sent to an onshore complex oil and gas treatment plant, 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 commercial gas. gas. Stage 1 is expected to produce an average of 1.1 million tonnes of sulfur per year from sour gas treatment.
While the consortium plans to sell all of the sulfur produced, it may be necessary to temporarily store the sulfur. Sulfur produced at the Bolashak plant will be stored under closed conditions, isolated from the environment. Liquid sulfur will be poured into sealed containers equipped with sensors. The sulfur will be converted to pastelled form prior to sale, thus avoiding the formation of sulfur dust during crushing.

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

Between 2006 and 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 peak construction period for the Pilot Development Phase, more than 40,000 people were employed on the project in Kazakhstan. More than 80% of the workers were citizens of Kazakhstan - an exceptional figure for projects of this magnitude.

Infrastructure and social projects are important components of NCOC's corporate and social responsibility. According to the SRPSK, a significant part of the investment in the development of the field goes to the construction of social infrastructure facilities in the field of education, healthcare, sports and culture. Funds are evenly distributed between Atyrau and Mangystau regions, where production operations are carried out under the SRPSK.

Since 1998, 126 projects have been implemented in close cooperation with local authorities, 60 projects in the Atyrau region and 66 in the Mangistau region. A total of US$78 million was spent in Atyrau Oblast and US$113 million in Mangistau Oblast.

In addition, under the 2009 Sponsorship and Philanthropy Program, NCOC and Agip KCO supported more than 100 cultural, health, education and sports initiatives. Among them are the advanced training of doctors and teachers, seminars on intercultural education and environmental literacy in schools, the invitation of leading Russian surgeons to operate Atyrau children, the purchase musical instruments for the Aktau school and the purchase of medical equipment and ambulances for the hospital in Tupkaragan.

An important role is played by the protection of health and labor. The participants of this project will carry out systematic risk management in order to continuously improve the system of health, safety and environment and reach the level of world leaders in this indicator. All this is carried out in accordance with the requirements of the North Caspian Production Sharing Agreement, Kazakh and international legislation, existing industry standards and corporate directives.

All participants of the SRPSK undertake:

Carry out their activities, ensuring the protection of the health and safety of all employees directly or indirectly involved in these activities, the environment in which their production operations are carried out, as well as company assets.

Manage the activities of the consortium and the risks associated with it in accordance with the requirements of the North Caspian Production Sharing Agreement, Kazakhstani and international legislation and apply the best of existing industry standards in those matters that cannot be regulated by laws and regulations.

Promote the implementation of HSE principles in the company culture, where all employees and service providers will be jointly responsible for the implementation of 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, conduct certification of the HSE management system and constantly inform the Agent companies, the Authorized Body, all interested parties about the state of affairs in the field of HSE in order to continuously improve.

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

Implement systems and procedures to respond promptly and effectively to unplanned and unwanted events and regularly review them.

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

Conduct joint work from government bodies Republic of Kazakhstan and all interested parties in order to develop regulations and standards aimed at improving the safety of company employees and protecting the environment.

Apply a constructive approach in 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 charity projects are aimed at ensuring economic sustainability and welfare, supporting healthcare, education, culture and cultural heritage sports, as well as providing assistance to the poor who are eligible to receive such support, as well as being in line 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 their own contributions by the participants themselves, and must also demonstrate to the public their long-term sustainability. No support for political or religious organizations, projects cannot create unfair conditions for market competition, 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 a proactive measure in support of local communities.

Bibliography:

State Program for the Development of the Kazakh 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 to designed and reconstructed buildings and structures of the oil industry, and separate requirements are given in the relevant sections of these Standards.

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

• "General plans industrial enterprises»;
• "Fire safety standards for the design of buildings and structures";
• "Industrial buildings of industrial enterprises";
• “Gas supply. Internal and external devices»;
• "Constructions of industrial enterprises";
• "Auxiliary buildings and premises of industrial enterprises";
• "Rules for the installation of electrical installations (PUE)";
• "Water supply. External networks and facilities”;
• "Warehouses of oil and oil products";
• "Main pipelines";
• "Automobile service enterprises";
• "Sanitary standards for the design of industrial enterprises."

a) MASTER PLAN REQUIREMENTS

6.2. A field master plan scheme should be developed based on the database technological scheme(project) development of an oil field, taking into account the schemes for the development of the oil industry and the distribution of productive forces in economic regions and union republics.

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

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

6.4. The scheme of the master plan should provide for the placement of the mouths of oil, gas, injection and other single wells, clusters of wells, storage facilities, BPS, SU, UPS, CPS, VRP, CS, substations and other facilities, as well as utilities (roads, oil - and gas pipelines, water conduits, power lines, communications, telemechanics, cathodic protection, etc.), providing technological and production processes for the collection and transport of products oil wells taking into account the existing transport links in the area of ​​the capacities of the CPS, OTU, GBP, 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 scheme, it is necessary to consider:

• brigade and field form of organization of field exploitation in accordance with the “Regulations on the brigade for oil production ...” of the Minnefteprom;
• the possibility of expanding and reconstructing technological systems;
• carrying out technical measures to intensify the production processes of oil and gas production, collection, and transportation.

6.6. The master plan of enterprises, facilities, buildings and structures of the field development should be designed in accordance with the requirements of the norms "General plans for industrial enterprises" and others specified in the general part of this section, as well as the requirements of these Norms.

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

The placement of industrial and auxiliary buildings and structures in the zones must be carried out according to their functional and technological purpose and taking into account explosive, explosion-fire and fire hazard them.

6.7. Access and on-site railways and roads to facilities, buildings and structures should be designed in accordance with the requirements of the standards " Railways 1520 mm gauge”, “Roads”, “Instructions for the design of roads for oil fields in Western Siberia” of the Minnefteprom.

6.8. The sizes of sites for the construction of enterprises, objects of 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 comply with the values ​​\u200b\u200bspecified in the rules "General plans for industrial enterprises". The areas of oil and gas well sites should be taken in accordance with the "Norms of Land Acquisition for Oil and Gas Wells" of the Ministry of Oil and Gas Industry.

The width of the land strip for the construction of linear structures should not exceed those specified: in the "Norms of land acquisition for main pipelines", "Norms of land acquisition for communication lines", "Norms of land acquisition for electrical networks with a voltage of 0.4 - 500 kV", "Norms allocation of land for highways.

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

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

• for buildings that manufacturing process directly related to the extraction of oil from the subsoil (the mouth of oil and gas wells, metering installations), - once every 25 years;
• for CPS, BPS, gas compressor stations, separation plants, OTU, UPS, KNS and electrical substations - once every 50 years.

6.11. Arrangement objects oil fields should be located from neighboring enterprises at the distances indicated in Table 19, taking into account the possibility of cooperating with these enterprises in the construction of engineering networks and highways.

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

6.13. The smallest distances between buildings and structures of oil field 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 smallest distances between buildings and structures located on the central heating station should be taken according to table. 22.

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

The smallest distances between buildings and structures of sewerage systems should be taken according to Table. 23.

6.16. The smallest distances from warehouse buildings, sheds of open areas for storing cylinders with oxygen, acetylene, nitrogen and chlorine to buildings and structures with industries of categories A, B, C, E should be at least 50 m, to other industrial and auxiliary buildings should be at least less:

• with the number of cylinders 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 pcs., including no more than 400 cylinders filled with combustible gases.

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

2. Joint storage of cylinders with combustible gases and oxygen cylinders is not allowed.

6.17. Distances from fire heating devices (furnaces for heating oil, oil products, gas, water and anhydride), located outside the building, to other technological apparatus, buildings and structures of the workshop or installation, which include the furnace, as well as to racks, with the exception of technological pipelines connecting fire heating devices with other technological devices must be at least those indicated in Table. 24.

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

a) between production, auxiliary and auxiliary buildings, installations, tanks and equipment - in the light between the outer walls or structures of structures (excluding metal stairs);

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

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

d) for on-site motor roads - up to the edge of the carriageway;

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

f) during reconstruction existing businesses or technological installations in case of impossibility of exact observance specifications without large material costs, in agreement with the organization approving the project, deviations in terms of gaps up to 10% are allowed.

6.19. External technological installations are recommended to be placed on the side of the blank wall of the production building.

In the case of placing open installations with production facilities of 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 should be located taking into account the requirements of No. 2.90.

Between outdoor installation and the building is allowed to have an overpass for the pipelines of this installation.

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

6.21. A ground emergency (drainage) tank intended for draining flammable liquids and combustible liquids from furnaces should be protected by a fireproof wall or dike at least 0.5 m high and placed at a distance of at least 15 m from the furnace platform.

An underground emergency (drainage) tank should 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 the CPS, OTP, tank farms, warehouses for flammable liquids and combustible liquids, BPS, UPS and CS should have a fence 2 m high with gates 4.5 m wide.

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

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

6.23. The area around the BPS 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 technological facilities of the DNS with a height of 30 m or more must be fenced with a 1.6 m high non-barbed wire fence.

The distance from the flare stack to the fence, as well as between the flare stacks, should be taken according to the heat engineering calculation, but not less than 30 m.

The area around the candle for gas discharge at the CS, clusters of wells, single gas wells is not fenced.

6.24. Placement of gas condensate tanks (separators, flame 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. Above-ground laying of gas pipelines from installations to the flare pipe should be provided on fireproof supports.

6.26. The territory of the mouths of a single well or a cluster of wells should be fenced with an earthen rampart 1 m high with a curb width along the top of the rampart 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 the sites of the facilities. On land plots not occupied by buildings and structures, the natural relief should be preserved and vertical planning should be provided only in cases where it is necessary to drain surface water and lay engineering 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 single system with their placement in the allotted technical lanes (corridors).

6.31. The method of laying engineering networks (ground, above-ground or underground) should be adopted taking 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 technological 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 (receiving 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 industries of categories A, B, C, E for fire danger - 20 m;
• to tanks with flammable liquids - 40 m;
• to tanks with flammable liquids and liquefied combustible gases - 60 m.

6.34. Receiving wells of reservoirs and wells with hydrants should be located at a distance of no more than 2 m from roadsides, and if they are located at a distance of more than 2 m, they should have access roads to them with a platform of at least 12 × 12 m.

6.35. Fire tanks or reservoirs should be placed according to the conditions of their service of objects located within a radius of:

• in the presence of autopumps - 200 m;
• in the presence of motor pumps - 100 - 150 m, depending on the type of motor pump.

To increase the radius of service, it is allowed to lay dead-end pipelines from tanks or reservoirs with a length of not more than 200 m and taking into account the requirements of clause 6.58 of these Norms.

6.36. Roads at the sites of central oil, gas and water collection and treatment sites should be designed with roadsides raised above the planning surface of the adjacent territory by at least 0.3 m. get on the road (device of ditches, etc.).

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

When developing oil deposits are divided into four stages:

I - increasing oil production;

II- stabilization of oil production;

III- declining oil production;

IV - late stage of deposit exploitation.

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

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

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

The third stage - falling 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 by the methods used at the second stage, as well as by thickening the water injected into the reservoir.

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

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

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

2. Ways of operating wells.

There are several types of well operation:

Fountain

gas lift

Deep and others

The operation of producing wells is understood as their use in technological processes of lifting from the reservoir to the surface of the reservoir products (oil, condensate, gas, water).

Methods of well operation and periods of their use are substantiated in the design documents for the development of the field and are implemented by oil and gas producing organizations according to the plans of geological and technical measures.

Wells should be operated only if they contain tubing. The depth of descent and standard sizes of downhole production equipment are established by the plans for commissioning wells or plans for repair work in accordance with technological and technical calculations in accordance with current regulatory and technical documents.

The development project is a comprehensive document that is an action plan for the development of a field.

The source 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 that saturate them.

Using these data, the reserves of oil, gas and condensate are determined. For example, the total in-place oil reserves of individual reservoirs are calculated by multiplying the area of ​​oil-bearing capacity by the effective oil and saturation thickness of the formation, the effective porosity, the coefficient of oil accumulation, the density of oil at surface conditions, and the reciprocal of the volumetric coefficient of oil at reservoir conditions. After that, commercial (or recoverable) oil reserves are found by multiplying the total geological reserves by the oil recovery factor.

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

In the design hall, a field development system is selected, the iodine of which is the determination of the required number and placement of wells, the sequence of their commissioning, information on the methods and technological modes of well operation, recommendations on regulating the balance of reservoir energy in deposits.

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

Wells are placed on the area of ​​the deposit evenly and unevenly. At the same time, uniformity and unevenness of two types are distinguished: geometric and hydro-gas-dynamic. The wells are geometrically evenly placed in the nodes of the correct conditional grids (three-, four-, five- and hexagonal) applied to the deposit area. Hydro-gas-dynamically uniform is such a placement of wells, when each has the same reserves of oil (gas, condensate) in the area of ​​their drainage.

The layout of wells is chosen 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 rate of construction of field facilities, the availability of drilling rigs, etc. Apply "thickening" and "creeping * - schemes of drilling wells. In the first case, wells are first drilled along a sparse grid, over the entire area of ​​the deposit, and then it is “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, wells are drilled in other areas.

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

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

The establishment of technological regimes for the operation of producing wells is reduced to planning the rate of oil (gas, condensate) withdrawal. Well operation modes change over time depending on the state of reservoir development (the position of the oil-bearing gas oil contour, well water cut, technical condition of the production string, well operation method, etc.).

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

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

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

Mining;

Discharge;

Special.

Production wells, having fountain, pumping or gas lift equipment and are intended for the extraction 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.

With the flowing method, liquid and gas rise along the wellbore from the bottom to the surface only under the action of reservoir energy, which the oil reservoir possesses. This method is the most economical, as it is typical for newly discovered, energetically not depleted deposits. When maintaining reservoir pressure by pumping water or gas into the deposit, in some cases it is possible to significantly extend the period of well flowing.

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

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

In pumping wells, the liquid is lifted to the surface by means of pumps lowered into the well - rod pumps (SHSN) or submersible pumps (ESP). In the fields, other methods of operating wells are also used.

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

The reserve fund of wells is provided for the purpose of involving in the development of individual lenses, wedging zones and stagnant zones that are not involved in the development of the wells of the main fund within the contour of their placement. The number of reserve wells is substantiated in the design documents, taking into account the nature and degree of heterogeneity of productive formations (their discontinuity), the density of the grid of wells of the main stock, etc.

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

Observational for periodic monitoring of changes in the position of WOC and GOC, GWC, changes in the oil-water-gas saturation of the formation during the development of the deposit;

Piezometric - for a systematic change in reservoir pressure in the aquifer, in the gas cap and in the oil zone of the reservoir.

The number and location of control wells is determined in the design documents for development.

Appraisal wells are drilled at fields (deposits) being developed or being prepared for trial operation in order to clarify the parameters and mode of operation of the reservoirs, identify and clarify the boundaries of isolated productive fields, assess the recovery of oil reserves in individual areas of the deposit within the boundaries of reserves of category A+B+C.

Special wells are intended for production of technical water, discharge of industrial waters, underground gas storage, liquidation of open fountains.

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

Absorbing wells designed for injection of commercial water from developed fields into absorbing formations.

Wells - backups are provided for the replacement of production and injection wells actually liquidated due to aging (physical wear) or for technical reasons (as a result of accidents during operation). The number, placement and procedure for commissioning backup wells as submitted by oil and gas production departments is justified by feasibility studies in projects and updated development projects and as an exception in technological schemes, taking into account possible oil production from backup wells, in multilayer fields - taking into account the possible use instead of them returnable wells from downstream facilities.

Mothballed wells- non-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 regulations.

The operational well stock is subdivided into wells that are in operation (operating), those that are in the overhaul after operation and awaiting overhaul, and those that are in the development and development after drilling.

Operating (operating) wells include wells that produce products in the last month of the reporting period, regardless of the number of days of their work in this month.

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

Post-operational wells that are under overhaul include those wells that have retired from the operating ones, on which repair work was carried out at the end of the reporting month. Wells awaiting overhaul include wells that have been idle for a calendar month.

Test questions:

1. How many stages is the development of deposits divided into?

2. What is meant by exploitation of production wells?

3. What is a development project?

4. On what parameters does the operation method depend?

Literature

1. Askerov M.M., Suleimanov A.B. Well Repair: Sprav, allowance. - : Nedra, 1993.

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

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

4. Brown SI. Labor protection 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 work of cement stone in a well, Nedra, 1990.

7. Varlamov P.S. Testers of layers of multi-cycle action. - 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 in the process of drilling. RD 39-0147716-102-87. VNIIpromgeofizika, 1987.

Topic: Methods for operating oil and gas wells.

Plan 1. Fountain method of operation.

2. Flowing conditions and possible methods for its extension.





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