Waterflooding of oil reservoirs. Types of waterflooding Types of waterflooding of oil fields

The main goal of regulating the process of developing an oil deposit is to ensure uniform movement of OWC or GOC from the water-bearing or gas-bearing contours. It is precisely the uniform development of oil reserves that achieves the overall technological safety of all structures in the chain “production - collection - preparation - transportation”.

The uniformity of oil flow into the well is ensured by the constant thickness of the exploited reservoir formation and the uniformity of its structure, which is manifested in the stability of its filtration and capacitance properties. In such a conditionally stationary mode, the filtration rate of liquid moving towards the well at a constant flow rate increases. Thus, when moving a unit volume of fluid towards the well, energy costs (pressure drop) per unit path length (pressure gradient) will continuously increase. Under these conditions, knowledge of the distribution of the energy potential of the deposit, which is reflected using isobar maps, is paramount, since it allows us to draw up a project for the rational placement of single or cluster drilling sites. However, obtaining reliable information on the energy potential of a deposit is possible only with a high degree of geological knowledge, which is achieved by a staged approach to the development of the deposit.

In this regard, the issue of choosing a reservoir development scheme and, in particular, well clustering schemes is fundamentally important. It is known that the larger the well pads, the more expensive it is to drill a well, since large well wastes are required. Modern drilling technologies make it possible to reach waste 2-4 km or more vertically. At the same time, the cost of communication corridors (roads, backfill sites, power lines, oil collections, water pipelines, water treatment facilities) is reduced, which leads to a decrease in capital investments and an increase in the degree of environmental safety of the entire fishery as a whole. First of all, land intensity indicators, technogenic loads on all elements of ecosystems, and environmental risks are reduced by reducing the size of communications and especially the organization of a system for collecting produced water at well pads.

Construction of the wellheads of single production oil wells. When constructing wellheads, depending on the method of operation, the following must be provided:

estuary area;

1) platform for inventory receiving walkways;

2) a site for a repair unit;

3) anchors for fastening the guy ropes of the repair unit;

4) foundation for a rocking machine;

5) control station for an electric centrifugal pump (ECP) or pumping machine;

6) ground equipment for operating wells with hydraulic piston pumps;

7) transformer substations;

8) diking the territory of wellheads;

10) sewer collection tank with inventory pallets.

If necessary, the following will be provided at the wellhead site:

1) units for launching treatment devices for flow pipelines;

2) a device for pumping demulsifiers, inhibitors, etc.

Arrangement of well clusters. A well cluster is a special area of ​​a natural or artificial section of a field territory with wellheads located on it, remote from another cluster or a single well at a distance of at least 50 m, as well as technological equipment and operational structures, utilities, equipment for underground well repair, household and office premises. The construction of enlarged well clusters imposes a number of restrictions on oil production methods, in particular on the placement of sucker rod pumps.

The total flow rate of one cluster of wells during its design should be taken no higher than 4000 m 3 /day. (for oil), and the gas factor is no more than 200 m 3 / m 3. Depending on the method of well operation, the following technological structures should be provided at the well cluster:

1) wellhead sites of oil and injection wells;

2) measuring installations;

3) process pipelines;

4) blocks for supplying demulsifiers, inhibitors, etc.;

5) gas distribution blocks (combs);

6) sites for a repair unit;

7) anchors for fastening the guy ropes of the repair unit;

8) foundations for pumping machines;

9) control stations for ESP and SRP;

10) transformer substations;

11) platforms for inventory receiving walkways;

12) collection container;

13) block for pumping water into injection wells and water distribution comb blocks.

The paper considers two options for organizing a cluster oil production system. The first one presents a project of three well clusters of 19 each. with a total number of 57 with the traditional amount of withdrawal from the bottom of the wells. There is no water management system at the well pad, and the pressure maintenance system is made of fiberglass materials that prevent the development of corrosion.

The second version of the project involves the construction of one enlarged well pad with the same number of wells, but with a maximum well bottom reach of 2 km. The well pad structures include a water treatment unit designed to process 171 m3 with local injection of water into the formation. The total cost of the water drainage system is 950 thousand rubles, and the cost of a 7.5 km long water pipeline in the first option is 13,220 thousand rubles.

The calculation results indicate that in addition to the gain in capital investments (8% of the cost of costs), the length of communications is reduced by 45%, and the corridors do not contain aggressive reservoir fluids, which is a guarantee of the environmental safety of the field. In the second option, there is no pumping of produced water from well pads to oil separation points and back, which results in energy savings of about 520 thousand kWh/year.

The data presented convincingly indicate the advisability of consolidating well pads when choosing a reservoir exploitation scheme, which leads to environmentally preferable options for oil production.

With all methods of operating wells, liquid and gas rise to the surface through special pump and compressor pipes (tubing), which are lowered into the wells before the start of operation. Their diameter is selected depending on the well flow rate. One of the factors complicating the process of well operation is paraffin deposits on the walls of pipes, wellhead equipment and flow lines.

The construction of wells with large waste limits the use of sucker rod pumps (SRP), and also contributes to the development of complications associated with pipe abrasion, which can lead to frequent accidents, especially at tubing connections.

To avoid abrasion of pipes, special high-strength couplings are used, which are installed in places where the wellbore is bent, and when choosing pumping equipment, preference is given to ESPs and hydraulically driven pumping systems in a closed oil and gas collection system. At the same time, such technologies (hydraulic pump systems) make it possible to supply inhibitors to prevent corrosion and paraffin formation and make it possible to combine the working fluid preparation technology with oil preparation technology, which reduces the cost of constructing power lines and reduces the likelihood of environmental risk.

The further system of oil treatment facilities, water discharge and injection is carried out depending on the distribution of reserves over the deposit area and section in individual fields, production rates and the degree of water cut and gas saturation of oil, pressure values ​​at the wellhead, location of the number of well clusters, engineering and geological construction conditions structures, environmental restrictions.

Facilities for collecting and transporting well products must provide:

a) sealed collection and transportation of well products to central collection points, uncompressor transportation of gas from the first separation stage to central collection points, gas processing plants, for own needs and other consumers;

b) measuring the production of individual wells and pads;

c) separation of gas from oil;

d) accounting for the total production of all wells;

e) use of the end sections of oil-gathering pipelines as they approach the central pumping station and separators for preliminary preparation for the separation of well production;

f) preliminary dehydration of oil, carried out according to the quality of the discharged formation water;

g) heating of well products when it is impossible to collect and transport them at normal temperatures.

Traditionally, most fields have developed the following systems for collecting, preparing and transporting oil (Fig. 4.4, according to Salamatova, 2004). The gas-liquid mixture from oil-producing wells is supplied to a group metering unit (GMU), where periodic measurements of liquid and gas flow rates of each well are carried out automatically in a metering separator.

Measuring installations. The most commonly used measuring devices are “Sputnik”, “Bius” and other modifications. The number of installations and their placement should be determined by technical and economic calculations. At the sites of metering installations, if necessary, units for injection of a demulsifier reagent and a corrosion inhibitor should be provided.

After the gas treatment unit, which is installed on each pad or individual well, the mixture is transported through oil-gathering pipelines to a collection point (SP) or to a booster pump station (BPS) for subsequent preparation. There may be two collection options: separate collection of watered and conditionally water-free oil, in connection with which two collectors with a length of up to several kilometers are laid from each gas treatment unit.

The collection points to which oil is supplied are divided into central (CPS), CPS and integrated collection points (KSP).

At the central processing plant, crude oil supplied from the gas treatment unit undergoes a full processing cycle, which includes two- or three-stage degassing using separators and bringing the oil to the required vapor pressure according to saturated vapor pressure. In addition, oil is dehydrated and desalted to marketable standards. The gas obtained after oil separation is purified from the dropping liquid and supplied for disposal, processing or other purposes. The gas of the first and second stages is transported under its own pressure, and the gas of the final stage must be compressed for use.

Produced waters are separated from crude oil at an oil treatment unit (OPF), which is part of the central processing plant. At the oil treatment plant in a special preliminary discharge tank, oil settles, the oil emulsion is heated in tube furnaces, oil is separated from water and desalted. After this, the oil enters the commercial oil reservoir and is subsequently pumped into the main oil pipeline. If commercial oil does not reach standard water and salt content, it automatically flows from special sealed settling tanks to a separator-divider, from which it is sent back to the oil treatment plant.

Oil treatment units (OPU). Oil treatment plants are an integral part of a single technological complex of facilities for the collection and preparation of well products and, as a rule, are located at the central processing plant. The technological complex of oil treatment facilities must provide:

Deep oil dehydration;

Desalting;

Reduced vapor pressure of commercial oil;

Reception of substandard oil and its supply for re-treatment;

Reuse of reagent and heat from drainage water by returning it to the beginning of the process.

The technological scheme of the oil preparation process should ensure:

Complete sealing of the oil preparation process;

Required quality of commercial oil;

Flexibility and maneuverability of the installation;

Possibility of releasing equipment and pipelines during repairs and emergency stops;

Use of heat produced from wells.

Reservoir parks. For the oil treatment facility, reserves of raw materials (well products; products coming from the booster pumping station or processing unit) and commercial (treated) oil should be provided:

For raw materials - daily volume supplied to the treatment unit;

For commercial oil - the volume of daily productivity of the oil treatment unit for commercial oil during pipeline transport;

For receiving formation and waste waters;

For emergency releases.

Standard steel tanks of various volumes, such as RVS, are most often used as storage tanks.

To discharge paraffin deposits from cleaning (steaming) of tanks, earth storage pits are provided. The total capacity of storage barns should be determined based on the collection and storage of paraffin deposits throughout the year. The internal surfaces of metal tanks and devices must have an anti-corrosion coating.

Gas treatment units (GTU). Depending on the direction of use of petroleum gas and the conditions of its transportation to consumers, the following methods of its preparation should be used:

Drying gas from moisture using absorption method;

Extraction of heavy hydrocarbons with dehydration of gas from moisture by low-temperature condensation (LTC).

When transporting a mixture of gases from the first and final separation stages without compressor, the technological scheme for their preparation should provide for:

When transporting gas in a two-phase state and under conditions leading to the formation of crystalline hydrates - compression of the gases of the end separation stages to the pressure of the first separation stage and joint drying of the gases of the first and end separation stages from moisture using the absorption method;

When transporting gas in a single-phase state - compressing the gases of the final separation stages to the pressure of the first separation stage, drying it from moisture or extracting heavy hydrocarbons from the gas of the first stage or a mixture of gases of the first and final separation stages using the NTK method with glycol injection.

The hydrocarbon condensate released during gas preparation is sent either to commercial oil, if this does not lead to an increase in the pressure of saturated oil vapors above the standard, or to oil before the first separation stage.

Booster pumping stations (BPS). In cases where the distance from the well clusters to the central pumping station is large, and the wellhead pressure is not enough to transport fluids, a booster station is constructed. Their main task is to provide additional energy to the liquid for transportation to the central station.

The technological complex of the booster station facilities must provide:

The first stage of oil separation with preliminary gas selection;

Preliminary dehydration of oil (if necessary);

Heating of well products (if necessary);

Transportation of gas-saturated oil to the central processing plant;

Compressor-free transportation of stage I petroleum gas to central processing plant, gas processing plant, etc.;

Purification of formation water in sealed apparatuses at the pressure of the first separation stage at the natural temperature of the raw materials entering the booster station;

Transportation in the presence of preliminary discharge of prepared formation water into the reservoir pressure maintenance system (RPM);

Obtaining water from water separators with a quality that ensures its injection into productive formations without additional preparation;

Accounting for oil, gas and prepared formation water;

Injection of chemicals (inhibitors, demulsifiers).

The CPS includes the following main technological and auxiliary structures:

Gas pre-selection block;

Oil separation unit;

Pumping unit (with buffer tank);

Unit for preliminary dehydration and purification of produced water;

Emergency tank block;

Oil metering unit;

Gas metering unit;

Water metering unit;

Air compressor unit for powering control and automation devices;

Well production heating unit (if necessary);

Reagent management unit for reagent injection before the first separation stage;

Unit for injection of inhibitors into gas and oil pipelines;

The drainage tank is underground.

The BPS must be equipped with emergency horizontal process tanks designed for the operating pressure of separation. The total volume of the containers must ensure that the maximum volume of liquid supplied to the booster station is received within two hours. DNS are designed as block, automated, factory-made ones, as a rule, without permanent maintenance personnel.

The construction of a booster station is also justified by the fact that the industry does not produce pumping equipment that allows pumping mixtures with a high content of gases (this is due to the limiting influence of cavitation processes). Therefore, at the booster station in front of the pump, partial gas separation is carried out using first-stage separation. The separated gas as a result of reduced boiling is supplied for disposal, most often to a combustion torch, or for use for local needs. Oil and water with dissolved remaining gas enter the second stage separators - CPS and OPF.

Flare system for emergency combustion of gas booster station. Petroleum gas is sent to the flare system, which cannot be accepted by facilities preparing for transportation due to their shutdown for repairs or in an emergency, as well as gas from purging equipment and pipelines

The diameter and height of the torch are determined by calculation, taking into account the permissible concentration of harmful substances in the ground layer of air, as well as the permissible thermal effects on people and objects. The height of the pipe must be at least 10 m (for gases containing hydrogen sulfide - at least 35 m. The gas speed at the mouth of the flare trunk must be taken taking into account the possibility of flame separation, but not more than 80 m/s.

The torch must be equipped with automatic remote ignition and an independent supply of fuel gas to the ignition device.

To capture condensate and moisture, there must be a container (condensate collector) in front of the flare pipe, which is supposed to be emptied as the BPS pumps fill up.

Central collection points (CPC) are a universal technological facility where the produced fluid is separated into target components - commercial oil, gas and waste water. The latter is purified to a level that meets the necessary requirements and introduced into the RPM system or, without purification, into special absorption wells for wastewater disposal.

The technological complex for the preparation of well products at the central processing plant must ensure the following processes:

a) reception and preliminary separation of incoming well production:

b) reception and accounting of products coming from nearby wells;

c) oil preparation;

d) preparation and disposal of reservoir and industrial wastewater, including storm water;

e) reception and accounting of commercial oil;

f) reception and preparation of gas for transportation;

g) supply of commercial oil to mainline transportation facilities.

Spilled liquid and precipitation must be collected in a special container. External areas for installation of technological equipment are constructed with a concrete coating and must be 15 cm above the planning level of the ground, and their slopes to ensure drainage of rainwater must be at least 0.003°. In case of a possible spill of flammable liquids, the sites should be fenced with a concrete side with a height of at least 15 cm.

The areas of furnaces and heating units for oil and petroleum products should be fenced with a solid wall, earthen rampart or curb stone at least 0.5 m high.

The level of noise and vibration of equipment installed in premises and open areas must not exceed the maximum permissible sanitary standards. When forced to use high-noise units, the following should be provided:

a) installation of noise silencers;

b) remote control;

c) soundproof observation booths.

Recently, in fields, especially small ones, complex collection points (CSP) or their various modifications, called autonomous units (AU), have been actively introduced.

PCBs are a technological unit where, unlike the BPS, not only the first stage of separation is carried out, but also the dehydration and desalting of oil to marketable condition. The technological unit also contains installations for purifying produced water and supplying it to the pressure maintenance plant. For these purposes, the CSP includes the PN and treatment facilities. Thus, oil supplied from the CSP to the central processing station does not require demulsification and, after its final degassing, is delivered to the consumer.

AU include surface well equipment (wellhead equipment, control station for supplying electricity to power pumps from a diesel power plant) and a technological unit for separating the gas-liquid mixture, as well as preparing the working fluid for pumping it to the RPM.

This technology is patented in the Russian Federation under No. 209547 “Development and operation of small oil fields and an autonomous installation for its implementation.” This technical solution is characterized by the following features:

Oil production is carried out by hydraulic piston pumps;

The technological block of the injected liquid is simultaneously used for oil preparation;

The source of electricity is a stationary power plant with a diesel generator DGA-800, operating on APG;

For drilling priority wells, a mobile mobile diesel power station 5A36 is used, which is subsequently used as a backup source.

The advantage of this technology is that the source of electricity is low-pressure APG of any composition. Energy is supplied via overhead lines to step-down substations and further to sludge plants (pumps), oil and liquid transportation equipment for reservoir pressure maintenance, central pumping station operation, water supply, domestic needs and other purposes.

In addition, APG, after drying in gas separators, is used as fuel in furnaces for heating oil and boiler houses operating on both gas and fuel oil. Boiler rooms are necessary to heat water, which is used as a coolant to maintain the required temperature of oil in tanks and residential villages.

The presence of a reserve fleet of tanks, including emergency ones, is an indispensable attribute of all technological schemes for collecting, transporting and treating oil. The tanks are a fairly powerful source of atmospheric pollution due to the evaporation of hydrocarbons, despite their sealed design.

Oil and gas pipelines. The system for collecting and transporting oil well products includes:

1) flow pipelines that ensure the collection of well production to the gas treatment plant;

2) oil and gas collection pipelines (collectors) that ensure the collection of well products from metering installations to points of the first stage of oil separation, booster pumping station or central pumping station;

3) oil pipelines (collectors) for transporting gas-saturated or degassed watered or anhydrous oil from oil collection points and booster pumping station to the central processing station;

4) oil pipelines for transporting commercial oil from the central pumping station to main oil transport facilities;

5) gas pipelines for transporting oil gas from oil separation plants to gas treatment plants, compressor stations, central pumping stations, gas processing plants and the own needs of industrial enterprises;

6) gas pipelines for transporting gas from the central pumping station to the main gas transportation facilities.

To protect pipelines from internal corrosion when transporting gas-liquid mixtures, the following should be provided:

Formation of a flow structure that prevents phase separation and liquid release;

Introduction of corrosion inhibitors;

Internal protective coating of pipes.

To protect pipelines from soil corrosion, an insulating coating and electrochemical protection are provided.

To collect condensate on gas pipelines transporting wet petroleum gas, condensate collectors are built, which are located in the lowest places of the terrain along the gas pipeline route.

Reagent input units. Reagent injection units at oil and gas collection and transportation facilities and structures include:

Block for dosing and supplying demulsifiers;

Block for dosing and supplying inhibitors;

Chemical supply unit;

Warehouse for storing chemicals.

Installations for preliminary discharge of formation waters (UPS). Facilities for preliminary separation of well production are considered as an integral part of a single technological complex of facilities for the collection, transportation, and preparation of oil, gas and water. The process flow diagram must provide:

Preparation of the oil emulsion for separation before entering the “settling” devices;

Separation of gas from liquid with preliminary gas selection;

Preliminary dehydration of oil to a water content of no more than 5-10% (mass).

To prepare the oil emulsion for separation, a demulsifier reagent is supplied at the end sections of the oil and gas collection (before the first stage of oil separation).

The process of preliminary dehydration of oil is provided when the water cut of the incoming product is at least 15-20% and is carried out, as a rule, without additional heating using demulsifiers that are highly effective at moderate and low temperatures.

Preliminary dehydration of oil is carried out in devices for the joint preparation of oil and water. The discharge of formation water from oil preliminary dehydration devices is carried out under residual pressure, ensuring its supply to the receiving pumping stations of the waterflooding system.

Compressor stations (CS). Compressor stations can be independent objects of field development or be part of a complex of technological structures of the central processing plant and are intended for transporting oil gas to gas processing plants and other consumers, for compressing gas as part of gas preparation facilities for transportation and in the gas-lift oil production system. The gas supplied to the compressors must be cleaned of mechanical impurities (dust, scale, iron oxides, etc.) and of droplets (oil, water, hydrocarbon condensate) in accordance with the requirements of the technical specifications for the equipment.

To remove gas from the internal cavity of a piston compressor, a gas discharge plug must be provided on the receiving gas pipeline of each compression stage of the compressor between the shut-off valve and the cylinder with the installation of shut-off valves on it. The candle must be placed in places that provide safe conditions for gas dispersion. In this case, gas discharge into the aerodynamic shadow zone of the compressor station building is not allowed. The height of the candle should be determined based on the results of gas dispersion calculations, but not less than 5 m from the ground surface.

Flare system CPS. The CPS flare system is provided for the following types of discharge of flammable gases and vapors:

Permanent - from installations for the regeneration of sorbents, stabilization (weathering) of hydrocarbon condensates, etc.;

Periodic - when emptying installations or individual devices before steaming, purging, repair, as well as during emergency shutdown and commissioning;

Emergency - when released from safety valves or other emergency release devices.

The flare system, as a rule, should include:

Common flare header;

Gas pipelines from individual structures and CPS facilities to the common flare header;

Separators;

Condensate collectors;

Torch barrel.

The height and location of installation of flare trunks should be selected depending on the topography of the site, the location of surrounding agricultural lands and residential settlements, the intensity of the prevailing wind direction, the requirements of fire safety standards and the results of calculations for thermal stress at the base of the flare and the dispersion of harmful substances contained in combustion products into the atmosphere.

The minimum height of flare shafts is assumed to be 20 m if the discharges do not contain hydrogen sulfide. If hydrogen sulfide is present in the waste gases, the flare height must be at least 30 m. To burn gas with a hydrogen sulfide content of more than 6% by weight, a special flare system must be provided.

Flare shafts must be equipped with:

a) remote flare ignition system;

b) constant burning burners (pilot burner);

c) a labyrinth seal (gas-static seal) with a torch diameter of 100 mm or more.

Structures for gas-lift oil production. The gas lift production scheme (compressor or non-compressor gas lift, gas lift mode - continuous, periodic) is organized taking into account the requirements for raw materials, gas injection volumes and injection pressure, commissioning of well stock by year and other technological requirements.

Gas discharge from equipment and gas pipelines must be carried out through outlet lines to the spark plug. The height of the gas discharge candle must be at least 5 m.

Gas pipelines along the territory of a well cluster should be laid underground to a depth of at least 0.8 m. In the above-ground method, gas pipelines should be laid in protective cases made of steel pipes, ensuring safe maintenance of the Christmas tree.

For fields where well production contains hydrogen sulfide and other harmful impurities, the use of gas containing these impurities for gas lift is not allowed.

Requirements for the master plan. The general plan of the field is developed on the basis of the data of the technological scheme (project) for the development of the oil field and is drawn up on maps of land users, usually on a scale of 1:25000, taking into account the requirements of land, water and other legislation 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.

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, GZU, BPS, SU, UPS, KNS, VRP, CS, 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 transport connections existing in the area, the capacities of the central processing plant, oil treatment plant, oil refinery, and the direction of external transportation oil, gas and water, sources of supply of electricity, heat, water, air, etc.

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

Form of organization of field exploitation;

Possibility of expansion and reconstruction of technological systems;

Carrying out technical measures to intensify production processes of oil and gas production, collection, and transportation.

Planning solutions of the master plan are 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 carried out according to their functional and technological purpose, taking into account explosion, explosion and fire hazards.

The dimensions of sites for the construction of enterprises, facilities, buildings and structures are determined based on the conditions for the placement of technological structures, utility structures and utilities, taking into account the requirements of fire safety and sanitary standards.

When locating enterprises, facilities, buildings and structures for oil production on coastal sections of rivers and other bodies of water, the planning marks of sites for their construction 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 pumping stations, gas compressor stations, separation plants, oil treatment plants, oil pumping stations, pumping stations and electrical substations - once every 50 years.

As a result of the analysis of modern approaches to the operation of oil fields, the following can be noted.

Environmental protection measures and EIA elements are present in regulatory documents for field development. However, the current regulatory framework does not reflect changes in environmental legislation, new trends in environmental management, economics, resource management and social changes.

Design studies do not sufficiently use the experience of greening in the development of oil fields of leading Russian companies and the innovations of foreign companies.

As a rule, with the established practice of interaction between field development participants at various stages, environmental problems are resolved as they arise. Modern principles of natural resource development, in addition to an integrated approach, require preventive identification and solution of such problems.

Environmental problems that arise at all stages of field development have a fairly long history. Almost 50 years of experience in the exploitation of many fields allows us to consider them typical, but not inevitable. In many ways, this situation can be explained by a pattern - the more inaccessible and remote the field is located, the less stringent environmental restrictions are imposed on it and the greater the likelihood of causing environmentally significant damage.

The solution to most environmental problems that require significant capital investments (decommissioning of wells, storage pits, land reclamation, etc.) must be carried out in a timely manner and not postponed indefinitely.

The composition of structures and methods of operating oil fields are sources of impact on environmental protection, regardless of the design features of structures and the volume of oil produced, therefore, from an environmental point of view, a fundamentally new concept of design work is necessary.

When designing and implementing field development, there is no practice of conducting detailed consultations with all interested organizations and individuals, which leads to the formation of many social and environmental problems in the later stages of oil production. A timely solution to these problems is economically and environmentally more justified.

In the process of environmental support of economic activities, little attention is paid to the creation of environmental information databases, including, if possible, data on all types of impacts on environmental protection during the development of the field.

Types of oil flooding

Contour flooding

Figure 2.1 – Scheme of natural flooding:

1 - production wells; 2 - injection wells

The wells are located in the aquifer-bearing part of the formation (Figure 2.1). The use of a contour development system is possible when the oil-water contact can move under achievable pressure drops. In this case, the impact on the formation is carried out through a system of injection wells located beyond the outer oil-bearing contour. The injection line is located approximately 300-800 m from the oil-bearing contour to create a more uniform impact on it, prevent the formation of flood tongues and local

Contour flooding is advisable:

With good hydrodynamic connection of the oil-bearing formation with the area where injection wells are located;

with relatively small sizes of oil deposits, when the ratio of the deposit area to the perimeter of the oil-bearing contour is 1.5-1.75 km. At large values, the created pressure in the boundary part has virtually no effect on the reservoir pressure in the center of the deposit, as a result, a rapid drop in reservoir pressure is observed there;

With a homogeneous formation with good reservoir properties both in terms of formation thickness and area.

Contour flooding also has disadvantages. These include the following:

1. increased energy consumption (additional power consumption of pumping units) for oil extraction, since injected water has to overcome the filtration resistance of the reservoir zone between the oil-bearing contour and the line of injection wells;

2. delayed impact on the deposit due to the remoteness of the line
injection;

3. increased water consumption due to its outflow to the external
reservoir area beyond the injection line;

Edge flooding

Unlike contour flooding, injection wells are located directly on the oil-bearing contour.

Contour applied:

If the hydrodynamic connection of the formation with the external
region;

To intensify the operation process, since
filtration resistance between injection and extraction lines
decrease due to their convergence.

However, the likelihood of the formation of flood tongues and water breakthrough to individual wells in production rows increases. This is associated with possible oil losses due to the formation of unaffected zones between injection wells. Oil can only be displaced from these zones through careful management of the development process, including the drilling of additional wells.

From an energy point of view, peripheral flooding is more economical, although with good hydraulic conductivity of the outer region, losses of injected water are inevitable.

In-circuit flooding.

They are mainly used in the development of oil deposits with very large area sizes. Intra-circuit flooding does not negate peripheral flooding, and in necessary cases, intra-circuit flooding is combined with peripheral flooding.

Dividing the oil-bearing area into several areas (usually 4-5 km wide, and with low-permeability reservoirs - 3-3.5 km) by means of intra-circuit flooding makes it possible to bring the entire oil-bearing area into effective development simultaneously.

To fully cut the oil-bearing area, injection wells are arranged in rows. When water is pumped into them along the lines of rows of injection wells, a high-pressure zone is formed, which prevents the flow of oil from one area to another. As injection progresses, the pockets of water formed around each injection well increase in size and finally merge, forming a single front of water, the progress of which can be regulated in the same way as during contour flooding. In order to accelerate the formation of a single water front along the line of a number of injection wells, the development of wells for injection in a row is carried out “every other”. In the intervals, design water injection wells are put into operation as oil production wells, with forced extraction carried out in them. As injected water appears in the “intermediate” wells, they are transferred to water injection.

Figure 2.2 – In-circuit flooding schemes.

1 - injection wells; 2- production wells

a) with cutting the deposit; b) axial

Production wells are located in rows parallel to the rows of water injection wells. The distance between rows of oil producing wells and between wells in a row is selected based on hydrodynamic calculations, taking into account the features of the geological structure and physical characteristics of reservoirs in a given development area.

The great advantage of the in-circuit flooding system is the ability to start development from any area and, in particular, to bring into development, first of all, areas with the best geological and operational characteristics, the highest density of reserves with high well flow rates.

The following types of in-circuit flooding are used in practice.

Axial, when injection wells cut the deposit along the axis of the fold (Figure 2.2). Used for calm, gently sloping anticlinal folds. In this case, it becomes possible to have one instead of several injection lines.

Focal, when individual sections of the deposit are exposed to waterflooding (Figure 2.3).

Figure 2.3 – Scheme of focal flooding in combination with peripheral flooding.

1 - production wells; 2 - injection wells

Focal waterflooding is advisable in the middle and late stages of reservoir exploitation, when issues of additional production of oil reserves from interlayers, pillars and dead-end zones not covered by the main development process are being resolved. As a rule, in case of focal flooding, production wells are used for injection, located rationally in relation to the surrounding production wells and in the formation zone with increased permeability. However, for focal flooding, it is possible to drill special wells to increase the coverage of a larger volume of the oil-saturated part of the formation or its low-permeability zones.

Block systems developments are used in elongated fields with rows of water injection wells located more often in the transverse direction. The fundamental difference between block systems is that block systems require the abandonment of boundary flooding (Fig. 7.4). As can be seen from the diagram, rows of water injection wells cut a single deposit into separate sections (blocks) of development. Block systems involve the location of injection wells in a direction perpendicular to the strike line of the fold.

Figure 2.4 – Block flooding scheme

The advantage of block systems is the following:

1. Refusal to locate water injection wells in the boundary zone eliminates the risk of drilling wells in a part of the reservoir that is poorly studied at the stage of exploration of the field.

2. The manifestation of the natural forces of the hydrodynamic region of the boundary part of the reservoir is used more fully.

3. The area to be equipped with RPM facilities is significantly reduced.

4. Maintenance of the reservoir pressure maintenance system (wells, pumping stations, etc.) is simplified.

5. The compact, close location of production and injection wells makes it possible to quickly resolve issues of development regulation by redistributing water injection among rows and wells and fluid withdrawal in production wells.

Area flooding

The most intensive system of formation stimulation, ensuring the highest rates of field development. Used when developing formations with very low permeability.

With this system, production and injection wells are placed according to regular patterns of four-, five-, seven- and nine-point systems.

Thus, in a four-point system (Fig. 7.5) the ratio between production and injection wells is 2:1, with a five-point system -1:1, with a seven-point system -1:2, with a nine-point system - 1:3. Thus, the most intense among those considered are the seven- and nine-point systems.

Figure 2.5 Basic schemes of area flooding.

a - four-point; b - five-point; c - seven-point; g - nine-point;

1 - production wells; 2 - injection wells.

The efficiency of area flooding is greatly influenced by the homogeneity of the formation and the amount of oil reserves per well, as well as the depth of the development object.

In conditions of a heterogeneous formation, both in section and area, premature water breakthroughs to production wells occur in the more permeable part of the formation, which greatly reduces oil production during the dry period and increases the water-oil factor, therefore it is advisable to use area flooding when developing more homogeneous formations in the latter stages of field development.

The selective waterflooding system is a type of areal flooding and is used in oil reservoirs with significant heterogeneity.

With the selective waterflooding system, reservoir development is carried out in the following order. The deposit is drilled along a uniform triangular and quadrangular grid, and then all wells are put into operation as production ones. The well design is selected in such a way that any of them meets the requirements for production and injection wells. The area of ​​the oil deposit is equipped with oil and gas gathering facilities and reservoir pressure maintenance facilities so that any well can be developed not only as a production well, but also as an injection one.

By performing a detailed study of the section in the wells according to logging data and carrying out hydraulic testing in the wells, wells for water injection are selected from among the producing ones. Such wells should be wells in which the oil-producing section is most fully exposed. The hydrodynamic connection of the selected well with neighboring ones is traced.

Barrier flooding

When developing gas and oil fields with a large volume of gas cap, the task may be to simultaneously extract oil from the oil rim and gas from the gas cap.

Due to the fact that it is very difficult to regulate the extraction of oil and gas, as well as reservoir pressure during separate extraction of oil and gas, which does not lead to mutual flows of oil into the gas-bearing part of the formation, and gas into the oil-bearing part, they resort to cutting a single oil and gas deposit into separate areas of independent development. In this case, water injection wells are located in the gas-oil contact zone, and water injection and oil and gas extraction are regulated in such a way that oil and gas are displaced by water while excluding mutual flows of oil into the gas part of the deposit, and gas into the oil part. This method allows for simultaneous production of oil from the oil-saturated part and gas from the gas cap. The method is rarely used, since it is extremely difficult to create a reliable barrier between oil and gas.

Figure 2.6 – Barrier flooding scheme

The better the degree of exploration, the more reliably the location of the external oil-bearing contour is determined; the steeper and more consistent the formation, the closer to the contour the injection line can be outlined. The meaning of this requirement is to guarantee against the installation of injection wells in the oil-bearing part of the formation. The greater the distance between injection wells, the greater the distance from the oil-bearing contour to the injection line. Fulfillment of this requirement ensures that the shape of the oil-bearing contours is preserved without sharp tongues of water intrusion into the oil part of the formation. The greater the distance between the internal and external oil-bearing contours, the greater the distances can be set between injection wells, since when the exploitation zone moves away from the injection zone, the interaction of individual injection and production wells will manifest itself to a lesser extent, it will be reflected in the form of interaction of injection and extraction lines . The meaning of this requirement also lies in the uniform movement of the oil-water contact.

Questions of the theory of oil displacement by water in a fractured-porous formation

Experience in the development of oil fields shows that not only carbonate rocks are saturated with fractures, but also sandstone or siltstone formations are fractured to one degree or another. This is indicated by the discrepancy between the permeability estimated for rock cores without fractures and the permeability determined during hydrodynamic testing of wells. The permeability of the formation turns out to be much higher than that determined from cores without fractures.

When the rocks themselves are low-porosity and poorly permeable, cracks turn out to be the main channels for the movement of oil to the bottoms of production wells. During the development of fractured-porous formations, pressure spreads faster through the system of fractures. Therefore, pressure differences arise between fractures and blocks, which cause fluid flows between fractures and blocks (matrices) of rocks. This leads to a delay in pressure redistribution compared to pressure redistribution in homogeneous formations.

Water pumped into such formations quickly breaks through cracks to production wells, leaving oil in the rock blocks. Oil is displaced from the fracture system itself quite efficiently, the displacement coefficient reaches 0.85. Oil is not displaced from rock blocks efficiently; the oil displacement coefficient is about 0.25.

Oil is displaced by water from blocks of fractured-porous formations under the influence of forces caused by pressure gradients in the system of fractures that also affect the rock blocks. On the other hand, oil is displaced under the influence of the difference in capillary pressure in water and oil. Its action leads to the occurrence of capillary impregnation of hydrophilic rocks, i.e., to the replacement of oil with water under the influence of a difference in capillary pressure. Capillary impregnation is also understandable from an energy point of view. Because the minimum surface energy at the oil-water interface will be achieved when the oil aggregates together in fractures rather than saturating matrix rocks that have a complex, highly branched surface.

Therefore, if a block of rock from a fractured-porous formation, saturated with oil, is placed in water (a similar situation arises when a block in a real formation is surrounded by cracks filled with water), then the speed j(t) capillary absorption of water into the block and, consequently, displacement of oil from it, will depend on time t:

j(t) ~ 1/ . (2.1)

The rate of capillary absorption is proportional to the rate of contraction of the interface between oil and water. In this case we can assume that:

j(t) ~e - b t . (2.2)

Based on the results of industrial tests, the most effective will be a combination of hydrodynamic and energy approaches. The rate of capillary impregnation is determined by the formula:

j(t) = , (2.3)

Where a– experimental coefficient.

From dimensional considerations and the physics of the absorption process, the coefficient b can be expressed like this:

b = , A = A(k n, k in, m, ) , (2.4)

Where kn, kv– relative permeability for oil and water;

k– absolute permeability;

q– angle of wetting of formation rocks with water;

s–surface tension at the oil-water interface;

μ n– oil viscosity;

A– experimental function;

l - length of the face of the formation rock cube.

Expression for the coefficient A, based on the condition that over an infinite time, the amount of water absorbed into a rock block is equal to the volume of oil extracted from it, has the form:

A=ml 3 s but hb/π ,(2.5)

Where s but– initial oil saturation of the rock block;

h– final oil recovery of the block during its capillary impregnation.

When considering the displacement of oil by water from a fractured-porous formation consisting of many blocks of rock, we represent these blocks as cubes with a side length l. Since the displacement of oil by water begins from the formation boundary at X= 0, then the blocks at the entrance to the formation will be saturated with water more than the subsequent ones. Water consumption q, pumped into a straight formation, goes into a certain number of rock blocks, so that at each moment of time, infiltration occurs in the region 0 £ x £ x f (x f– coordinate of the capillary impregnation front). This front moves in the formation at a speed:

v f = d x f /dt. (2.6)

If we assume that the rock blocks in each section of the formation begin to be saturated at the moment of time l(when the front of capillary impregnation approaches them, then the rate of water absorption must be calculated from this point in time. If during the time Dl a certain number of rock blocks have “entered” into impregnation, then the water consumption Dq included in these blocks will be:

Dq = . (2.7)

To determine the rate of water absorption per unit volume of a fractured-porous formation, it is necessary to divide j(t) on l 3, which is what was done in formula (2.7). The rate of impregnation in (2.3) is calculated from the moment l, in which to the block with coordinate x f (l) a front of water soaking into the blocks approached.

Summing up the cost increments Dq in formula (2.7) and directing Dl to zero, we arrive at the expression:

q = v f (l)dl.(2.8)

At a given flow rate q expression (2.8) is an integral equation for determining the speed of advancement of the impregnation front v f (l).

Substituting into (2.8) the expression for the rate of impregnation (2.3) we obtain:

Solving the integral equation (6.9) allows us to write an expression for the speed of movement of the capillary impregnation front:

v f (t) = = (2.10)

From (2.10) we obtain an expression for determining its position (coordinates):

x f (t) = dt.(2 .11)

Formula (2.11) allows you to determine the duration of water-free reservoir development t = t*, at which x f (t *) = l.

To calculate the development indicators of a fractured-porous formation during the production of water-flooded products, do this. It is believed that this layer “fictitiously” extends at x > l ad infinitum. Water consumption spent on impregnation of a fictitious part of the formation at x > l, will be:

q fict =bhbms but h. (2.12)

Substituting here v f (l) according to expression (2.10), and replacing in it t on l, we get:

q fict =qbdl.(2.13)

Consequently, the flow rate of water absorbed into the fractured-porous layer during the period t > t *, or the oil production rate obtained during this period is equal to:

q n = q - q fictitious. (2.14)

The water flow will accordingly be q in = q f. From the above expressions, the current water cut of products and oil recovery can be determined using general formulas. Expression (2.3) can be used for approximate calculations of oil displacement from a fractured-porous formation in the case of block impregnation, caused not only by capillary forces, but also by pressure gradients in the fracture system. Thus, according to formulas (2.3) and (2.4), the displacement of oil from rock blocks occurs under the influence of a force determined using the product scosq, and the dimension is = [Pa×m]. During hydrodynamic displacement of oil from rock blocks, water enters these blocks, and oil is displaced from them under the influence of a pressure gradient. Dimension grad P expressed as Pa/m. Capillary and hydrodynamic will have the same dimension if we take instead scosq value ( scosq)/l. Then:

b = k( +grad P) (2.15)

Thus, in formula (2.15), the impregnation of rock blocks is taken into account both due to capillary forces and due to pressure gradients in the system of cracks.

Questions for self-control:

1. For what reasons is there a delay in pressure redistribution in fractured-porous formations compared to pressure redistribution in homogeneous formations?

2. Under the influence of what forces is oil displaced by water from blocks of fractured-porous formations?

3. What is the hydrodynamic and energetic approach to explaining the process of capillary impregnation of hydrophilic rocks?

4. On what indicators (values) does the rate of capillary impregnation of hydrophilic rocks depend?

5. Write down expressions for the speed of movement of the capillary impregnation front and for determining its position (coordinates)

6. Write down a formula that allows you to determine the duration of water-free development of a fractured-porous formation

The most intensive system of formation stimulation, ensuring the highest rates of field development. Used when developing formations with very low permeability.

With this system, production and injection wells are placed according to regular patterns of four-, five-, seven- and nine-point systems.

Thus, in a four-point system (Fig. 7.5) the ratio between production and injection wells is 2:1, with a five-point system -1:1, with a seven-point system -1:2, with a nine-point system - 1:3. Thus, the most intense among those considered are the seven- and nine-point systems.

Figure 2.5 Basic schemes of area flooding.

a - four-point; b - five-point; c - seven-point; g - nine-point;

1 - production wells; 2 - injection wells.

The efficiency of area flooding is greatly influenced by the homogeneity of the formation and the amount of oil reserves per well, as well as the depth of the development object.

In conditions of a heterogeneous formation, both in section and area, premature water breakthroughs to production wells occur in the more permeable part of the formation, which greatly reduces oil production during the dry period and increases the water-oil factor, therefore it is advisable to use area flooding when developing more homogeneous formations in the latter stages of field development.

The selective waterflooding system is a type of areal flooding and is used in oil reservoirs with significant heterogeneity.

With the selective waterflooding system, reservoir development is carried out in the following order. The deposit is drilled along a uniform triangular and quadrangular grid, and then all wells are put into operation as production ones. The well design is selected in such a way that any of them meets the requirements for production and injection wells. The area of ​​the oil deposit is equipped with oil and gas gathering facilities and reservoir pressure maintenance facilities so that any well can be developed not only as a production well, but also as an injection one.

Contour flooding. The wells are located in the aquifer-bearing part of the formation (Fig. 7.1). The use of a contour development system is possible when the oil-water contact can move under achievable pressure drops. In this case, the impact on the formation is carried out through a system of injection wells located beyond the outer oil-bearing contour. The injection line is located approximately 300-800 m from the oil-bearing contour to create a more uniform impact on it, prevent the formation of flood tongues and local

Table 7.1Waterflooding applicability criterion

Contour flooding is advisable: with good hydrodynamic connection of the oil-bearing formation with the area where injection wells are located;

Rice. 7.1. Schematic diagram of natural flooding: 1 - production wells; 2 - injection wells

with relatively small sizes of oil deposits, when the ratio of the deposit area to the perimeter of the oil-bearing contour is 1.5-1.75 km. At large values, the created pressure in the boundary part has virtually no effect on the reservoir pressure in the center of the deposit, as a result, a rapid drop in reservoir pressure is observed there;

with a homogeneous formation with good reservoir properties both in terms of formation thickness and area.

Contour flooding also has disadvantages. These include the following:

increased energy consumption (additional power consumption of pumping units) for oil extraction, since injected water has to overcome the filtration resistance of the formation zone between the oil-bearing contour and the line of injection wells;

delayed impact on the deposit due to the remoteness of the line

injection;

increased water consumption due to its outflow to the external

reservoir area beyond the injection line;

Edge flooding.

Accelerating the impact on the reservoir can be achieved by placing injection wells in close proximity to the oil-bearing contour or even between the external and internal oil-bearing contours.

Perimeter flooding is used:

with deteriorated hydrodynamic connection of the formation with the external

region;

to intensify the operation process, since

filtration resistance between injection and extraction lines

decrease due to their convergence.

However, the likelihood of the formation of flood tongues and water breakthrough to individual wells in production rows increases. This is associated with possible oil losses due to the formation of unaffected zones between injection wells. Oil can only be displaced from these zones through careful management of the development process, including the drilling of additional wells.

From an energy point of view, peripheral flooding is more economical, although with good hydraulic conductivity of the outer region, losses of injected water are inevitable.

In-circuit flooding.

They are mainly used in the development of oil deposits with very large area sizes. Intra-circuit flooding does not negate peripheral flooding, and in necessary cases, intra-circuit flooding is combined with peripheral flooding.

Dividing the oil-bearing area into several areas (usually 4-5 km wide, and with low-permeability reservoirs - 3-3.5 km) by means of intra-circuit flooding makes it possible to bring the entire oil-bearing area into effective development simultaneously.

To fully cut the oil-bearing area, injection wells are arranged in rows. When water is pumped into them along the lines of rows of injection wells, a high-pressure zone is formed, which prevents the flow of oil from one area to another. As injection progresses, the pockets of water formed around each injection well increase in size and finally merge, forming a single front of water, the progress of which can be regulated in the same way as during contour flooding. In order to accelerate the formation of a single water front along the line of a number of injection wells, the development of wells for injection in a row is carried out “every other”. In the intervals, design water injection wells are put into operation as oil production wells, with forced extraction carried out in them. As injected water appears in the “intermediate” wells, they are transferred to water injection.

Rice. 7.2. In-circuit flooding schemes. 1 - injection wells; 2- production wells a) with cutting of the deposit; b) axial

Production wells are located in rows parallel to the rows of water injection wells. The distance between rows of oil producing wells and between wells in a row is selected based on hydrodynamic calculations, taking into account the features of the geological structure and physical characteristics of reservoirs in a given development area.

The great advantage of the in-circuit flooding system is the ability to start development from any area and, in particular, to bring into development, first of all, areas with the best geological and operational characteristics, the highest density of reserves with high well flow rates.

The following types of in-circuit flooding are used in practice. Axial, when injection wells cut the deposit along the axis of the fold (Fig. 7.2-6). Used for calm, gently sloping anticlinal folds. In this case, it becomes possible to have one instead of several injection lines. Focal, when individual sections of the deposit are exposed to waterflooding (Fig. 7.3).

Rice. 7.3. Scheme of focal flooding in combination with peripheral flooding. 1 - production wells; 2 - injection wells

Focal waterflooding is advisable in the middle and late stages of reservoir exploitation, when issues of additional production of oil reserves from interlayers, pillars and dead-end zones not covered by the main development process are being resolved. As a rule, in case of focal flooding, production wells are used for injection, located rationally in relation to the surrounding production wells and in the formation zone with increased permeability. However, for focal flooding, it is possible to drill special wells to increase the coverage of a larger volume of the oil-saturated part of the formation or its low-permeability zones.

Block systems developments are used in elongated fields with rows of water injection wells located more often in the transverse direction. The fundamental difference between block systems is that block systems require the abandonment of boundary flooding (Fig. 7.4). As can be seen from the diagram, rows of water injection wells cut a single deposit into separate sections (blocks) of development. Block systems involve the location of injection wells in a direction perpendicular to the strike line of the fold.

The advantage of block systems is the following:

Refusal to locate water injection wells in the boundary zone eliminates the risk of drilling wells in a part of the reservoir that is poorly studied at the exploration stage of the field.

The manifestation of the natural forces of the hydrodynamic region of the boundary part of the reservoir is used more fully.

• 3. The area to be equipped with RPM facilities is significantly reduced.
• 4. Maintenance of the reservoir pressure maintenance system (wells, pumping stations, etc.) is simplified.
• 5. The compact, close location of production and injection wells makes it possible to quickly resolve issues of development regulation by redistributing water injection among rows and wells and fluid withdrawal in production wells.

Area flooding.

The most intensive system of formation stimulation, ensuring the highest rates of field development. Used when developing formations with very low permeability.

With this system, production and injection wells are placed according to regular patterns of four-, five-, seven- and nine-point systems.

Thus, in a four-point system (Fig. 7.5) the ratio between production and injection wells is 2:1, with a five-point system -1:1, with a seven-point system -1:2, with a nine-point system - 1:3. Thus, the most intense among those considered are the seven- and nine-point systems.

The efficiency of area flooding is greatly influenced by the homogeneity of the formation and the amount of oil reserves per well, as well as the depth of the development object.

Rice. 7.4. Schematic diagram of reservoir development using block systems. 1 - production wells; 2 - injection wells

Rice. 7.5. Basic schemes of area flooding. a - four-point; b - five-point; c - seven-point; g - nine-point; 1 - production wells; 2 - injection wells.

In conditions of a heterogeneous formation, both in section and area, premature water breakthroughs to production wells occur in the more permeable part of the formation, which greatly reduces oil production during the dry period and increases the water-oil factor, therefore it is advisable to use area flooding when developing more homogeneous formations in the latter stages of field development.

The selective waterflooding system is a type of areal flooding and is used in oil reservoirs with significant heterogeneity.

With the selective waterflooding system, reservoir development is carried out in the following order. The deposit is drilled along a uniform triangular and quadrangular grid, and then all wells are put into operation as production ones. The well design is selected in such a way that any of them meets the requirements for production and injection wells. The area of ​​the oil deposit is equipped with oil and gas gathering facilities and reservoir pressure maintenance facilities so that any well can be developed not only as a production well, but also as an injection one.

By performing a detailed study of the section in the wells according to logging data and carrying out hydraulic testing in the wells, wells for water injection are selected from among the producing ones. Such wells should be wells in which the oil-producing section is most fully exposed. The hydrodynamic connection of the selected well with neighboring ones is traced.

Rice. 7.6. Barrier flooding scheme

Barrier flooding.

When developing gas and oil fields with a large volume of gas cap, the task may be to simultaneously extract oil from the oil rim and gas from the gas cap.

Due to the fact that it is very difficult to regulate the extraction of oil and gas, as well as reservoir pressure during separate extraction of oil and gas, which does not lead to mutual flows of oil into the gas-bearing part of the formation, and gas into the oil-bearing part, they resort to cutting a single oil and gas deposit into separate areas of independent development. In this case, water injection wells are located in the gas-oil contact zone, and water injection and oil and gas extraction are regulated in such a way that oil and gas are displaced by water while excluding mutual flows of oil into the gas part of the deposit, and gas into the oil part. This method allows for simultaneous production of oil from the oil-saturated part and gas from the gas cap. The method is rarely used, since it is extremely difficult to create a reliable barrier between oil and gas.

The choice of an oil extraction system and the development of oil fields depends on dozens of factors: the depth and quality of productive formations: the amount of recoverable reserves, their structure according to the degree of knowledge (): characteristics of reservoirs; composition and properties of oil: gas factor and composition of associated gases: saturation pressure of oil with gas: properties and conditions of occurrence of formation waters; position of water-oil contact.

In addition to the listed main development indicators, natural and climatic characteristics and engineering and geological conditions are taken into account when developing the field.

One of the main requirements for development is rationalization: ensuring specified production rates with minimal capital investments and minimal impacts on the environment. The most important component of field development design is the identification of operational facilities. The part of the oil deposit allocated for exploitation by an independent network of production and injection wells is called a production facility.

Explored deposits are considered prepared for industrial development if the following conditions are met:

Requirements for the master plan

The general plan of the field provides for the placement of wellheads for oil, gas, injection single and cluster wells, gas treatment facilities, and booster pump stations. installations for preliminary discharge of formation waters (UPS), cluster pumping stations (PSS), CS, engineering communications (roads, oil and gas pipelines, water pipelines, power lines, communication lines, cathodic protection, etc.), ensuring the processes of collection and transportation of well products, as well as the supply of electricity, heat, water and air.

The placement of production and auxiliary buildings and structures must be carried out according to their functional and technological purpose, taking into account explosion and fire hazards. When locating oil production structures on coastal areas of reservoirs, site planning marks are taken 0.5 m above the highest water horizon with the probability of exceeding it once every 25 years (wellheads, gas treatment facilities) and once every 50 years (KS, CPS, BPS, UPS ).

Environmental protection measures and EIA elements are present in regulatory documents for field development. However, with the current practice of interaction between participants in field development, typical environmental problems are solved not in a preventive manner, but as they arise. There is a pattern - the more remote the field is located, the less stringent environmental restrictions are imposed on it and the greater the environmental damage is caused to the environment.

In order to avoid social and environmental problems at the later stages of oil production, consultations with all interested organizations and individuals should be carried out even when designing field development. The operation of oil fields harms the environment, regardless of the design features of the structures and the volume of hydrocarbons produced. Costly environmental measures must be carried out in a timely manner (liquidation of wells, storage pits, land reclamation), and not postponed indefinitely.

The technological safety of the operation of structures in the chain "production - collection - preparation - transportation" is largely ensured by the uniform development of oil reserves. To do this, it is necessary to have reliable information about the distribution of the energy potential of the deposit, which is reflected using isobar maps. Here, the choice of well clustering scheme is fundamentally important. It is known that the larger the well pads, the more expensive it is to drill a well, since large face waste from the vertical is required (up to 2-4 km or more). However, this reduces the cost of communication corridors and increases the degree of environmental safety of the fishery as a whole.

Well cluster

An area of ​​natural or artificial territory with wellheads, technological equipment, utilities and office premises located on it is allocated for well clusters. An enlarged cluster may contain several dozen directional wells. The total oil flow rate of one well cluster is assumed to be up to 4000, and the gas factor - up to 200.

The technological structures of a well cluster usually include:

• wellhead sites of production and injection wells;
• metering installations;
• units for supplying reagents-demulsifiers and inhibitors;
• gas distribution and water distribution blocks;
• blocks for pumping water into injection wells;
• control stations for ESP and SRP pumps;
• foundations for pumping machines;
• transformer substations;
• sites for repair units;
• collection tank and process pipelines.

The well pad structures may include a wastewater treatment unit (WTP) with local injection of water into the formation. In this case, there is no energy-intensive pumping of formation water to oil separation points and back, and there are no aggressive formation fluids in the transport corridors, which increases the environmental safety of the field.

The construction of wells with large bottom-hole waste limits the use of deep-well sucker rod pumps due to complications associated with pipe abrasion. To avoid accidents, when choosing pumping equipment, preference is given to ESPs and hydraulically driven pumping systems in a closed oil and gas collection system. Such systems make it possible to supply inhibitors to prevent corrosion and wax formation.

The system of oil treatment, water discharge and injection facilities is built depending on the distribution of reserves over the deposit area, production rates, the degree of water cut and gas saturation of oil, the pressure at the wellhead, and the location of well clusters (Fig. 5.1). These facilities must provide:

• sealed collection and transportation of well products to the central processing plant;
• separation of gas from oil and compressor-free transportation of gas of the first separation stage to collection points, gas processing plants and for own needs;
• measuring the production costs of individual wells and clusters, accounting for the total production of all wells;
• preliminary dehydration of oil.

Group metering units

The gas-liquid mixture from production wells enters the gas-liquid unit, in which periodic measurements of the liquid and gas flow rates of each well are carried out automatically in a metering separator. The number of installations is determined by calculations. Units for injection of a demulsifier and a corrosion inhibitor are located at the GZU sites.

Booster pump station

In cases where the distance from the well clusters to the central pumping station is large, and the wellhead pressure is not enough to pump fluids, a booster station is constructed. The mixture reaches the booster station through oil collection pipelines after the gas treatment unit.

The CPS includes the following block structures:

• first stage of separation with preliminary gas selection;
• preliminary dehydration and purification of produced water;
• measuring oil, gas and water;
• pump and air compressor unit;
• injection of reagent before the first separation stage;
• injection of inhibitors into gas and oil pipelines;
• emergency tanks.

The construction of a booster station is necessary because pumping equipment does not allow pumping mixtures with a high gas content due to the occurrence of cavitation processes. The gas separated as a result of pressure reduction in the first separation stage is most often supplied to a combustion flare or for use for local needs. Oil and water with dissolved remaining gas enter the second stage separators at the central processing plant and oil treatment plant.

Central collection point

At the central processing plant, crude oil undergoes a full processing cycle, which includes two- or three-stage degassing of oil using separators and bringing the oil to the required vapor pressure according to saturated vapor pressure. After separation, the gas is cleared of dropping liquids and supplied for disposal or processing. Gas from the first and second separation stages is transported under its own pressure. The end stage gas requires compression for further use.

Here, at the central processing plant, oil is dehydrated and desalted to marketable standards. Produced waters are separated from crude oil at an oil treatment unit (OPF) as part of the central processing plant. In a special tank, oil settles, the oil emulsion is heated in tube furnaces and desalted. After this, commercial oil enters the reservoir with subsequent pumping to the main oil pipeline.

Tank parks

The presence of a reserve tank fleet is a mandatory attribute of all technological schemes for the collection, preparation and transportation of petroleum gas. Standard RVS type tanks are used to create reserves:

• raw materials supplied to the oil treatment plant, required in the amount of daily production volume of wells;
• commercial oil in the amount of daily productivity of the oil treatment plant.

In addition, reservoirs of various volumes are needed to receive formation and waste water, as well as for emergency discharges.

To discharge paraffin deposits from cleaning (steaming) of tanks, earthen storage barns are installed. In addition, tanks are a source of air pollution due to the evaporation of hydrocarbons stored in them.

Compressor stations

CS can be independent objects of field development or be part of a complex of technological structures of the central processing plant. CS are designed to supply petroleum gas to gas processing plants, to compress gas in a gas lift production system and to prepare it for transportation.

To remove gas from the cavity of a piston compressor, a gas discharge plug is provided on the receiving gas pipeline of each compression stage of the compressor with a shut-off valve installed on it. The height of the candle is at least 5 m and is determined by gas dispersion calculations.

Flare system

Petroleum gas, which cannot be accepted for transportation, as well as gas from purging equipment and pipelines, is sent to the emergency flare system of the BPS.

The diameter and height of the torch are determined by calculation taking into account the permissible concentration of harmful substances in the ground layer of air, as well as permissible thermal effects on people and objects. The height of the pipe must be at least 10 m, and for gases containing hydrogen sulfide, at least 30 m. The gas speed at the mouth of the flare shaft is taken taking into account the exclusion of flame separation, but not more than 80 m/s.

Oil and gas pipelines

The system for collecting and transporting production wells includes:

• flow pipelines from the wellhead to the gas treatment plant;
• collectors that ensure the collection of products from the gas storage unit to the points of the first stage of separation of the booster station or central processing station;
• oil pipelines for supplying gas-saturated or degassed water-cut oil or anhydrous oil from collection points and booster pump stations to the central pumping station;
• oil pipelines for transporting commercial oil from the central pumping station to the main oil pumping station of the main pipeline:
• gas pipelines for supplying petroleum gas from separation units to gas processing plants, compressor stations, central processing stations, gas processing plants and for own needs:
• gas pipelines for supplying gas from the central pumping station to the main compressor station of the main pipeline.