Traditional systems for the development of oil and gas fields. Oil field development systems. Row-Based Development Systems

The development of oil and gas wells is a whole complex of actions aimed at pumping hydrocarbon raw materials from the field to the bottom. In this case, a certain order of location of drilling rigs along the entire plane of the oil-bearing contour should be provided. Engineers assume the sequence of bringing the wells into working condition, installing technological equipment and maintaining the operating mode in the field.

What is the development of oil and gas wells

The development of a well for oil or gas is a series of measures that directly relate to the extraction of natural resources from the bowels of the Earth. This is a whole science that has been intensively developing from the very beginning of the existence of the industry. Now advanced technologies for extracting hydrocarbons, new ways of recognizing processes underground, and using reservoir energy are being developed. In addition, new methods of planning and exploration of deposits are constantly being introduced.

The main task of the complex of actions aimed at extracting resources is the rational use of oil-bearing areas, the fullest possible development of gas, oil and condensate. The organization of these processes at any facility is a priority for the entire industry. The development of oil and gas fields is carried out using traditional wells, sometimes mining is allowed. An example of the latter is the Yaregskaya oil deposit, which is located in the Komi Republic.

In order to have a more detailed idea of how hydrocarbon production processes proceed in the fields, one should learn more about the system for developing oil and gas fields and the main stages of resource extraction. This will be discussed below.

What you need to know about the well development system?

Under the concept of a system for the development of oil and gas reservoirs, a certain form of organization of the extraction of natural resources is meant. Its character is defined as follows:

sequence of putting technological systems into operation;
grid of locations for drilling in the fields;
the rate of introduction into operation of gas and oil pumping systems;
ways to maintain balance;
reservoir energy application technologies.

What is a well grid? This is a certain principle of placement of production wells and water supply systems. A certain distance must be maintained between them, which is called the mesh density. Places for drilling are located evenly or unevenly, as a rule, on several lines. From the rows a square, polygonal or triangular system is formed.

Important! Triangular mesh design involves 15.5% more drilling space than a rectangular mesh. And this is subject to equal distance between the wells.

Density should be understood as the ratio of the total area of the field to the number of wells working for the extraction of raw materials. But the concept itself is rather complicated, and the density is often determined based on specific conditions in certain fields.

It is also important to distinguish between fields that use isolated deposits and areas consisting of several layers. The object of operation is 1 or several productive layers of one oil-bearing area. As a rule, they differ in geological and technical conditions and expediency from the point of view of the economy. The following should be taken into account when operating the fisheries:

geological and physical features of the region;
physical and chemical characteristics of natural resources and aquifers;
phase state of raw materials;
estimated mining technology, availability of technical equipment;
mode of layers of natural resources.

Objects are divided by engineers into independent and returnable. The second type is used as a place to install wells for drilling other oil and gas fields.

Stages of development of oil and gas fields

A stage is a period of development that has characteristic changes only for it. At the same time, they are always natural and relate to technological and economic indicators. Under these concepts are hidden the average annual and total capacity of the field, the current use of water for flooding, and the amount of water in the feed. In addition, there is the so-called water-oil factor, which should also be taken into account. It is a quotient of the amount of water and oil pumped out.

Modern production divides the extraction process into 4 main stages:

The first stage is called field development. It is characterized by an intensive increase in the rate of extraction of natural resources. For the year, the increase is approximately 1-2% of the total reserves of raw materials. At the same time, the rapid construction of mining structures is being carried out. The pressure in the reservoir decreases sharply, and the water cut of the production is minimal. With a low viscosity of raw materials, the total proportion of water does not exceed 4%, and with a high viscosity - 35%.
The second stage is a set of measures aimed at maintaining a high level of hydrocarbon pumping. This stage is characterized by consistently high extraction of the resource for up to 7 years. With a high viscosity of the raw material, the period is reduced to 2 years. Due to the reserve fund, the maximum increase in wells is observed during this period. Water cut reaches 7% and 65% at low and high feedstock viscosity. Most of the wells are being converted to artificial lift.
The third stage is considered the most difficult in the entire development process. The main goal of the fishery at this time is to minimize the drop in the rate of extraction of natural resources as much as possible. There is a decrease in the rhythm of pumping out the resource, a decrease in the number of operating wells. Water cut is up to 85%. The duration of the third stage is from 5 to 10 years.
The fourth stage is the final one. Slowly declining rates of resource depletion and large fluid intake are observed. The sharp decrease in the number of operating wells is due to the high degree of watering. The duration of the stage is about 15-20 years. The term is determined by the limit of economic feasibility of exploitation of the deposit.

Construction of production wells and water supply stations

In order to maintain reservoir pressure in the area of oil and gas potential, it is necessary to use fluid injection into productive deposits. Alternatively, gas can be used. If water is used, then this process is called flooding. There are aquifer, in-contour technologies and the method of waterflooding by area. It is worth considering each method in detail.

The first method is characterized by water injection from wells located outside the oil-bearing area. The construction of installations is carried out exactly along the perimeter of the deposit, forming a polyhedron. But production oil wells are located inside this ring. When waterflooding in this way, the amount of oil pumped out is equal to the volume of water pumped into the oil-bearing area.
If large deposits are being developed, then in-loop technology should be used. It implies the division of the deposit into regions. All of them are independent of each other. At the same time, from 1.6 to 2 volume units of injected water falls per unit mass of oil.
The areal method is not used as the main waterflood. This is a secondary resource extraction technology. It is used when the reserves of reservoir energy are used up to a large extent, but at the same time there is still a large accumulation of hydrocarbons in the bowels of the Earth. The water supply is carried out through the hydraulic system. Fluid injection wells are located strictly on the grid.

Important! Now the waterflooding technology has almost exhausted itself. To increase the efficiency of production, other methods of development are used. Nevertheless, with its help, it was possible to significantly increase the amount of extracted resources and the volume of the industry.

In the fields, alkaline media, hot water and steam, foam and emulsions, and polymers are often used. The extraction of resources from oil and gas fields also resorts to the use of carbon dioxide, solvents and other gases under pressure. The so-called method of microbiological impact on the oil-bearing area is also used.

Now the development of oil wells is carried out by flowing, gas lift and pumping methods.

Basic concepts and characteristics of development systems

The field development system is understood as a set of measures on the extraction of hydrocarbons from the bowels and the management of this process. The development system determines the number of production facilities, methods of influencing the reservoirs and the rate of extraction of hydrocarbons from them, the location and density of the grid of production and injection wells, the sequence of putting blocks and sections of the deposit into development, the methods and modes of well operation, measures to control and regulate the development process, protection of subsoil and the environment.

Development systems are justified in technological design documents.

Operational facility means a productive formation, a part of a formation or a group of formations allocated for development by an independent grid of wells. Reservoirs combined into one development object should have similar lithological characteristics and reservoir properties of productive reservoir rocks, physical and chemical properties and composition of fluids saturating them, values of initial reduced reservoir pressures.

On the basis of the sequence of putting individual objects into production drilling, the following field development systems can be distinguished.

Top-down development system. This system consists in the fact that each layer of a given field is first introduced into exploration, and then into operational mass drilling, but after the overlying layer has been mostly drilled out (Fig. 10).

The top-down development system was organically linked to percussive drilling, in which the isolation of one formation from another during the drilling process is achieved not by circulating mud, as in rotary drilling, but by running a special casing string to isolate each formation. With percussive drilling technology, this development system was the most economical and, accordingly, the most common. With the current state of science and technology, it does not allow efficient use of the existing drilling technique and data from electrometric well surveys. In addition, it greatly delays the pace of development and exploration of deposits and is not currently used.

Rice. 10. Scheme of development of oil fields.

a- top-down system b- bottom-up system

Bottom-up development system. This system consists in the fact that, first of all, the lowest of the high-yield horizons (layers) is drilled. The horizon from which development begins is called the reference horizon (Fig. 10).

The main advantages of this system are as follows:

1) Simultaneously with the exploration and drilling of the reference horizon, logging and core sampling are used to study all overlying formations, which greatly reduces the number of exploration wells, while immediately highlighting the structure of the entire field;

2) the percentage of unsuccessful wells decreases, since wells that fall outside the contour of the deposit in the reference horizon can be returned by operation to the overlying horizons;

3) significantly increase the pace of development of oil fields;

4) the number of accidents during drilling, associated with the withdrawal of the circulating solution into the reservoir layers, is reduced, and the claying of the reservoirs is also significantly reduced.

Floor development system. The floor system is usually used in the development of multilayer fields, in the section of which there are two or three or more sustained along the strike and removed along the section of the productive formation.

On the basis of the sequence of development of the deposit in rows and the commissioning of wells, the development systems are divided into phased and simultaneous (continuous).

With a staged reservoir development system, two or three rows of wells are first drilled, closest to the row of injection wells, while leaving a significant part of the reservoir undrilled. Calculations and field development experience in a similar way show that drilling the fourth row of wells does not increase the total oil recovery due to well interference. Therefore, drilling of the fourth row is started when the first row of wells is flooded and out of operation. The fifth row is drilled simultaneously with the decommissioning of the second row of wells, etc.

Each replacement of an outer row of wells with an inner row is called a development stage. Such a drilling system in rows in the case of development from the contour to the arch resembles a creeping system of continuous drilling along the rise and differs from it in that not all wells are in operation at the same time, but no more than three rows.

With a simultaneous development system, the reservoir is flooded simultaneously over the entire area.

Classification of the development of reservoir deposits on the basis of the impact on the reservoir

The current state of technology corresponds to the following division of methods for the development of oil deposits on the basis of the impact on the reservoir:

1) development method without reservoir pressure maintenance;

2) pressure maintenance method by pumping water;

3) method of maintaining pressure by pumping gas or air;

4) vacuum process;

5) compressor-circulation method for the development of condensate deposits;

6) in situ combustion method;

7) method of cyclic steam injection.

Development without reservoir pressure maintenance is used in cases where the pressure of marginal waters provides an elastic-water drive mode in the reservoir during the entire period of operation or when, for one reason or another, it is not economically profitable to organize the injection of gas or water into the reservoir.

In cases where the formation water pressure cannot provide an elastic-water-driven regime, the development of a deposit without maintaining formation pressure will necessarily lead to the manifestation of a dissolved gas regime, and therefore to a low reserve utilization factor. In these cases, artificial maintenance of reservoir pressure is necessary.

If it is assumed that the oil field will be developed in the main period in the dissolved gas regime, which is characterized by a slight movement of the water-oil section, i.e., with a weak activity of edge waters, then a uniform, geometrically correct location of wells on a square or triangular grid. In those cases where a certain movement of the water-oil and gas-oil sections is expected, the wells are located taking into account the position of these sections.

The water injection pressure maintenance method aims to maintain reservoir pressure above saturation pressure. This will ensure the development of the deposit under a hard water-driven regime. The latter makes it possible to develop the reservoir up to the extraction of 40 - 50% of the reserves, mainly by the flowing method with high rates of fluid withdrawal and, ultimately, to obtain a high reserve utilization rate - 60 - 70%.

Development systems with reservoir pressure maintenance, in turn, are subdivided into systems with contour, near-contour and intra-contour influence.

The method of maintaining pressure, in which water is pumped into the edge region of the formation, is called edge flooding. It is rational to apply edge flooding in the development of relatively narrow deposits (no more than 3-4 km wide), on which three to five rows of production wells are located.

When developing large deposits, when water injection into the aquifer area cannot provide the specified production rates and affect the wells located inside the deposit, it is advisable to use in-loop waterflooding. Previously, in the early days of pressure maintenance by water injection, a phased development system was used, which was a creeping system of development in rise or fall. In both cases, a mothballed part of the deposit was formed, which is highly undesirable. That's why when developing large deposits currently apply in-loop waterflooding.

Systems with in-circuit exposure are divided into in-line, areal, focal, selective, central.

In-loop flooding also used in the development of lithological deposits, whose boundaries are determined by the replacement of sandstones by clays. In these cases, water is pumped along the axis of the deposit. Such waterflooding is called in-loop along the axis. If the injection is carried out in the center of a lithologically limited reservoir through one well, the flooding is called focal. Practice has shown the effectiveness of such flooding of lithological objects, consisting of a large number of lenticular deposits.

Over time, in case of localized waterflooding, adjacent production wells begin to be watered, and after full watering they are transferred to water injection. Gradually, focal flooding turns into a central one.

Central waterflooding is called, which is carried out through three or four wells located in the center of the deposit.

As a rule, central flooding through several wells at once at the beginning of development is never carried out in practice.

In the practice of developing large deposits, edge flooding, intra-contour block flooding and spot flooding are used simultaneously.

When developing large platform-type oil deposits in Western Siberia, in-line development systems are used. Their variety is block systems. With these systems, in the fields, usually in the direction transverse to their strike, there are rows of production and injection wells. In practice, three-row and five-row well arrangements are used, which represent, respectively, the alternation of three rows of producing and one row of injection wells, five rows of producing and one row of injection wells. With a larger number of rows (seven to nine), the central rows of wells will not be provided with an injection effect due to their interference with the wells of the outer rows.

The number of rows in in-line systems is odd due to the need to drill a central row of wells, to which the water-oil section is supposed to be drawn when it is moved during the reservoir development. Therefore, the central row of wells in these systems is often referred to as the tie row.

The distance between rows of wells usually varies within 400 - 600 m (rarely up to 800 m), between wells in rows - within 300 - 600 m.

With a three-row system, the deposit is cut by rows of injection wells into a number of transverse strips with a width equal to four times the distance between the rows of wells. With a five-row system, the width of the stripes is equal to six times the distance between the rows. These development systems provide very fast drilling of deposits. With these systems, at the beginning of the development of the deposit, lithological features of the reservoir are not taken into account.

Systems with areal arrangement of wells. Let's consider the most commonly used in practice systems for the development of oil fields with areal wells: five-spot, seven-spot and nine-spot.

Five-point inverted system (Fig. 11). The element of the system is a square, in the corners of which there are production wells, and in the center - an injection well. For this system, the ratio of injection and production wells is 1/1.

Rice. 11. Location of wells in a five-spot inverted development system

Seven-point inverted system (Fig. 12). The system element is a hexagon with production wells in the corners and an injection well in the center. The production wells are located at the corners of the hexagon, while the injection wells are located in the center. The ratio is 1/2, i.e., there are two production wells per injection well.

Rice. 12. Location of wells in a seven-spot inverted development system

1 - conditional contour of oil-bearing capacity, 2 and 3 - wells, respectively, injection and production

Nine-point inverted system (Fig. 13). The ratio of injection and production wells is 1/3.

Rice. 13. Location of wells in a nine-spot inverted development system

1 - conditional contour of oil-bearing capacity, 2 and 3 - wells, respectively, injection and production

The most intensive of the considered systems with areal arrangement of wells is five-spot, the least intensive is nine-spot. It is believed that all areal systems are “rigid”, since it is not allowed, without violating the geometric order of the location of wells and flows of substances moving in the reservoir, to use other injection wells to displace oil from this element, if the injection well belonging to this element cannot be operated due to or other reasons.

Indeed, if, for example, in block development systems (especially in three-row and five-row) any injection well cannot be operated, then it can be replaced by an adjacent one in a row. If the injection well of one of the elements of the system with an areal arrangement of wells fails or does not accept the agent injected into the reservoir, then it is necessary either to drill another such well (center) at some point of the element, or to carry out the process of displacing oil from the reservoir due to more intensive injection working agent into the injection wells of neighboring elements. In this case, the ordering of flows in the elements is strongly violated.

At the same time, when using a system with an areal arrangement of wells, in comparison with an in-line one, an important advantage is obtained, consisting in the possibility of a more dispersed impact on the formation. This is especially significant in the process of developing highly heterogeneous reservoirs. When using in-line systems to develop highly heterogeneous reservoirs, the injection of water or other agents into the reservoir is concentrated in separate rows. In the case of systems with areal wells, injection wells are more dispersed over the area, which makes it possible to expose individual sections of the reservoir to greater impact. At the same time, as already noted, in-line systems, due to their great flexibility compared to systems with areal wells, have the advantage of increasing the vertical coverage of the formation. Thus, in-line systems are preferred when developing formations that are highly heterogeneous along the vertical section.

In the late stage of development, the formation is largely occupied by the oil-displacing substance (for example, water). However, water, moving from injection wells to production wells, leaves some zones in the reservoir with high oil saturation, close to the initial oil saturation of the reservoir, i.e., the so-called oil pillars. On fig. 14 shows oil pillars in an element of a five-spot development system. To extract oil from them, in principle, it is possible to drill wells from among the reserve ones, as a result of which a nine-point system is obtained.

In addition to the above, the following development systems are known: a system with a battery (ring) arrangement of wells (Fig. 15), which can be used in rare cases in deposits of a circular shape in plan; system for barrier flooding used in the development of oil and gas deposits; mixed systems - a combination of the described development systems, sometimes with a special arrangement of wells, are used in the development of large oil fields and fields with complex geological and physical properties.

Rice. 14. An element of a five-point system, which is transformed into an element of a nine-point well location system.

1 – “a quarter” of the main production wells of the five-spot element (corner wells), 2 – pillars of oil (stagnant zones), 3 – additionally drilled production wells (lateral wells), 4 - flooded area of the element, 5 - injection well

Rice. 15. Scheme of the battery arrangement of wells

1 - injection wells, 2 – conditional contour of oil-bearing capacity, 3 and 4 - production wells, respectively, of the first battery with a radius R1 and a second battery with a radius R2

In addition, selective impact systems are used to control the development of oil fields with a partial change in the previously existing system.

In the case of applying methods of influence in the development of depleted deposits, they are called secondary. If they are applied from the very beginning of the development of the deposit, they are called primary. The vacuum process is a typical secondary process and is never used from the very beginning of operation.

The method of maintaining pressure by gas injection is usually used in deposits that have a gas cap. Maintaining pressure by gas injection aims to maintain the energy resources of the reservoir during operation. To do this, from the very beginning of operation, gas is pumped into the arch of the structure through injection wells located along the long axis of the structure. In addition, gas injection is sometimes used for areal displacement of oil by gas (the Marietta method).

Thermal impact on the formation is carried out by pumping hot water into the formation through injection wells. Injection of hot water is used for flooding reservoirs containing highly paraffinic oil and having a temperature of about 100 ° C. Injection of cold water into such a reservoir leads to cooling of the reservoir, to the precipitation of paraffin, which clogs the pores of the reservoir.

In the case when the impact on the formation by means of water injection is carried out after the development of the deposit in the dissolved gas mode, two main stages can be distinguished: displaced residual oil; b) the period of progressive watering of production wells.

By the time of water breakthrough into production wells, the entire pore space in the reservoir will be occupied by the liquid phase, so the further waterflooding process will be steady: the amount of liquid produced per day will be equal to the daily volume of water injected.

Generalization of materials carried out American researchers, showed that the oil recovery factor in the dissolved gas regime is on average 20% of geological reserves. The use of area flooding at the last stage of development increases it to 40%. At the same time, the use of flooding at the very beginning of development increases the recovery factor from 60 to 85%. According to the calculations of American specialists, the final oil recovery of about 80% of geological reserves is expected at the East Texas field.

You can specify four more parameters that characterize a particular development system.

1. Density parameter of the grid of wells S c , equal to the area of oil-bearing capacity per well, regardless of whether the well is a production or injection well.
If the oil-bearing area of the field is equal to S, and the number of wells in the field is n, then S c = S/n. Dimension - m 2 / well. In some cases, the parameter S sd is used, which is equal to the oil-bearing area per one production well.

2. Parameter A.B. Krylov N cr, equal to the ratio of recoverable oil reserves N to the total number of wells in the field N cr = N/n. Dimension of parameter =t/well.

3. Parameter equal to the ratio of the number of injection wells n n to the number of production wells n d = n n / n d. The parameter is dimensionless. The parameter for a three-row system is approximately 1/3, and for a five-row system ~1/5.

4. Parameter p, equal to the ratio of the number of reserve wells drilled in addition to the main stock of wells in the field to the total number of wells. Reserve wells are drilled in order to involve in the development of parts of the reservoir that are not covered by development as a result of previously unknown features of the geological structure of this reservoir, as well as physical
properties of oil and rocks containing it (lithological heterogeneity, tectonic disturbances, non-Newtonian properties of oil, etc.).

If the number of wells of the main stock in the field is n, and the number of reserve wells is n p, then p = n p / n. The p parameter is dimensionless.

Generally speaking, the well spacing density parameter S c can vary over a very wide range for development systems without reservoir stimulation. So, when developing deposits of superviscous oils (with a viscosity of several thousand 10 -3 Pa * s), it can be 1 - 2 * 10 4 m 2 / well. Oil fields with low-permeability reservoirs (hundredths of microns 2) are developed at S c = 10 - 20*10 4 m 2 /well. Of course,
the development of both high-viscosity oil fields and fields with low-permeability reservoirs at the indicated values of S c can be economically feasible at significant reservoir thicknesses, i.e. at high values of the A.I. Krylov parameter or at shallow depths of the developed reservoirs, i.e. . at a low cost of wells. For the development of conventional collectors S c \u003d 25 - 64 * 10 4 m 2 / well.

When developing deposits with highly productive fractured reservoirs, S c can be equal to 70 - 100*10 4 m 2 /well or more. The parameter N cr also varies within fairly wide limits. In some cases, it can be equal to several tens of thousands of tons of oil per well, in others it can reach up to a million tons of oil per well.

For oil field development systems without reservoir stimulation, the parameter α is naturally equal to zero, and the parameter p can be in principle 0.1 - 0.2, although reserve wells are mainly envisaged for a system with oil reservoir stimulation.

Oil and gas production has been carried out by mankind since ancient times. At first, primitive methods were used: collecting oil from the surface of reservoirs, processing sandstone or limestone soaked with oil using wells. But the beginning of the development of the oil industry is considered to be the time when mechanical drilling of wells for oil appeared, and now almost all the oil produced in the world is extracted through boreholes. At present, the structure of the resource base is such that large deposits are at a late stage of development and the use of traditional technologies to involve undeveloped reserves may not be economically feasible. As a result, significant volumes of reserves will not be involved in commercial development. As is known, all issues of oil deposit development and well operation are closely related to the reservoir regime and all the processes occurring in them are easily explained.

According to existing ideas, the regime of oil deposits is the dominant force of reservoir energy, which manifests itself in the development process. All modes known to us (water-pressure, gas-pressure, dissolved gas and gravitational) are characterized by a certain regularity. The most characteristic is the dependence of the gas factor (F) on the oil recovery factor (h), as well as the change in the range of the component composition of the gas of oil deposits. Modes can appear both separately and in a mixed form (in combination with other modes). As experience in the development of oil fields shows, in oil deposits with a mixed regime, the change in the gas factor occurs in accordance with the prevailing regime, which manifests itself in the development process.

Deposit development modes:

Elastic, in which the energy of the elastic expansion of water, oil and rocks is used as the only source of energy.

Water-driven, in which only the energy of the hydrostatic head of the marginal waters is used. Oil from the reservoir to the bottom of the wells moves under the action of the pressure of the marginal water. In the water-driven mode, the water pressure acts on the oil from below.

Gas pressure, which uses the energy of compressed gas enclosed in a gas cap (gas cap mode). Oil is displaced to the bottom of wells under the pressure of expanding gas, which is in a free state. In the gas-pressure mode, the gas creates pressure on the oil from above.

Dissolved gas regime, in which the main source of energy is the energy of the released and expanding gas. The dissolved gas regime appears if the pressure of marginal waters is weak or there is no free gas in the deposit. Oil moves towards the reservoir under the influence of the energy of the expanding gas.

Gravity mode - oil from the reservoir moves to the bottomhole under the influence of gravitational forces ( gravity ). In the gravitational regime, there is no pressure of marginal waters, gas cap and gas dissolved in oil. The flow of oil to the bottomholes of wells occurs due to the forces of gravity, which manifest themselves in the deposit. This mode is typical for the late stages of the development of the field.

On the developed deposits, any of these modes of development in its pure form is rare. Usually modes coexist in various combinations.

For example: an oil deposit can be simultaneously developed under the influence of gas pressure in the gas cap and the pressure of marginal waters. Dissolved gas mode can be combined with gas pressure or elastic:

Mixed mode, in which several moving forces appear simultaneously.

As a result of the operation of wells, not all reserves of hydrocarbons contained in the deposits are extracted from the subsoil.

The ratio of the amount of oil or gas extracted from the deposit to their initial (geological) reserves is called the oil recovery (gas recovery) coefficient of the reservoir.

The value of this coefficient depends primarily on the development mode.

When developing oil deposits, the most effective resilient and waterproof modes , called oil displacement mode by water, because high viscosity water displaces oil well.

Oil recovery factor at gas-pressure mode and the mode of dissolved gas is the smallest, because only part of the energy of the expanding gas is used to displace the oil. Most unproductively slips towards the wells.

At gravity mode with a low rate of oil recovery, a high oil recovery factor can be obtained, but an increase in the duration of the deposit development may turn out to be economically unprofitable.

Gas recovery is higher than oil recovery due to the low viscosity of gases and their weak interaction with the porous medium of rocks. The highest gas recovery can be achieved by lowering reservoir pressure to atmospheric pressure. Therefore, the development of gas deposits is stopped when the pressure at the wellhead is slightly more than atmospheric.

The mode of operation of the deposit (m / r) can be artificially changed.

For example: injection of gas into its highest part to create a gas cap - is transferred from gravitational or dissolved gas regime to gas pressure; injection of water into wells drilled around the reservoir to the productive formation - an artificially created water-driven development regime.

The set of measures that can be used to influence the process of deposit development and manage this process is called the deposit development system.

Different systems can be used on the same deposit. The most rational will be one that ensures the implementation of the planned plans for oil and gas production and the achievement of their complete extraction from the bowels of the earth at minimal cost.

The reservoir development system may change as it is developed and additional information about the properties and structure of productive formations is obtained. A set of measures that improve the development system is called the regulation of the development system of the exploited deposit (drilling new wells, changing the operating conditions of wells - transferring from the flowing method of operation to mechanized, etc.)

Geometrically incorrect well layouts are obtained as a result of various regulatory measures (drilling new wells, shutting down old ones that are unprofitable, etc.). Such well placement schemes are used in the development of gas deposits.

The well placement system in the development of gas deposits has little effect on the gas recovery of the formation. The number of gas wells is determined by the potential (ie the maximum allowable flow rate) of each separately and the total demand for gas. Gas wells are placed evenly in the highest parts of the deposit.

During the development of oil deposits under natural regimes, reservoir energy is depleted and reservoir pressures drop. With a decrease in reservoir pressure, gas begins to be released from oil and the pressure mode of operation of the deposit switches to the mode of dissolved gas, and well flow rates decrease. Further depletion of the energy of the gas released from the oil leads to the manifestation of the gravity mode of development and the need to use additional energy sources to lift oil from the well.

Thus, the development of oil fields under natural regimes does not provide high rates of oil production and high oil recovery factors: huge amounts of oil remain in the subsoil, especially in the regime of dissolved gas. As a result, the development of deposits can be delayed for many years, and costs will increase due to the use of additional energy sources. To ensure high rates of oil recovery from the reservoir and achieve oil recovery factors, it is necessary to artificially maintain reservoir pressure during development by pumping water or gas (air) into the deposit. Injection of water into the formation - flooding - is the most common method of reservoir pressure maintenance in the world. Over 90% of all oil is produced from flooded fields.

Pedagogical technology - Modular "No. of lessons - modules in the topic - M 3 and M 4

Oil and oil and gas Place of Birth- these are accumulations of hydrocarbons in the earth's crust, confined to one or more localized geological structures, i.e. structures located near the same geographic location.

deposit called a natural local single accumulation of oil in one or more interconnected reservoirs, i.e., in rocks capable of containing and releasing oil during development.

The hydrocarbon deposits included in the deposits are usually located in layers or massifs of rocks that have a different distribution underground, often different geological and physical properties. In many cases, individual oil and gas reservoirs are separated by significant strata of impermeable rocks or are located only in certain areas of the field. Such isolated or different formations are developed by different groups of wells, sometimes using different technologies.

Places of accumulation of natural gas in a free state in the pores and cracks of rocks are called gas deposits. If the gas reservoir is viable for development, i.e. when the sum of the costs of extraction, transportation and use of gas is less than the economic effect obtained from its use, then it is called industrial. gas field usually refers to one deposit or a group of deposits located in the same area.

The size and multilayer nature of fields with capacitive properties of reservoirs generally determine the size and density of oil reserves, and in combination with the depth of occurrence determine the choice of development system and methods of oil production.

D evelopment system deposits should be called a set of interrelated engineering solutions that determine the objects of development; the sequence and pace of their drilling and development; the presence of impact on the reservoirs in order to extract oil and gas from them; number, ratio and location of injection and production wells; the number of reserve wells, field development management, subsoil and environmental protection. Building a field development system means finding and implementing the above set of engineering solutions.

Let us introduce the concept of a deposit development object.

D evelopment object- this is a geological formation (layer, massif, structure, set of layers) artificially identified within the field being developed, containing industrial reserves of hydrocarbons, the extraction of which from the subsoil is carried out using a certain group of wells or other mining structures.

Developers, using the terminology common among oilmen, usually consider that each object is developed by “its own grid of wells”. It must be emphasized that nature itself does not create development objects - they are allocated by people developing the field. One, several or all layers of the field can be included in the development object.

The main features of the development object are the presence of industrial oil reserves in it and a certain group of wells inherent in this object, with the help of which it is developed.

To better understand the concept of a development object, consider an example. Let we have a field, the section of which is shown in Fig. 1. This field contains three layers, differing in thickness, areas of distribution of hydrocarbons saturating them and physical properties. The table shows the main properties of layers 1, 2 and 3 occurring within the field.

Fig.1. Section of a multilayer oil field

It can be argued that it is advisable to single out two development objects in the field under consideration, combining layers 1 and 2 into one development object (object A), and developing layer 3 as a separate object (object B).

The inclusion of reservoirs 1 and 2 in one object is due to the fact that they have close values of oil permeability and viscosity and are located at a small vertical distance from each other. In addition, recoverable oil reserves in reservoir 2 are relatively small. Formation 3, although it has smaller recoverable oil reserves compared to formation 1, contains low-viscosity oil and is highly permeable. Consequently, the wells that have penetrated this formation will be highly productive. In addition, if reservoir 3 containing low-viscosity oil can be developed using conventional flooding, then reservoirs 1 and 2, characterized by high-viscosity oil, will have to use a different technology from the beginning of development, for example, oil displacement with steam, solutions of polyacrylamide (water thickener) or using in-situ combustion.

At the same time, it should be taken into account that, despite the significant difference in the parameters of layers 1, 2 and 3, the final decision on the allocation of development objects is made on the basis of an analysis of technological and technical and economic indicators of various options for combining layers into development objects.

Development objects are sometimes divided into the following types: independent, that is, being developed at a given time, and returnable, that is, one that will be developed by wells operating another object during this period.

An important component of creating such a system is the allocation of development objects. Therefore, we will consider this issue in more detail. It can be said in advance that combining as many reservoirs as possible into one object at first glance always seems to be beneficial, since such a combination will require fewer wells to develop the field as a whole. However, excessive combination of reservoirs into one object can lead to significant losses in oil recovery and, ultimately, to a deterioration in technical and economic indicators. The following factors influence the selection of development objects.

1. Geological and physical properties of oil and gas reservoir rocks. In many cases, reservoirs that differ sharply in permeability, total and effective thickness, as well as heterogeneity, are not advisable to develop as one object, since they can differ significantly in productivity, reservoir pressure in the process of their development and, consequently, in well operation methods, and the rate of oil reserves production. and change in water cut of products. For formations with different areal heterogeneity, different grids of wells can be effective, so it turns out to be impractical to combine such formations into one development object. In highly vertically heterogeneous formations with separate low-permeability interlayers that do not communicate with high-permeability layers, it can be difficult to provide acceptable coverage of the horizon by vertical stimulation due to the fact that only high-permeability interlayers are included in active development, and low-permeability interlayers are not exposed to the agent injected into the reservoir (water , gas). In order to increase the coverage of such reservoirs by development, they tend to be divided into several objects.

2. Physical and chemical properties of oil and gas. Of great importance in the selection of development objects are the properties of oils. Reservoirs with significantly different oil viscosities may not be appropriate to combine into one object, since they need to be developed using different technologies for extracting oil from the subsoil with different layouts and well grid densities. A sharply different content of paraffin, hydrogen sulfide, valuable hydrocarbon components, industrial content of other minerals can also make it impossible to jointly develop reservoirs as one object due to the need to use different technologies for extracting oil and other minerals from reservoirs.

3. Phase state of hydrocarbons and reservoir regime. Different reservoirs that lie relatively close to each other vertically and have similar geological and physical properties, in some cases it is not advisable to combine into one object as a result of the different phase state of reservoir hydrocarbons and reservoir regime. So, if there is a significant gas cap in one reservoir, and the other is developed under a natural elastic water-driven regime, then combining them into one object may not be appropriate, since their development will require different layouts and numbers of wells, as well as different oil and gas extraction technologies. .

4. Conditions for managing the process of developing oil fields ny. The more reservoirs and interlayers are included in one object, the more technically and technologically more difficult it is to control the movement of oil sections and the agent displacing it (water-oil and gas-oil sections) in separate reservoirs and interlayers, it is more difficult to carry out separate impact on interlayers and extract oil and gas from them , it is more difficult to change the speed of formations and interlayers. The deterioration of the conditions for managing the development of the field leads to a decrease in oil recovery.

5. Technique and technology of well operation. There may be numerous technical and technological reasons leading to the expediency or inexpediency of using certain options for selecting objects. For example, if it is supposed to take such significant fluid flow rates from wells operating a certain reservoir or groups of reservoirs identified as development objects that they will be the limit for modern well operation tools. Therefore, further enlargement of objects will be impossible for technical reasons.

In conclusion, it should be emphasized once again that the influence of each of the listed factors on the choice of development objects must first be subjected to technological and feasibility analysis, and only after that it is possible to make a decision on the allocation of development objects.

Reservoir development systems are classified according to the location of the wells and the type of energy used to move the oil.

Well placement. Well placement is understood as a grid of placement and distances between wells (grid density), the pace and order of putting wells into operation. Development systems are divided into the following: with the placement of wells on a uniform grid and with the placement of wells on an uneven grid (mainly in rows).

Development systems with the placement of wells on a uniform grid distinguish between: in the form of a grid; by mesh density; by the rate of putting wells into operation; according to the order of putting the wells into operation relative to each other and the structural elements of the deposit. Grids in a form happen square and triangular (hexagonal). With a triangular grid, more wells are placed on the area by 15.5% than with a square grid in the case of equal distances between wells.

Under grid density wells imply the ratio of the area of oil-bearing to the number of producing wells. However, this concept is very complex. Researchers often put different content into the concept of well pattern density: they take only the area of the drilled part of the reservoir; the number of wells is limited by different values of the total oil production from them; whether or not injection wells are included in the calculation; in the process of field development, the number of wells changes significantly, the area of oil-bearing under pressure regimes decreases, this is taken into account in different ways, etc. Sometimes there are small, medium and large degrees of well compaction. These concepts are very conditional and are different for different oilfield areas and periods of development of the oil industry. The problem of the optimal density of the well grid, which ensures the most efficient field development, was the most acute at all stages of the development of the oil industry. Previously, the density of the well grid varied from 10 4 m 2 / well (distance between wells 100 m) to (4-9) -10 4 m 2 / well, and from the late 40s - early 50s they switched to well grids with density (30-60) 10 4 m 2 / well. Based on the theory of interference and a simplified schematization of the process of oil displacement by water from a homogeneous reservoir, it was believed that when developing oil fields in a water-driven regime, the number of wells does not significantly affect oil recovery.

Development practice and further studies have established that in real heterogeneous reservoirs, the density of the well pattern has a significant impact on oil recovery. This effect is the greater, the more heterogeneous and discontinuous productive formations, the worse the lithological and physical properties of the reservoirs, the higher the viscosity of oil in reservoir conditions, the more oil is initially contained in the oil-water and sub-gas zones. Consolidation of a grid of wells in heterogeneous lenticular formations significantly increases oil recovery (development coverage), especially with successful well placement relative to various lenses and screens. The grid density has the greatest influence in the range of grid densities over (25 - 30) 10 4 m 2 /well. In the range of grid densities less than (25-30) 10 4 m 2 /SW, although the effect is noted, it is not as significant as with rarer grids. In each case, the choice of mesh density should be determined taking into account specific conditions.

Currently, two-stage drilling of initially rare grids of wells and their subsequent selective compaction are used in order to increase the coverage of heterogeneous reservoirs by waterflooding, increase the ultimate oil recovery and stabilize oil production. In the first stage, the so-called main fund of production and injection wells is drilled at a low grid density. According to the data of drilling and research of wells of the main fund, the geological structure of a heterogeneous object is specified, as a result of which changes in the density of the grid of wells are possible, which are drilled into the second stage and are called reserve. Reserve wells are 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 stock within the contour of their placement. The number of reserve wells is justified taking into account the nature and heterogeneity of the reservoirs (their discontinuity), the density of the well grid, the ratio of oil and water viscosity, etc. The number of reserve wells can be up to 30 % the main fund of wells. Their placement should be planned earlier in development. Note that, in order to replace<* ликвидированных скважин из-за старения (физического износа) или по техническим причинам (в результате аварий при эксплуатации добывающих и нагнетательных скважин) требуется обосновывать также число скважин-дублеров, которое может достигать 10 - 20 % фонда.

According to the rate of putting wells into operation, we can distinguish simultaneous(also called "solid") and slow deposit development system. In the first case, the rate of putting wells into operation is fast - all wells are put into operation almost simultaneously during the first one to three years of the development of the object. With a long commissioning period, the system is called delayed, which, according to the order of putting the wells into operation, is distinguished into thickening and creeping systems. It is expedient to use a thickening system on objects with a complex geological structure. It follows the principle of two-stage drilling. The creeping system, oriented with respect to the formation structure, is divided into systems: a) down dip; b) up the rebellion; c) along the stretch. In the practice of developing large domestic deposits, creeping and thickening development systems are combined in a complex. Only difficult natural (swamps, swamps) and geological conditions determined the use of the creeping system at the Samotlor field.

Development systems with placement of wells on a uniform grid are considered appropriate for reservoir operation modes with fixed contours (dissolved gas,

gravitational mode), i.e., with a uniform distribution of reservoir energy over the area.

Development systems with placement of wells along uneven the grid is similarly distinguished: by the density of the grid; according to the rate of putting wells into operation (putting rows of wells into operation - one row, two, three are in operation); according to the order of putting the wells into operation. Additionally, they are divided: according to the shape of the rows - with open rows and with closed (ring) rows; according to the mutual arrangement of rows and wells - with sustained distances between rows and between wells in rows and with compaction of the central part of the area.

Such systems were widely used in reservoir operating modes with moving circuits (water, gas, pressure-gravity and mixed modes). In this case, the wells were placed in rows parallel to the original oil-bearing contour. With modern design, the initial well spacing is almost always uniform.

Type of energy used. Depending on the type of energy used to move oil, there are: systems for the development of oil deposits under natural conditions, when only natural reservoir energy is used (without RPM); reservoir pressure maintenance systems, when methods are used to regulate the balance of reservoir energy by artificially replenishing it.

According to the methods for regulating the balance of reservoir energy, there are: development systems with artificial waterflooding; development systems with gas injection into the reservoir.

Development systems with artificial waterflooding can be carried out according to the following main options: contour, near-contour, intra-contour, barrier, block, with hearth, focal, areal flooding.

Development systems with gas injection into the reservoir can be used but in two main options: gas injection into elevated parts of the deposit (into the gas cap), areal gas injection.