Which reservoir flooding method is the most intensive. Types of flooding
The most widely used method of influencing the reservoir in order to maintain reservoir pressure and increase the final oil recovery is the method of pumping water into the reservoir (in the industrial literature, this method is called flooding). In Russia, more than 80% of oil deposits are developed using waterflooding.
Water is pumped through special injection wells. The location and grid of injection wells are determined in the technological scheme of field development. It is advisable to start pumping water into a productive formation from the very beginning of the development of an oil field.
In this case, it is possible to prevent a decrease in reservoir pressure due to fluid withdrawal from the reservoir, maintain it at its original level, maintain high oil flow rates from wells, intensify field development and ensure high oil recovery factors. As noted, waterflooding is subdivided into contour, near-contour and intra-contour.
With edge flooding (Fig. 24), water is injected into the formation through injection wells drilled outside the outer oil-bearing contour along the reservoir perimeter. The distance between injection wells is determined in the technological scheme for the development of this field. The line of injection wells is distributed approximately 400–800 m from the outer contour of oil-bearing capacity in order to create a uniform impact on the deposit, prevent the formation of premature watering tongues and water breakthroughs to production wells.
Outflow flooding is usually used in oil fields of small size and reserves, in deposits with good reservoir properties, both in terms of reservoir thickness and area. Under such conditions, edge flooding provides a more complete recovery of reserves, displacing oil to the tightening rows of production wells. The disadvantages of edge flooding include increased consumption of injected water due to partial drift beyond the injection line; slow response to the reservoir due to the remoteness of the injection line from production wells, etc.
Rice. 24 Edge flooding
A more effective impact on the oil reservoir is achieved when injection wells are located (drilled) inside the oil-bearing contour, in the water-oil zone of the reservoir, in more permeable areas of the deposit. Such waterflooding is called edge waterflooding.
Edge flooding is used:
- on small-sized deposits;
- with insufficient hydrodynamic connection of the productive formation with the external area;
– in order to intensify the process of oil production
A more effective system for influencing oil deposits, which makes it possible to increase oil production faster, reduce the terms of reserves development and increase the final oil recovery, is in-loop flooding (Fig. 25).
In case of in-loop waterflooding, injection wells are located (drilled) inside the oil-bearing contour. The choice of the layout and grid of injection wells is determined by specific geological conditions, physical and chemical properties of oil, etc.
Rice. 25 In-loop flooding
In recent years, to intensify the development of oil fields, the method of artificially “cutting” the deposit into separate areas or blocks has become a common method by pumping water into rows of injection wells located along the planned cutting lines within the natural oil-bearing contour. At the same time, artificial supply loops are created close to production wells, and each area is developed independently. In the initial period, during intra-loop flooding, water is injected into the oil deposit. Further, in the process of water injection into the deposit along the line of injection wells, a water shaft is formed, dividing the deposit into parts. For faster development of the in-loop waterflooding process, water is injected not into all injection wells of the cutting row, but through one well, and the intermediate wells of the row are operated temporarily as oil wells with forced oil recovery.
As the watering progresses, these wells are developed and transferred to injection wells. For the first time in our country, in-loop flooding was carried out at the largest oil field in Tatarstan - at the Romashkinskoye field, which was cut by rows of injection wells into 26 separate production areas.
In-loop waterflooding makes it possible to increase the rate of oil recovery and reduce the development time of large oil fields. In some cases, to intensify the development of an oil field, a combined effect is used, i.e. contour (contour) flooding with intra-contour central flooding.
Currently, several in-loop waterflooding systems are used, which differ from each other in the location of injection wells, the sequence of putting them into operation, the rate of water injection into the reservoir, as well as oil withdrawals from oil producing wells.
In case of intraloop waterflooding, spot waterflooding is also used. Local flooding is used in cases where there is no influence from flooding in certain areas of the deposit, as a result of which reservoir pressure drops in this area and, accordingly, oil flow rates in production wells fall. In case of spot flooding, an oil producing well is selected in the center of the site, transferred to an injection well, and water injection is started, as a result of which the effect of the injected water on the surrounding oil producing wells is ensured.
A selective system of in-loop waterflooding is also used. The most intense reservoir stimulation system is considered to be areal flooding. Production and injection wells in this system are placed in regular geometric blocks in the form of five-, seven- or nine-point grids, in which injection and production wells alternate. In order to intensify oil production and increase the final oil recovery, gas or air is injected into the productive formation, and water and gas are alternately injected into the formation.
An improved system for influencing an oil reservoir with a complex structure is the alternate injection of water and gas into the reservoir. At the end of 1971, based on the analysis of the development of the Zhuravlevsko-Stepanovskoye field in the Orenburg region, the method of alternate injection of water and gas into the oil deposit was substantiated and industrially tested in order to increase the efficiency of the displacement process and increase the final oil recovery. The essence of this method is as follows. The gas, when injected into the reservoir, penetrates, first of all, into highly permeable interlayers, reduces the phase permeability for water in them, as a result of which, during the subsequent injection of water into the reservoir, the displacement front is leveled.
and thereby increases the coverage of the formation by the impact. The water injected after the gas pushes it, due to its lower viscosity, into low-permeability dense interlayers, from where oil will be displaced as a result of piston and entraining gas displacement. The method of alternately pumping water and gas into the reservoir is a variant of the pulse impact on the reservoir, since in this case more favorable conditions are created for the manifestation of capillary forces due to a twofold increase in the surface tension of water at the boundary with oil. Partial dissolution of gas in oil, reducing its viscosity, also improves the efficiency of the process of oil displacement by water. Under the conditions of a fractured reservoir, these processes will be more efficient, since the solubility of the gas and the gravitational redistribution of the displacing agent in oil increase: solubility due to an increase in the contact surface, and gravitational redistribution due to the freedom of flows in open fractures. The gravitational redistribution of oil and injected gas in terms of thickness creates a condition that prevents advanced watering of the formation along the bottom in deposits with high oil viscosity. In addition, the utilization of associated gas at an early stage of development, due to the lack of consumers, solves one of the important tasks of protecting the environment and subsoil. Pilot work on this method was carried out at the Zhuravlevsko-Stepanovskoye field in Orenburg in 1971–1974 (authors V.I. Kudinov, I.A. Povorov) and gave good results. According to research and pilot works, the final oil recovery with alternate injection of water and gas into the reservoir increases by 8–10%. Further industrial implementation of this method is constrained by the lack of small-sized compressors for high pressure and performance.
Types of oil flooding
Outline flooding
Figure 2.1 - Scheme of regular waterflooding:
1 - production wells; 2 - injection wells
Wells are located in the aquifer aquifer (Figure 2.1). The use of an edge development system is possible when the water-oil contact can move with achievable pressure drops. The impact on the formation in this case is carried out through a system of injection wells located behind the outer contour of the oil-bearing capacity. The injection line is located approximately 300-800 m from the oil-bearing contour to create a more uniform impact on it, to prevent the formation of flood tongues and local
Outline flooding is expedient:
With good hydrodynamic connection of the oil-bearing formation with the area of injection wells;
with relatively small sizes of oil deposits, when the ratio of the area of the deposit to the perimeter of the oil-bearing contour is 1.5-1.75 km. At high values, the created pressure in the aquifer practically does not affect the formation pressure in the center of the reservoir, as a result, there is a rapid drop in formation pressure;
With a homogeneous formation with good reservoir properties both in thickness of the formation and in area.
Infinity flooding also has disadvantages. Among them are the following:
1. increased energy consumption (additional costs of pumping facilities) for oil recovery, since the injected water has to overcome the filtration resistance of the formation zone between the oil-bearing contour and the line of injection wells;
2. delayed impact on the reservoir due to the remoteness of the line
injection;
3. increased water consumption due to its outflow to the external
formation area beyond the injection line;
Edge flooding
Unlike edge flooding, injection wells are located directly on the oil-bearing contour.
The contour is applied:
With a deteriorated hydrodynamic connection of the formation with the external
region;
To intensify the operation process, since
filtration resistance between the injection and extraction lines
decrease due to their proximity.
However, the likelihood of formation of watering tongues and water breakthrough to individual wells of operational rows increases. This is associated with possible oil losses due to the formation of zones not covered by the impact between injection wells. Oil from these zones can only be displaced by careful management of the development process, including the drilling of additional wells.
From an energy point of view, near-edge waterflooding is more economical, although with good hydraulic conductivity of the outer area, losses of injected water are inevitable.
In-loop flooding.
They are mainly used in the development of oil deposits with very large areal dimensions. In-loop waterflooding does not deny out-of-loop waterflooding, and, if necessary, in-loop waterflooding is combined with out-of-loop waterflooding.
The division of the oil-bearing area into several areas (usually 4-5 km wide, and with low-permeability reservoirs - 3-3.5 km) by means of in-loop waterflooding allows you to enter the entire oil-bearing area into effective development at the same time.
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 zone of high pressure is formed, which prevents the flow of oil from one area to another. As the injection progresses, the pockets of water formed around each injection well increase in size and finally merge, forming a single water front, the progress of which can be controlled in the same way as in edge 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 “through one”. In the intervals, the design water injection wells are put into operation as oil producing ones, carrying out forced extraction in them. As the injected water appears in the "intermediate" wells, they are transferred to water injection.
Figure 2.2—Schemes of in-loop waterflooding.
1 - injection wells; 2- production wells
a) with cutting the deposit; b) axial
The production wells are arranged in rows parallel to the rows of water injection wells. The distance between the rows of oil wells and between wells in a row is chosen based on hydrodynamic calculations, taking into account the peculiarities of the geological structure and the physical characteristics of reservoirs in a given developed area.
A great advantage of the in-loop waterflooding system is the ability to start development from any area and, in particular, to put into development first of all areas with the best geological and operational characteristics, the highest density of reserves with high well flow rates.
In practice, the following types of in-loop waterflooding are used.
Axial, when injection wells cut the deposit along the axis of the fold (Figure 2.2). It is used for calm gently sloping anticlinal folds. In this case, it is possible to have one instead of several injection lines.
Focal, when separate sections of the deposit are exposed to flooding (Figure 2.3).
Figure 2.3—Scheme of localized waterflooding in combination with contour waterflooding.
1 - production wells; 2 - injection wells
Spot flooding is expedient at the middle and late stages of the deposit exploitation, when the issues of additional recovery of oil reserves from interlayers, pillars and dead-end zones not covered by the main development process are being addressed. As a rule, in case of spot 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 spot flooding, it is possible to drill special wells to increase the impact coverage of a larger volume of the oil-saturated part of the reservoir or its low-permeability zones.
block systems developments are used in elongated fields with the location of rows of water injection wells more often in the transverse direction. The fundamental difference between block systems is that block systems require the rejection of edge flooding (Fig. 7.4). as can be seen from the scheme, rows of water injection wells cut a single deposit into separate areas (blocks) of development. Block systems assume the location of injection wells in the direction perpendicular to the strike line of the fold.
Figure 2.4—Scheme of block waterflooding
The advantage of block systems is as follows:
1. Rejection of the location of water injection wells in the aquifer zone eliminates the risk of drilling wells in a part of the reservoir poorly studied at the stage of exploration of the deposit.
2. The manifestation of the natural forces of the hydrodynamic region of the aquifer part of the formation is more fully used.
3. Significantly reduces the area to be equipped with RPM facilities.
4. The maintenance of the reservoir pressure maintenance system (wells, sewage pumping station, etc.) is simplified.
5. Compact, close location of production and injection wells allows you to quickly solve the issues of development regulation by redistributing water injection in rows and wells and fluid withdrawal in production wells.
Areal flooding
The most intensive reservoir stimulation system, providing the highest rates of field development. Used in the development of formations with very low permeability.
With this system, production and injection wells are placed according to the correct schemes of four-, five-, seven- and nine-spot systems.
So, 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, seven- and nine-point systems are the most intensive among those considered.
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 uniformity of the formation and the amount of oil reserves per well, as well as the depth of the development object, have a great influence on the efficiency of areal waterflooding.
Under the conditions of a heterogeneous formation, both along the section and along the area, premature water breakthroughs to production wells along the more permeable part of the formation occur, which greatly reduces oil production during the anhydrous period and increases the water-oil ratio, so it is desirable to use areal flooding when developing more homogeneous formations in the latter. stages of field development.
The selective waterflooding system is a kind of areal waterflooding and is used in oil deposits with significant heterogeneity.
With a system of selective flooding, the development of a deposit is carried out in the following order. The deposit is drilled on a uniform triangular and quadrangular grid, and then all wells are put into operation as production wells. The design of wells is selected in such a way that any of them meets the requirements for production and injection wells. The oil deposit area is equipped with oil and gas collection facilities and reservoir pressure maintenance facilities so that any well can be developed not only as a production well, but also as an injection well.
By a detailed study of the section in the wells according to the logging data, by conducting hydrointerference in the wells, from among the producing wells, wells are selected for water injection. Such wells should be wells in which the oil-productive section is opened to the fullest extent. The hydrodynamic connection of the selected well with neighboring ones is traced.
Barrier flooding
In the development of oil and gas fields with a large volume of the gas cap, the task of simultaneously extracting oil from the oil rim and gas from the gas cap can be set.
Due to the fact that the regulation of oil and gas extraction, as well as reservoir pressure during separate oil and gas extraction, which does not lead to mutual flows of oil into the gas-bearing part of the reservoir, and gas into the oil-bearing part, is very difficult, 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 zone of gas-oil contact, and water injection and oil and gas withdrawals 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 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—Scheme of barrier flooding
The better the degree of exploration, the more reliably the location of the outer contour of oil-bearing capacity is determined, the steeper and more stable the reservoir, the closer to the contour it is possible to outline the injection line. The meaning of this requirement is to guarantee against the laying of injection wells in the oil-bearing part of the reservoir. The greater the distance between the injection wells, the greater should be the distance from the oil-bearing contour to the injection line. The fulfillment of this requirement ensures the preservation of the shape of the oil-bearing contours without sharp tongues of water intrusion into the oil part of the reservoir. The greater the distance between the inner and outer contours of oil-bearing capacity, the greater the distances can be set between injection wells, since when the operating zone is removed from the injection zone, the interaction of individual injection and production wells will be less pronounced, it will affect the interaction of injection and extraction lines . The meaning of this requirement also lies in the uniformity of the movement of the oil-water contact.
Questions of the theory of oil displacement by water in a fractured-porous reservoir
The experience of developing oil fields shows that not only carbonate rocks are saturated with fractures, but also layers of sandstones or siltstones are more or less fractured. This is indicated by the discrepancy between the permeability estimated for cores of rocks without fractures and the permeability determined during hydrodynamic studies of wells. Reservoir permeability is much higher than determined from cores without fractures.
When the rocks themselves are low-porosity and poorly permeable, fractures become the main channels for the movement of oil to the bottomholes of production wells. During the development of fractured porous formations, pressure spreads faster through the fracture system. Therefore, there are differences between pressures in fractures and blocks, which cause fluid overflows between fractures and blocks (matrices) of rocks. This leads to a delay in pressure redistribution compared to pressure redistribution in homogeneous reservoirs.
The water injected into such formations quickly breaks through the cracks to the production wells, leaving the oil in the rock blocks. Oil is displaced quite efficiently from the fracture system itself, the displacement efficiency reaches 0.85. Oil from rock blocks is not displaced efficiently enough, the oil displacement coefficient is about 0.25.
Oil is displaced by water from blocks of fractured porous formations under the action of forces caused by pressure gradients in the system of fractures that also affect rock blocks. On the other hand, oil is displaced by the difference in capillary pressure between water and oil. Its action leads to the appearance of capillary impregnation of hydrophilic rocks, i.e., to the replacement of oil with water in them under the action of a difference in capillary pressure. Capillary impregnation is also explainable from the energy point of view. Since the minimum surface energy at the oil-water interface will be reached when oil comes together in fractures, and does not saturate matrix rocks with a complex, highly branched surface.
Therefore, if a rock block of a fractured porous reservoir saturated with oil is placed in water (a similar situation occurs when a block in a real reservoir is surrounded by cracks filled with water), then the velocity j(t) capillary absorption of water into the block and, consequently, the 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 is the experimental coefficient.
For reasons of dimension and physics of the absorption process, the coefficient b can be expressed like this:
b= , A \u003d A (k n, k in, m, ) , (2.4)
Where k n, k in– 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 is the viscosity of oil;
A– experimental function;
l- the length of the face of the reservoir rock cube.
Expression for coefficient A, based on the condition that for an infinite time the amount of water absorbed into the 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 is the initial oil saturation of the rock block;
h- the final oil recovery of the block during its capillary impregnation.
When considering the displacement of oil by water from a fractured-porous reservoir consisting of many blocks of rock, we represent these blocks as cubes with a face length l. Since the displacement of oil by water begins from the reservoir boundary at X= 0, then the blocks at the entrance to the reservoir will be saturated with water more than the next ones. Water consumption q, injected into a straight formation, goes into a certain number of rock blocks, so that at each moment of time the impregnation occurs in the region of 0 £ x £ x f (x f is the coordinate of the capillary impregnation front). This front moves in the reservoir with the speed:
v f = d x f / dt. (2.6)
If we assume that rock blocks in each section of the reservoir begin to be impregnated at the time l(when the front of capillary impregnation has approached 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 “entered” into the impregnation, then the water consumption Dq included in these blocks will be:
Dq = 
. (2.7)
In order for 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 done in formula (2.7). The impregnation rate in (2.3) is calculated from the moment l, in which to the block with coordinate x f (l) the front of water soaking into the blocks approached.
Summing up cost increments Dq in formula (2.7) and letting Dl to zero, we arrive at the expression:
q = 
v f (l)dl.(2.8)
At a given flow q expression (2.8) is an integral equation for determining the speed of advance of the impregnation front v f (l).
Substituting into (2.8) the expression for the impregnation rate (2.3) we get:
The solution of the integral equation (6.9) allows us to write an expression for the velocity 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 waterless reservoir development t = t *, with which x f (t *) \u003d l.
To calculate the development indicators of a fractured-porous formation during the period of production of watered products, the following is done. It is believed that this layer "fictitiously" extends at x > l to infinity. The water consumption spent on the impregnation of the fictitious part of the reservoir at x > l, will be:
q fict =bhbms but h. (2.12)
Substituting here v f (l) by expression (2.10), and replacing in it t on l, we get:
qfict =qbdl.(2.13)
Consequently, the flow rate of water soaking into the fractured porous formation during the period t > t*, or the oil production rate received during this period is equal to:
q n \u003d q - q fictitious. (2.14)
The water flow rate will accordingly be q in = q f. From the above expressions, it is possible to determine the current water cut of production and oil recovery by general formulas. Expression (2.3) can be used for approximate calculations of oil displacement from a fractured porous formation in the case of impregnation of blocks, due not only to capillary forces, but also to pressure gradients in the fracture system. Thus, according to formulas (2.3) and (2.4), oil is displaced from rock blocks under the action 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 action of a pressure gradient. Dimension grad P expressed as Pa/m. Capillary and hydrodynamic will have the same dimension if we take instead of scosq value ( s cosq) / l. Then:
b = k( + gradP) (2.15)
Thus, formula (2.15) takes into account the impregnation of rock blocks due to both capillary forces and pressure gradients in the fracture system.
Questions for self-control:
1. For what reasons is there a delay in the redistribution of pressure in fractured-porous formations in comparison with the redistribution of pressure 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 energy 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 the expressions for the speed of the capillary impregnation front and for determining its position (coordinates)
6. Write down the formula that allows you to determine the duration of the waterless development of a fractured-porous reservoir
Plan
Introduction
1. Geological part
1.1 Brief geological and field characteristics of the oil (gas) field
1.2 Basic information about stratigraphy, lithology and tectonics
1.3 Characteristics of oil, gas and formation waters
2. Technological part
2.1 Current state of development and dynamics of the main technological indicators of the field
2.2 Analysis of the state of the RPM system
3. Design part
3.1 New machinery and technology for wastewater treatment
3.2 Ways to improve the technology of water injection into the reservoir
4. Estimated part
4.1 Calculation of the development time of an oil deposit
4.2 Calculation of the injection process of those. liquids into wells
5. Safety and environmental friendliness of the project
5.1 Occupational health, safety and fire prevention
5.2 Subsoil and environmental protection
Conclusion
Bibliography
Introduction
Formation waters separated from oil during its collection and preparation are highly mineralized, and for this reason they cannot be discharged into rivers and reservoirs, as this leads to the death of freshwater. Therefore, formation waters are pumped into productive or absorbing formations. Together with reservoirs, fresh water is also pumped in, which is used in the technological process during oil desalination, as well as storm water that enters the industrial sewer system. In general, all these waters are called sewage. In the total volume of wastewater, stratal water accounts for 85-88%, fresh water - 10-12%, and storm water - 2-3%. The use of oilfield wastewater in the reservoir pressure maintenance system in the water-driven mode of field development is an important technical and environmental measure in the oil production process, which allows for a closed cycle of circulating water supply according to the scheme: injection well - reservoir - production well - oil and gas collection and treatment system with a water treatment unit - PPD system. At present, several types of water are used for the purposes of RBP, which are determined by local conditions. This is fresh water extracted from special artesian or underflow wells, water from rivers or other open water sources, water from aquifers found in the geological section of the field, formation water separated from oil as a result of its preparation. All these waters differ from each other in physical and chemical properties and, consequently, in the effectiveness of the impact on the formation, not only to increase pressure, but also to increase oil recovery. The oil deposits of most fields in the Ural-Volga region are multilayer with high layered heterogeneity of rocks in terms of permeability and small effective oil-saturated thicknesses. A number of fields are characterized by hydrodynamic communication between reservoirs, due to the merging of layers or a small thickness of sections between them with the presence of fracture systems. The problems of efficient development of hard-to-recover reserves are solved by downscaling production facilities, optimizing well grids, improving waterflooding systems, optimizing reservoir and bottomhole pressures, and applying hydrodynamic secondary and tertiary well stimulation methods. Thus, one of the main conditions for further increasing the efficiency of reservoir flooding is to limit the movement of water through channels with low filtration resistance, which will allow more rational use of its energy to displace oil. In the scientific and technical literature, studies on the role of the quality of injected water are not sufficiently covered. Under flooding conditions, the completeness of the development of productive formations primarily depends on the degree of coverage of the development object both in terms of area and section, which is largely determined by the nature of the movement of injected water and formation water. Therefore, the main attention in the geological and field analysis should be given to the issues of formation coverage by the effect of injected water and the features of water movement through productive formations. Geological and physical factors affecting the waterflooding process include the filtration properties of productive formations, the nature and degree of their heterogeneity, the viscosity properties of saturating formations and the quality of fluids injected into them, etc.
1. Geological part
1.1 Brief geological and field characteristics of the oil (gas) field
The Arlanskoye field is unique in terms of oil reserves, located in the north-west of Bashkiria within the Volga-Ural oil and gas province. It is located on the territory of Krasnokamsky and Dyurtyulinsky regions of the republic and partly on the territory of Udmurtia. The field was discovered in 1955 and put into development in 1958. Terrigenous deposits of the Visean stage of the Lower Carboniferous and carbonate deposits of the Moscow stage of the Middle and Tournaisian stages of the Lower Carboniferous are commercially oil-bearing. The main object of exploitation are terrigenous formations of the Lower Carboniferous. For the further development of the Arlan deposit, the development of the Middle Carboniferous deposits is of great importance. The industrial oil content of the latter was established almost simultaneously with the discovery of the field, but due to the complex structure of the deposits, it did not attract much attention for a long time. The length of more than 100 km, with a width of up to 25 km, is confined to an extensive anticlinal fold with gentle wings. Oil-bearing sandstones of the Visean stage of the Lower Carboniferous age, carbonate reservoirs of the Kashira-Podolsk productive strata of the Middle Carboniferous. The main reserves are concentrated in the sandstones of the terrigenous strata of the Lower Carboniferous (75% of the initial reserves) at a depth of 1400-1450 m. During the development, waterflooding is used. The main method of exploitation of producing wells is mechanized. The total fund of wells is about 8 thousand units. Oil is produced with a high water content (93%).
1.2 Basic information about stratigraphy, lithology and tectonics
The Arlan oil field is one of the largest in the country and the largest in Bashkortostan. Its length along the oil-bearing contour in the terrigenous sequence of the Lower Carboniferous (TTNK) is more than 100 km, and its width is up to 30 km. Oil-bearing are the TTNK sandstone layers (Elkhovsky, Radaevsky, Bobrikovsky, Tula and Aleksinsky horizons of the Visean stage), carbonates of the Tournaisian stage, Vereya, Kashirsky and Podolsk horizons of the Moscow stage of the Middle Carboniferous. The deposit is confined to a vast asymmetric anticline of the northwestern direction. Its southwestern flank is steep (up to 4°), the northeastern flank is more gentle (up to 1°). The amplitude of the structure along the closed isohypse of 1190 m is 90-100 m. In the core of the fold there is a giant barrier reef of the Upper Devonian (Famennian) age. Along the top of the TTNK, the structure is complicated by a large number of local uplifts of smaller size and amplitude. Their sizes vary, but do not exceed 1-5 km. Up the section, the structure is less contrasting and is almost leveled in the Permian deposits. The depth of occurrence of the TTNK is 1250-1300 m; it submerges regionally from south to north. In the section TTNK, nine layers of sandstones are distinguished and clearly correlated: Aleksinsky horizon - layer C 0; the Tula horizon – layers C I , C II , C III , C IV0 , C IV , C V and C VI0 ; Bobrikovsko-Radaevsky horizon - layer C VI. The thickness of the reservoirs varies dramatically from well to well. The C II, C III (in the northern part of the field) and C VI formations are among the main and most consistent in terms of area. The remaining layers have smaller thicknesses and are more heterogeneous. Sandstones are characterized by rather high porosity and permeability properties (PRP). The thickness of the TTNK ranges from 33 to 150 m. Its sharp increase is confined to zones of deep erosion of the carbonate sequence of the Tournaisian stage. In some wells, Tournaisian limestones are completely eroded, and the formed karst sinkholes are filled with a thick layer of terrigenous deposits. Carbonate reservoirs of the Middle Carboniferous (Kashiro-Podolsky and Tournaisian) have much worse properties (low permeability and porosity, small thickness). Oils of all objects have high viscosity (20-30 mPa⋅s), their density is 0.88-0.90 t/m3. The saturation pressure in the HPTC is 8 MPa, gas saturation is from 5 to 20 m3/t. The oil content of the section of the Middle Carboniferous was studied mainly along with the search and exploration of oil deposits in the terrigenous sequence of the Lower Carboniferous. Stratigraphically, the Middle Carboniferous deposits include the upper part of the Bashkirian stage and the full extent of the Moscow stage. They are composed of carbonate rocks with subordinate interlayers of marls, mudstones, and siltstones, occurring mainly in the Vereisk horizon. According to the complex of geological and field geophysical materials, the considered deposits are divided into 11 packs (I-XI), of which the II-VII packs of the Kashirsky and Podolsky horizons are commercially oil-bearing, and the productivity of the latter has been established only in the Vyatka area. The identified units are quite clearly traced not only within the considered deposit, but also in a large area of the Birsk saddle and adjacent areas of the Perm-Bashkir arch and the Upper Kama depression. Each of the units is a rhythmically constructed lithological complex, the lower part of which is made up of carbonate rocks with a high content of porous-permeable varieties, and the upper part is predominantly dense impermeable carbonates, clayey and clayey-carbonate deposits. According to the standard logging, the bottoms of each member, as a rule, are characterized by negative SP readings, low GM, positive MZ increments, low and medium GM values, and when subdividing and correlating the Middle Carboniferous section, they are conventionally identified as a productive reservoir. Opposite electrical and radio logging characteristic is the upper, most dense part of the section of the considered packs, which is distinguished as a "dense section" and is estimated as an oil reservoir. The marked productive strata are confined to: B1 (member XI) - to the Bashkirian stage, overlying B1-B3 (members VIII-X) - to the Vereian, K1-K4 (members IV-VII) - to the Kashirian, P1-P3 (members I and III ) - to the Podolsky horizons. When comparing these productive strata, a complex lenticular nature of the distribution of the reservoir interlayers contained in them is revealed, due to frequent changes in the mineralogical composition, structural and textural composition, capacitive and filtration properties of rocks. Studies have shown that the lithologically heterogeneous productive section of the Middle Carboniferous is universally associated with recrystallization, dolomitization, sulfatization, silicification, etc. Within the Arlanskoye deposit, when moving to the Novokhazinskaya area, a significant qualitative change in the productive section is noted, the lithological heterogeneity (segmentation) of III-VI units sharply increases, the degree of their dolomitization and sulfatization increases, the intensity and variety of forms of manifestation of post-sedimentary transformations increase, the reservoir properties and oil saturation of the constituent rocks significantly deteriorate, and the stratigraphic level of oil-bearing reservoirs decreases. The listed features naturally increase in the southeast direction, and in the Yusupov area of the Arlanskoye deposit, the entire Middle Carboniferous section becomes unproductive. In the Arlanskaya and Nikolo-Berezovskaya areas, the III and IV packs are commercially oil-bearing, confined to the base of the Podolsky (P3) and the top of the Kashirsky (K1) horizon, respectively, and in the Novokhazinskaya area, moreover, only in its northern half (Sharipovsky area), the underlying V and Member VI (K2 and K3) identified in the middle of the section of the Kashirian horizon. In the northwestern part of the Arlan field in the Vyatka area, the range of commercial oil content increases, covering the II-III units of the Podolsky horizon (P2 and P3) and the IV, V and VII units of the Kashirsky horizon (K1, K2 and K4), the total thickness of which reaches 110 m ( Fig. 1).
Fig.1. Scheme of distribution of oil deposits in the Middle Carboniferous of the Arlan field
Distribution of oil-bearing capacity of productive formations: a - P 2 , P 3 , K 1 , K 2 , K 4 ; b - P 3, K 1; c - K 2, K 3; operating areas: 1 - Vyatskaya 2 - Arlanskaya, 3 - Nikolo-Berezovskaya, 4 - Novokhazinskaya. In the process of prospecting and exploration work on the territory of the Arlanskoye field, oil shows were noted, and in the well. 92 and 210 in the Nikolo Berezovskaya area, oil inflows were obtained during the opening and testing of layers B2 and B3 (packs IX and X), occurring in the lower part of the Vereisk horizon. However, their oil content is still not entirely clear. From the conducted structural-facies analysis, it follows that the preconditions for an extremely heterogeneous (differentiated) spatial distribution of oil content in the Middle Carboniferous (more precisely, Kashirsko-Podolsk) deposits of the Arlanskoye field were laid down during the period of accumulation and primary (sedimentation-diagenetic) transformation of sediments in a shallow offshore marine basin with sharply dissected bottom topography, unstable hydrodynamic, temperature and hydrochemical regimes, and a generally hot climate. This led to the predominant accumulation of carbonate sediments, characterized by structural mineralogical heterogeneity and a variety of forms of manifestation in the subsequent phases of their transformation (late diagenesis, epigenesis) of secondary processes, among which a special role belonged to dolomitization and genetically closely related sulfatization.
1.3 Characteristics of oil, gas and formation waters
On the territory of the northern half of the deposit (Arlanskaya, Nikolo-Berezovskaya and Vyatskaya areas), located hypsometrically below the Novokhazinskaya area, the accumulation and transformation of the Kashirsko-Podolsk deposits took place with the combined participation of a fairly intense hydrodynamic activity of sea waters and cation-exchange (metasomatic) processes, which generally have a positive effect on the formation of reservoir rocks. As a result, the main part of the porous-permeable interlayers of productive strata K 1 and P 3 is made up of organogenic-relict (metasomatic) dolomites and biomorphic (mainly foraminiferal) dolomitic limestones, the appearance of the pore space in which is due to the primary stacking of formed elements (mainly shells of organisms) sediment with the active participation of dolomitic metasomatism. The transformation of sediments in subsequent phases took place mainly under the action of leaching of calcareous relic sites not replaced by dolomite. A significantly different situation of carbonate accumulation in the Kashirsko-Podilsk time was on the territory of the Novokhazinskaya area, which was a vast shoal, somewhat isolated from the main waters of the sea basin. Here, under the influence of high alkalinity, salinity, and temperature of the seabed, the solubilities of CaCO 3 and MgCO 3 converged, which contributed to the transformation of these components into dolomite and its intensive accumulation. Moreover, the optimal conditions for the sedimentation of dolomites are achieved by the time of supersaturation of natural marine under calcium sulfates. According to field geophysical surveys of wells, up to six layers of porous-permeable rocks are distinguished in the productive formation K 1 in the Arlanskaya and Nikolo-Berezovskaya areas, and up to two in the P 3 formation. Each of the interlayers has a thickness of 0.5 to 3-4 m. The highest degree of lithological heterogeneity and pronounced lenticularity of reservoirs, which determine their weak hydrodynamic connection and extremely low productivity, are observed in the productive formations K 2 and K 3 of the Novokhazinskaya area. In the section of productive formations, among porous-permeable interlayers well saturated with oil at elevated hypsometric marks (above WOC), interlayers with highly porous rocks (more than 15%) are often found, which, due to low permeability (less than 0.005 μm 2) and their lenticular occurrence, turned out to be slightly oil-saturated (non-industrial) or completely aquiferous. Such layers prevail over well-saturated ones in the sections of most wells. In many of them, the beds contain only buried water. The presence of water-saturated interlayers among well-saturated ones is confirmed by the production of water together with oil in wells located at high hypsometric levels (Fig. 2).
Rice. 2. Schematic profile of the oil-bearing unit of the Kashirsko-Podolsk deposits of the Arlan area. a - dense section between the layers; interlayers: b - industrially oil-bearing, c - slightly oil-saturated, d - water-saturated; e - VNK; e - dense rocks in the reservoir; 1-8-wells
To assess the effective oil-saturated thickness of productive formations in these cases, it is not enough to use the traditional method of establishing the lower limit of porosity, at which the rocks become impermeable and lose their reservoir properties. This boundary for the Kashirsko-Podilsky deposits is 9-11%. The determining factor here is the minimum value of oil saturation. When elucidating the nature of the saturation of the layers, materials from studies of oil and gas condensate, BC (preferably on highly mineralized water) and soils were used according to the generally accepted methodology. On the basis of the obtained distributions of resistivity (r p) of the reservoirs occurring in the obviously oil and water-bearing parts of the deposit, and the distributions of the complex parameter Kp 2 r p for the same reservoirs, their critical values for oil-bearing reservoirs were revealed (r p = 7 Ohm-m and Kp 2 r p r p \u003d 0.41). Using specific dependencies r p =f(k p) and pp = f(Kn), obtained from the study of core samples, the lower limit of the oil saturation coefficient (Kn) is set from 0.62 to 0.67. These values are in good agreement with the well test results, i.e. in none of the tested intervals, from which commercial oil flows were obtained, formations with oil saturation less than 67% are distinguished. Thus, according to the described method, the following parameters were determined for each productive layer: h eff, r p, Kp and Kn. In some cases, to assess the nature of the saturation of the reservoirs, the materials of the INOC were involved, confirming the established value of oil saturation in terms of rp. The boundary of the oil deposit or the contour of oil-bearing capacity in these conditions is the line of replacement of commercially oil-bearing reservoirs with impermeable rocks. By the nature of the distribution of oil-saturated reservoirs within the entire area of the field, vast, medium and small in size and isolated from each other areas of oil-bearing are distinguished. The revealed features of the distribution of oil content and the structure of oil deposits in the carbonate deposits of the Middle Carboniferous of the Arlan field made it possible to identify objects of calculation, areas with different categories of reserves, determine the calculation parameters, establish expected oil recovery factors for various sections of the deposit, calculate the balance and recoverable reserves of oil and gas dissolved in it for industrial categories A, B and C 1 . The field is equipped, oil deposits in the Middle Carboniferous have a shallow depth, which allows them to be quickly and cost-effectively put into commercial development.
2. Technological part
2.1 Current state of development and dynamics of the main technological indicators of the field
Let's analyze the technical and economic indicators of the Arlan UDNG presented in Table 1.
Table 1 - The main technical and economic indicators of the Arlansky UDNG for 2006-2008
| Indicators | 2006 | 2007 | 2008 |
| Oil production thousand rubles | 2168,5 | 2156 | 2181 |
| Marketable oil tons | 2153,043 | 2140,664 | 2170,173 |
| Gross output thousand rubles | 1627180 | 1504413 | 1618174 |
| Average daily flow rate of wells for oil per well worked out of the operating stock ton/day | 2,3 | 2,2 | 2,2 |
| Fluid production t.t. | 12119 | 13325 | 13913 |
| 82,1 | 83,8 | 84,3 | |
| Putting new oil wells into operation SCR | 27 | 30 | 28 |
| including from intelligence | 2 | 2 | 3 |
| 0,954 | 0,956 | 0,950 | |
| Fulfillment of the volume of capital investments thousand rubles. | 331856 | 700545 | 556037 |
| including development drilling thousand rubles | 82429 | 119800 | 173315 |
| exploration drilling | 58183 | 124000 | 77706 |
| Well construction | 76762 | 173418 | 124632 |
| The average annual cost of fixed industrial and production assets for core activities | 2842535 | 3180431 | 3925996 |
| Return on assets (output of gross output per 1 rub. of the average annual cost of the industrial production fund) rub | 0,57 | 0,47 | 0,41 |
Let's start with the analysis of the production program. In 2008, the plan for oil production was exceeded by 3.1%. The annual level of oil production in 2008, compared with 2007, increased by 25 thousand tons.
At the same time, the volume of marketable oil increased and amounted to 101.4% of the 2007 level.
Figures 3 and 4 show the dynamics of oil and liquid production over the last 5 years of operation of OGPD Krasnokholmskneft.
Rice. 3 Dynamics of fluid production
Rice. 4 Dynamics of oil production
In recent years, against the background of an increase in fluid production, oil production has been gradually decreasing, which indicates an increase in the degree of water cut in wells. In 2008, more water was injected, which resulted in an increase in liquid production by 462.7 thousand tons.
Let us analyze in more detail the change in the volume of oil production and the factors that influenced this change.
For clarity, we will compile table 2 of data changes for 2008 in relation to 2006 and 2007.
Table 2 - Changes in the main TEP
| Indicators | absolute change | % change | ||
| 2008- 2006 | 2008-2007 | 2008/2006 | 2008/ 2007 | |
| Oil production thousand rubles | 12,5 | 25,0 | 100,6 | 101,2 |
| Gross output thousand rubles | -9006,0 | 113761 | 99,5 | 107,6 |
| Average daily production rate of wells for oil per well worked out of the operating stock ton/day | -0,1 | 0 | 95,7 | 100,0 |
| Oil water cut (weight) % | 2,2 | 0,5 | 102,7 | 100,6 |
| Operating factor of the existing oil well stock | -0,004 | -0,006 | 99,58071 | 99,37238 |
The average daily oil production rate of wells is falling, but in 2008, thanks to the measures taken, it remained at the level of the previous year.
It can be seen that the water cut of the produced oil is growing (Fig. 5), which has a negative impact on oil production. Compared to 2000, oil water cut (by weight) increased by 2.2%.
Rice. 5 Dynamics of oil water cut (weight) %
The operating factor of the existing well stock is decreasing, which entails a decrease in oil production.
The number of oil wells increases evenly (Fig. 6) every year by about 29. Thanks to this, the level of oil production is maintained.
Rice. 6 Dynamics of the number of wells (wells)
2.2 Analysis of the state of the RPM system
The natural regimes of occurrence of oil deposits are short-lived. The process of reservoir pressure reduction accelerates as fluid withdrawals from the reservoir increase. And then, even with a good connection of oil deposits with the supply circuit, its active impact on the deposit, the depletion of reservoir energy inevitably begins. This is accompanied by a widespread decrease in the dynamic levels of fluid in the wells and, consequently, a decrease in production. When organizing reservoir pressure maintenance (RPM), the most difficult of the theoretical issues and still not fully resolved is the achievement of maximum oil displacement from the reservoir with effective control and regulation of the process. It should be borne in mind that water and oil differ in their physical and chemical characteristics: density, viscosity, surface tension coefficient, wettability. The greater the difference between the indicators, the more difficult is the process of displacement. The mechanism of oil displacement from a porous medium cannot be represented by a simple piston displacement. Here there is a mixture of agents, and breakage of the oil jet, and the formation of separate, alternating flows of oil and water, and filtration through capillaries and cracks, and the formation of stagnant and dead-end zones. The oil recovery factor of the field, the maximum value of which the technologist should strive for, depends on all the above factors. The materials accumulated to date make it possible to assess the impact of each of them. A significant place in the efficiency of the reservoir pressure maintenance process is occupied by the placement of wells in the field. They determine the pattern of flooding, which is divided into several types. Reservoir pressure maintenance, which first appeared in our country under the name of edge flooding, has become widespread. Today, it is a secondary method of oil production (as it was called at the beginning), and an indispensable condition for the rational development of deposits from the first days is laid down in development projects and carried out at many fields in the country. At the Arlanskoye field in different years, large-scale experiments were carried out on pilot testing of methods for increasing oil recovery. The largest of them was the long-term injection of a surfactant solution in the Nikolo-Berezovskaya area. Unfortunately, the result was negative and the experiment was terminated. Among the largest is also an experiment to study the dependence of recovery factor on the density of the grid of producing wells in the Novokhazinskaya area. The scale of these works was unique. The results obtained unequivocally proved that the development of reserves is significantly determined by the density of the grid. In addition to the above experiments at the field, on a pilot and industrial scale, work was carried out on in-situ combustion (it was possible to organize combustion, but the results turned out to be negative due to the presence of acidic products), intensification of the development of non-drained reserves of thin reservoirs by reducing the distance between production and injection wells, polymer flooding, changing the direction of filtration, injection of gel-forming compositions, etc. It can be noted that the development of deposits of the Middle Carboniferous and the Tournaisian stage is still haphazard, since there is no own grid of wells for these objects, as well as a reservoir pressure maintenance system (except for the Vyatka area, on which the deposits of the Kashira-Podolsky horizon were drilled along their own grid of wells using waterflooding). The development of these facilities is mainly planned at the expense of the revolving fund. In total, about 9 thousand wells for various purposes have been drilled. The water cut of the product is 95%. Oil production decreased to 4.2 million tons/year. More than 1,000 wells have been decommissioned. Liquid withdrawal also decreased from 160 to 80 million tons. Over the entire period of development, 457 million tons of oil were produced, including 404.2 million tons from TTNK. However, despite some shortcomings, the development of the field can be assessed as satisfactory. The achieved recovery factor is 0.396, and the state of development allows us to hope that the approved recovery factor will be achieved. The RPM flowsheet at the Arlansky UDNG is determined by the oil field development project and, first of all, by the number and location of injection wells. It is possible to single out the following principal systems of the PPD of the Arlan UDNG:
a) an autonomous system, when the injection facility (pumping station) serves one injection well and is located in close proximity to it;
b) a centralized system, when the pumping station ensures the injection of the agent into a group of wells located at a considerable distance from the pumping station.
In turn, the centralized PPD system is subdivided into group and beam. With a group system, several wells are supplied with one injection pipeline: a type of group system is the use of distribution points (RP), in this case, a group of wells is connected directly to the RP. With a beam system, a separate injection conduit is supplied from the pumping station to each injection well. The autonomous system includes a water intake structure, a lifting station, an injection pumping station, and an injection well. The water intake facility is a source of water supply: water is produced here for the purpose of injection into the reservoir. Water intakes are subdivided into: a) underflow; b) open. In understream water intakes along the riverbed, understream wells are drilled with a depth of 12 ... 15 m and a diameter of 300 mm to the aquifer. The rise of water is carried out by an artesian or electric pump lowered into the well. In siphon water intakes, water is pumped out from wells under the action of a vacuum created by special vacuum pumps in a vacuum boiler, and the water entering them is pumped out by pumps to the pumping station P of the lift and the injection facility. In open water intakes, the pump unit is installed near the water source and pumps water out of it to the injection site. Underground pumping stations with pumps located below the river level can be used. In recent years, an increasing share of the water injected into the reservoir is occupied by wastewater, which is treated at special facilities and pumped out to the injection sites. The centralized injection system includes a water intake, a second lift station, a cluster injection pumping station and injection wells. A cluster pumping station (CPS) is a special structure made of concrete or brick, which houses pumping and power equipment, technological piping, starting and control equipment. In recent years, block NCS have become widespread at the Arlansky UDNG, which are manufactured at factories in the form of separate blocks and delivered to the installation site assembled.
3. Design part
3.1 New machinery and technology for wastewater treatment
Oilfield wastewater is a dilute disperse system with a density of 1040-1180 kg/m 3 , the dispersion media of which are highly mineralized brines of calcium chloride type (sodium chloride, calcium chloride). Dispersed phases of wastewater - oil droplets and solid suspensions. When well production is extracted from the subsoil, formation water, which is in an emulsified state, practically does not contain any contaminants: impurities do not exceed 10-20 mg/l, but after the separation of the emulsion into oil and water, the content of dispersed particles in the separated water increases greatly: oil - up to 4-5 g/l, mechanical impurities - up to 0.2 g/l. This is explained by the fact that as a result of a decrease in the interfacial tension at the oil-water boundary due to the introduction of a demulsifying agent into the system and the turbulence of the stratified flow, the dispersion of oil in water is intensified, as well as the washing and peptization of various sludge deposits (corrosion products, clay particles) in the morning pipeline surfaces. In addition, an intermediate layer is accumulated in water separators, consisting of water droplets with undestroyed armor shells, agglomerates solid particles, mechanical impurities, asphalt-resinous substances and high-melting paraffins, microcrystals of salts and other pollutants. As it accumulates, part of the intermediate layer is discharged with water, and a significant amount of contaminants passes into the aquatic environment. As a result of mixing waters of different chemical composition, the sulfate balance is disturbed, which also leads to an increase in solid sediment. Wastewater contains dissolved gases: oxygen, hydrogen sulfide, carbon dioxide, which intensify their corrosive activity, which leads to rapid wear of oilfield equipment and pipelines and, consequently, secondary pollution of wastewater with corrosion products. Wastewater contains ferrous iron - up to 0.2 g/l, the oxidation of which leads to the formation of sediment and carbon dioxide. Oilfield effluents can be contaminated with sulfate-reducing bacteria from stormwater that precipitate calcium carbonate and iron sulfide. The presence of oil droplets and mechanical impurities in waste water leads to a sharp decrease in the injectivity of productive and absorbing layers. Therefore, before pumping wastewater into productive or absorbing formations, their treatment is required. The main water quality indicators that make it possible to use them are:
4) concentration of hydrogen ions (рН) – 8.5…9.5;
These data are based on the experience of application of reservoir pressure maintenance at the Tuymazinskoye field and should be reviewed when organizing reservoir pressure maintenance in other areas. At the Tuymazinskoye field, a chemical treatment of fresh water was tested to remove salts and suspended particles from it. Subsequently, many water treatment processes were abandoned, considering them unjustified. However, if for this field, which has high porosity and reservoir permeability, the refusal to treat water using the above technology did not cause significant complications in the operation of the system, it could be unacceptable for other regions. Then the formation water injection began, which required its own approach. Formation waters are distinguished by a high content of salts, mechanical impurities, dispersed oil, and high acidity. Thus, the water of reservoir D 1 of the Tuymazinsky oil field belongs to highly mineralized brines of the calcium chloride type with a density of 1040 ... 1190 kg / m3. with salt content up to 300 kg/cu.m. (300 g/l). The surface tension of water at the boundary with oil is 5.5...19.4 dynes/cm, the content of suspended particles is up to 100 mg/l, the granulometric composition of suspended solids is characterized by a predominant content of particles up to 2 microns (more than 50% by weight). Formation waters from the process of separation from oil are mixed with fresh water, with demulsifiers, as well as with process water of oil treatment plants. It is this water, called waste water, that is pumped into the reservoir. A characteristic feature of waste water is the content of oil products (up to 100 g/l), hydrocarbon gases up to 110 l/m3, suspended particles up to 100 mg/l. Injection of such water into the formation cannot be carried out without purification to the required standards, which are established based on the results of pilot injection. Currently, in order to reduce the consumption of fresh water and utilize produced formation water, the use of wastewater for the purpose of RPM is widely used. Water must undergo preliminary purification from mechanical impurities (up to 3 mg/l) and oil products (up to 25 mg/l). The most widely used purification method is the gravitational separation of components in tanks. In this case, a closed circuit is used. Outflow water containing oil products up to 500 thousand mg/l and mechanical impurities up to 1000 mg/l enters the settling tanks from above. The layer of oil at the top serves as a kind of filter and improves the quality of water purification from oil. Mechanical impurities settle down and are removed from the tank as they accumulate. From the tank, water enters the pressure filter. Then a corrosion inhibitor is fed into the pipeline, and water is pumped out to the sewage pumping station by pumps. For the accumulation and sedimentation of water, vertical steel tanks are used. Anti-corrosion coatings are applied to the inner surface of the tanks in order to protect against the effects of formation waters. The choice of a technological scheme for wastewater treatment depends on many factors: the type of production, feedstock, quality requirements and volumes of treated wastewater. The choice of treatment facilities provides for a comprehensive assessment of production conditions: the availability of existing treatment equipment, the availability of production facilities for the modernization of existing equipment and the placement of new equipment, incoming and required output concentrations of pollutants, and much more. Installations for the preparation of wastewater for flooding oil reservoirs are divided into open and closed. Wastewater I in the open type wastewater treatment plant, coming from the oil treatment plant, is sent to sand trap 1 , where large mechanical impurities are deposited. From the sand trap, wastewater flows by gravity into the oil trap 3, which serves to separate the main mass of oil and mechanical impurities from water II. Its principle of operation is based on gravitational separation at a low speed of waste water (less than 0.03 m/s). At such a speed of movement of wastewater, oil droplets with a diameter of more than 0.5 mm have time to float to the surface. The accumulated oil III in the trap is removed through the oil gathering pipe and pump 2 is fed to the oil treatment plant for re-treatment. After the oil trap, wastewater for post-treatment from oil and mechanical impurities enters the settling ponds 4, where the duration of settling can be from several hours to two days. Sometimes, to speed up the process of settling suspended solids or to neutralize wastewater in front of the settling ponds, chemicals are added to the water: lime, aluminum sulfate, ammonia, etc. After the settling ponds, the oil content in the wastewater is 30-40 mg / l, and mechanical impurities - 20-30 mg / l. This depth of wastewater treatment IV usually sufficient to pump it into absorbing formations, and in this case, water through the chambers 5 And 6 arrives at the reception of pumps 7, which pump it into absorbing wells. Injection of water into injection wells requires its deeper purification. In this case, the waste water from the chamber 6 pump 8 is sent to alternately operating filters 9 And 10. Quartz sand (fraction 0.5-1.5 mm), anthracite chips, expanded clay sand, graphite, etc. are used as a filtering material. Waste water entering the filter should contain no more than 40 mg/l of oil and no more than mechanical impurities 50 mg/l. The residual content of oil and mechanical impurities after the filter is 2-10 mg/l. Purified water from the filter V enters the container 11, from where the high-pressure pump 14 injected into an injection well. After 12-16 hours of operation, the filter becomes dirty and the flow is switched to another filter, and the dirty filter is switched to washing. The filter is washed with purified water taken by the pump 13 from tank 11 and pumped through the filter in the opposite direction. The duration of washing is 15 - 18 minutes. Water with washed mud is discharged into the sludge tank 12. Plants for the treatment of wastewater of a closed type provide for the exclusion of contact of water with oxygen in the air to prevent oxidative reactions. According to the principle of operation, closed-type plants are divided into settling, filtration, flotation and electroflotation.
Water-oil emulsion I in a closed-type wastewater treatment plant, coming from the field, is mixed with hot formation water VII, which is discharged from the settling tanks or demulsifier heaters of the oil treatment plant and contains a demulsifying agent, passes a drop former 1 and enters the settling tank with liquid hydrophilic filter 2 , in which the water is preliminarily discharged. The settling tank with a liquid hydrophilic filter is made on the basis of a typical vertical tank and has a siphon device that maintains a given water layer under the oil layer. The water-oil emulsion, which has changed its type from reverse to direct as a result of mixing with hot water with a demulsifying agent and turbulent mixing in the droplet maker, enters the settling tank 2 under the water layer through the distributor. Rising through the liquid hydrophilic filter (water layer), the oil droplets are released from the emulsion water. Thus, the preliminary dehydration of the oil occurs and the pre-dehydrated oil II is discharged from the top of the settling tank 2. The wastewater III separated at this stage flows into a settling tank with a hydrophobic liquid filter 3. This settling tank is also made on the basis of a typical vertical tank and has a siphon device that maintains a given oil layer above the water layer. Waste water is introduced through a beam perforated distributor into the oil layer (liquid hydrophobic filter) and, going down, is freed from oil droplets. Captured oil V (trap oil) is collected in the chamber, discharged from the top of the settling tank and sent to the oil treatment plant. An indestructible emulsion layer may form at the oil-water interface IV , which is periodically withdrawn and also sent to the oil treatment unit. The water that has passed through the oil layer and freed from the main part of the drip oil is also subjected to sedimentation in the water layer. All these operations provide a sufficiently deep purification of formation water from dripping oil, and purified water VI, having passed tank 4 , pump 5 is pumped into absorption or injection wells. The main apparatus of closed-type wastewater treatment plants based on the principle of filtration is a coalescing filter-settler of the FZh-2973 type, developed by the BashNIPIneft Institute. Wastewater is first subjected to sludge in a horizontal sump, and then through the inlet pipe 6 enters the receiving area IN sediment filter located in the middle part of the body 3. Wastewater from the receiving compartment through perforated partitions 10 enters the filtration compartments B. Filtration compartments filled with coalescing filter 5, which is used as granular polyethylene with a granule size of 4-5 mm. Polyethylene has a hydrophobic property: oil wets it, but water does not. Therefore, oil drops, lingering on the surface of the granules, merge (coalesce) and leave the filtration compartments B into the sump A in an enlarged form. For this reason, in the settling compartments, a rapid separation of water and oil droplets occurs and oil is removed from above through the oil outlet pipes 1, and purified water through pipes 7. The mechanical impurities deposited in the settling compartments are removed through the pipes 8. Settling compartments are equipped with manholes 2. Loading and unloading of granular polyethylene into the filtration compartments is carried out through hatches 4 And 9. When granulated polyethylene is clogged, it is washed by feeding 10-15% of kerosene dispersion into purified water for 30 minutes.
Technological scheme of a plant for the treatment of wastewater of a closed type on the principle of sludge
Wastewater treatment based on the flotation principle is carried out in a flotation tank. Flotation is the process of extracting the smallest dispersed particles from a liquid using gas bubbles floating up in the liquid. In the flotation tank, gas bubbles form in the flotation zone 5 due to the release of dissolved gas from gas-saturated waste water as a result of pressure reduction when it enters this zone. Water saturation pressure with gas - 0.3-0.6 MPa; the amount of gas released from the water - 25 l/m 3 . Gas-saturated water is introduced through the inlet pipe 1 into the lower part of the flotation zone using a perforated distributor. Waste water rises in the flotation zone at a rate that ensures that the water stays in the flotation zone for about 20 minutes. The released gas bubbles, rising up the beast, meet on their way dispersed particles distributed in the water. Dispersed particles that are poorly wetted by water (oil droplets) are captured by bubbles and float on the surface, forming a foam layer there. Captured oil is collected in a trough 4 to collect oil and is discharged through a branch pipe 2. Water from the flotation zone 5 flows into the cesspool 6, located in the annular space between the housing 3 tank and flotation zone, where it slowly sinks down. Dispersed particles, which are well wetted by water, are not captured by gas bubbles in the flotation zone, but settle down under the action of gravity in the flotation and settling zones, from where the precipitate is discharged through the corresponding perforated pipes and nozzles 9 And 10. Purified water is discharged through an annular perforated collector and branch pipe 8. The flotation tank is sealed, so the gas released from the water is discharged from the top of the tank through pipe 7. The content of impurities (mg / l) in the waste water entering the flotation tank for treatment should be: oil - 300, mechanical impurities - up to 300. Residual the content in the purified water leaving the flotation tank is (mg/l): oil - 4-30, mechanical impurities - 10-30.
Electroflotation is the flotation with the gas produced by electrolysis. Electrolysis of water produces bubbles of oxygen and hydrogen. The advantage of electroflotation in comparison with gas flotation is the possibility of obtaining finely dispersed gas bubbles up to 16 * 10 7 pieces / (m 2 * min) during electrolysis, which leads to a rapid clarification of oily water. The essence of the electroflotation method of wastewater treatment is included in the following. Electrodes are installed in the technological vessel and a direct electric current is passed through. As a result of electrolysis, gas bubbles are released on the electrodes, which rise up, penetrating the layer of treated oily water. When moving in waste water, the bubbles collide with dispersed particles suspended in water, stick to them and float them. Thus, the dispersed particles are collected in the upper part of the vessel in the form of foam, which is removed using a scraper conveyor. Purified water is discharged through a branch pipe located at the bottom of the apparatus. The location of the electrodes has a significant effect on the process of wastewater treatment by electroflotation. It is recommended to place one electrode at the bottom of the apparatus so that it covers the entire bottom as far as possible. This is necessary so that the bubbles released during electrolysis on this electrode permeate the entire volume of treated water and ensure the flotation of dispersed particles. The second electrode is fixed in a vertical position so that it does not interfere with the flotation of dispersed particles. The electrodes are made in the form of plates, grids; movable electrodes can be used to control the distance. between them. To increase the efficiency of flotation and electroflotation processes, chemical reagents are introduced into the treated wastewater, which, according to the mechanism of action on dispersed particles, are divided into two groups: coagulants and flocculants. Coagulants are electrolytes, the addition of which to wastewater leads to the association of the smallest dispersed particles into sufficiently large compounds, followed by their precipitation. The mechanism of action of such a coagulant as aluminum sulfate is as follows. When aluminum sulfate is dissolved, its hydrolysis occurs:
Al 2 (SO 4) 3 "2AI 3+ + 3SO 4 2-,
Al 3+ + 3H 2 O "Al (OH) 3 + 3H+.
The resulting aluminum hydroxide is a flaky gelatinous precipitate, which, settling, entrains dispersed particles (oil and mechanical impurities). Since this process takes place actively in an alkaline environment, ammonia water or milk of lime (obtained by slaking lime) is added simultaneously with the coagulant. In addition to aluminum sulfate, coagulants are also ferric chloride, ferrous sulfate. Flocculants are high molecular weight water-soluble polyelectrolytes. The mechanism of their action is that long chains of polyelectrolyte molecules are adsorbed by their active centers (hydrophilic groups) on the surface of dispersed particles, which leads to flocculation (flocculation). In contrast to coagulation, during flocculation, dispersed particles do not contact each other, but are separated by a bridge from the molecular chain of the flocculant. As flocculant water soluble polymer is used polyacrylamide(PAA). The effectiveness of coagulants and flocculants increases significantly when they are used together in the wastewater treatment process. At the same time, the dosage of flocculants is tens or even hundreds of times less than that of coagulants.
3.2 Ways to improve the technology of water injection into the reservoir
At many multi-layer fields of the Arlansky UDNG, there are more than two already opened (perforated) production facilities per injection well. This was done to maintain reservoir pressure (volumes of water injection) while limiting capital investments for the construction of new injection wells. It is known that the joint injection of water into several reservoirs that are heterogeneous in permeability leads to rapid flooding of deposits, low coverage by their impact and the formation of water blockades of individual undeveloped zones. At the same time, the accelerated advancement of the front of oil displacement by water along highly permeable formations leads to water breakthroughs to the bottomholes of production wells and, as a result, the volume of produced water and the cost of its injection increase. This, at best, leads to an increase in the cost of oil production, and in the worst case, the decommissioning of a flooded well along with the loss of undeveloped oil reserves remaining in low-permeability formations. The practice of joint injection of water into several reservoirs also leads to the loss of information about the actual injection of water into each of the reservoirs. The contradiction between "economic considerations" and the protection of the subsoil when choosing production facilities can already be resolved if the technology is used simultaneously - separate injection of water into several production facilities through one well. This technology is part of the technology for the simultaneous separate development of several production facilities, proposed by the Research Institute "UralGeoTech" and the Research Institute "Bashneft". The main distinguishing feature of this technology is: sequential lowering of reservoir sections, checking the tightness of the packer (from below and from above) for each subsequent section, corresponding to the interval for which it is necessary and possible to create a differential repression. This will prevent cross-flows both between the selected intervals - reservoirs through the packer at the time of injection (with different overbalances for different intervals), and through the pipe string at the time of shutdown, despite a significant difference in reservoir pressures, and also guarantee reliable extraction of the multi-packer unit from wells for revision or repair. This technology allows you to study separately each of the selected intervals and set the optimal repression value for them, taking into account the existing restrictions. To implement the technology, a downhole installation is used, consisting of a pipe string with several packers, the number of which matches the number of sections, each section including at least one downhole chamber with a flow control valve. At the same time, one or several packers are equipped on top with a pipe string disconnector without or with a thermal compensator, or a separate telescopic connection for separate lowering and extraction of each section from the well, as well as relieving the stress of the pipe string. Figure 1 shows the layout for water injection in three production facilities (isolated reservoirs). In the rules for the development of oil and gas and oil fields, a production facility is understood as "a productive reservoir, part of a reservoir or a group of reservoirs allocated for development by an independent grid of wells" that does not exclude its combination with other objects, but has an individual impact system that provides differentiated control of filtration flows (the field of reservoir pressure)". If two heterogeneous and hydraulically isolated reservoirs are affected by two different overbalances through one injection well, and completely independent drawdown values are also created from the side of production wells, then these reservoirs should be considered as separate operational development objects.
Rice. 7 Scheme of the underground layout of the ORP injection well
And vice versa, if during the joint operation of several reservoirs, some of these reservoirs are not affected at all, for example, due to low permeability or due to the impossibility of creating an ultimate pressure gradient on them, then they can hardly be attributed to production objects, since in this case, they are no different from non-perforated layers. An independent grid of wells at the level of each object is needed solely to ensure the optimal reservoir pressure field adapted to the specific geological and technological conditions of the selected object. With the technology of simultaneous separate development of several objects, this can be ensured with the help of a grid of wells combined for them. Currently, work has been carried out for injection wells with four isolated reservoir intervals, but there is a fundamental and technical possibility to significantly increase the number of such intervals (objects). Successful implementation of this technology is possible in injection wells with an open hole to productive formations, which makes it possible to change the water injection regimes in each of the intervals (formation) by changing control valves or fittings using cable technology and special tools. When using this technology, it is possible to control the injection of water into each object and optimally regulate development processes - differentially affect individual layers due to operational (by changing the wellhead regulators or downhole regulators in the respective sections) changing the modes of each of the well formations in a wide range, which ultimately will increase the oil recovery factor. This technology allows optimizing repressions, changing filtration directions, and performing non-stationary flooding even in winter. Thus, in multi-layer fields, it is necessary to carry out a large-scale implementation of the ORRNE technology in order to ensure a differentiated impact on various production targets (intervals and/or reservoir sections). Currently, work has been carried out for injection wells with four isolated reservoir intervals, but there is a fundamental and technical possibility to significantly increase the number of such intervals (objects). The diameter of the pipe string and the standard dimensions of the control valve for each section are selected using the software package of the Ural branch of the Research Institute "Bashkirgaz" SANDOR, depending on the geological and field characteristics of the corresponding production facilities. Each subsequent section is lowered on a column of technological pipes, and the upper section is lowered on a column of stock pipes. Specialized equipment for the implementation of the ORRNEO technology is being developed by LLC NTP Neftegaztekhnika, Ufa. Let's take a closer look at individual developments. Column disconnector type RKG, RKM, RKSH. The string disconnector is designed to disconnect (by hydraulic action - RKG or mechanically RKM, RKSH) and subsequent connection (automatically - by hydraulic or mechanical action) of the tubing string with the packer installed in the well, as well as to compensate for changes in the length of the tubing string under thermobaric conditions (Fig. 8 ) Packer type SLH. The main advantage of this packer is an increase in its tightness, as well as the reliability of retrieval from the well. At the same time, the number of tripping operations and accidents during the operation of a multi-packer unit is reduced. The packer includes an anchor on top, triggered by both pipe and bottomhole pressure, which increases the reliability of the packer both during setting and during its operation. Also, the packer has a “cone - ram” anchoring device from below, which is released both from interference (8 - 12 tons) of the pipe string, and without interference, by moving (mechanically or hydraulically) the sliding sleeve in the wellbore, without shearing the shear screws of the ram holder .
Fig. 8 Disconnector of the RKSH column
Downhole regulator type 5 RD. This regulator allows, depending on the formation parameters, to maintain a given bottomhole pressure or a given water flow rate during injection, even when the formation pressure and injectivity change. Wellhead regulator type 5 PP. This regulator, in contrast to the traditionally used wellhead fittings, allows you to quickly change and maintain the set values of wellhead pressure, in particular, in the study of reservoirs. The efficiency of the technology of simultaneous separate injection of water into several reservoirs at injection wells was tested at the following multi-layer fields: Vanyeganskoye, Ai-Eganskoye, Priobskoye, Tarasovskoye, Barsukovsky, Yuzhno-Tarasovsky, Festivalnoye, Vostochno-Yagtinskoye, Yuzhno-Kharampurskoye and others. The economic effect of this technology is mainly expressed in additional oil production or a reduction in capital investments for drilling additional wells. The technology allows compared to the separate operation of several layers:
Reduce capital investments for drilling wells (by 2-3 times);
Reduce operating costs (variable costs) (by 20-40%);
Reduce the development period of a multilayer field (by 30%);
To increase the cost-effective development period of flooded and gassed reservoirs by extending their operation with the connection of additional facilities;
Increase the oil recovery factor of reservoirs by increasing the period of their cost-effective development;
Reduce the likelihood of freezing of X-mas trees and flow headers of injection wells due to low reservoir permeability;
Increase the efficiency of using wells and downhole equipment;
Reduce the likelihood of leaks in the production string.
Compared to the joint operation of several reservoirs, the technology allows:
To increase the oil recovery factor of the reservoirs by subdividing objects of different permeability and saturation and increasing the degree of their coverage by waterflooding;
Increase oil production by 30-40% due to differentiated and controlled impact on each of the reservoirs;
Ensure accounting of injected water (agent) into each of the reservoirs;
Prevent interlayer cross-flows along the wellbore at the time of its shutdown and with small repressions;
To increase the efficiency of enhanced oil recovery methods by using one well simultaneously for reservoir pressure maintenance and selective injection of an agent to equalize the injectivity profile;
Non-stationary impact on the layers, changing their regimes;
Provide increased repression on low-permeability oil-saturated reservoirs with simultaneous limitation of water injection into high-permeability reservoirs;
Regulate the directions and velocities of reservoir fluid filtration by quickly controlling the reservoir pressure field;
Reduce the likelihood of leaks in the production casing;
Explore and control the development of individual reservoirs. At present, the technology has been successfully implemented in 37 injection wells, including 12 with 3 layers and 25 with 2 layers. The technology is most effectively implemented in gas-lift and injection wells.
4. Estimated part
4.1 Calculation of the development time of an oil deposit
In this regard, one of the tasks of the development analysis is to confirm the field operation mode specified by the design document, for which the dynamics of the average reservoir pressure in the extraction zone and the state of the current reservoir and bottomhole pressures and gas factor over the reservoir area as of the analysis date are considered. If it is found that the value of the average reservoir pressure in the extraction zone is below the saturation pressure, and the bottom hole pressure in the production wells has decreased in relation to the saturation pressure by more than 25% with a significant increase in the gas factor, then there is no water drive mode in the field and its development is carried out in the mode dissolved gas. It should be noted that at the current level of development of the oil industry, such a situation is extremely rare. With a delay in the implementation of the pressure maintenance method, as well as to confirm the existence of an elastic water-pressure regime, the elastic energy reserve or the volume of oil produced from the reservoir due to the elastic energy of the fluid and reservoir is determined
· - reserve of elastic energy of the deposit;
· - reservoir elasticity coefficient;
- reservoir volume;
- pressure reduction,
- porosity;
· - coefficient of compressibility of liquid (oil);
· - coefficient of compressibility of the medium (rock);
· - initial average reservoir pressure;
· - current average reservoir pressure.
Comparing the current cumulative oil and water production with , one can be convinced of the presence of elastic energy in the reservoir or the need to introduce pressure maintenance methods. In order to identify the modes of an oil deposit, in addition to data on reservoir parameters, the ratio of saturation pressure and reservoir pressure, it is necessary to establish a hydrodynamic connection of this deposit with the aquifer area. This connection can manifest itself in various ways. In the practice of developing oil fields, there may be cases of interaction between neighboring fields that are part of a single water-pressure system. The influence of neighboring fields must be taken into account in the analysis of reservoir pressures and in hydrodynamic calculations during the design, provided that these fields are large in terms of production and injection, if they are operated for a long time and if water injection on them started lagging behind the withdrawal or is systematically carried out in smaller volumes than fluid withdrawal. If necessary, this type of study is best done when drafting the project document. If this is not done, then an assessment of the impact of the work of neighboring fields on the ones under consideration should be done during the development analysis. The influence of the development of neighboring fields is established by the change in reservoir pressure and the displacement of the water-oil contact, and sometimes the displacement of the oil deposit is also noted. It is easier to establish this before the start of development of the field under consideration due to the anomalously low initial reservoir pressure compared to neighboring deposits. In the course of work, the influence of neighboring deposits is established by calculation by the method of computer simulation. The hydrodynamic connection of this deposit with the edge area is also manifested during the operation of edge and edge injection wells in the form of leaks of injected water into the edge area. If during in-loop flooding all the injected water goes into the deposit, then in aquifer wells, part of the injection goes beyond the oil-bearing contour, especially in the first years of field development. It is also necessary to estimate the volume of leaks beyond the oil-bearing contour when the pressure on the injection line is set above the initial reservoir pressure and the accumulated injection significantly exceeds the fluid withdrawal accumulated since the beginning of development. Leakage volumes are determined by computer simulation or by the elastic regime formulas (sequential change of stationary states method) provided that the reservoir is represented as an enlarged well:
· - leakage of injected water into the contour area;
· - average reservoir permeability;
- layer thickness;
- viscosity of water;
· - correction factor, determined during the period of trial operation;
- pressure on the discharge line;
· - initial reservoir pressure;
· - dimensionless injection at time t, determined according to Table 1.
· - dimensionless time, ;
- radius of the enlarged well;
· - coefficient of piezoconductivity.
4.2 Calculation of the injection process of those. liquids into wells
The total injection for the rows of injection wells, for the field and its facilities is determined as the sum of the amounts of injected water for individual wells. Distribution of injection during intraloop flooding between adjacent areas or development blocks is made in accordance with the rate of fluid withdrawal or in accordance with the average hydraulic conductivity of adjacent areas or development blocks. The distribution of the volumes of injected water in the wells of the cutting rows between adjacent areas is recommended to be carried out taking into account fluid withdrawals and changes in reservoir pressure over the analyzed period in these areas according to the formula:
· - injection volume for the analyzed period (possible by years or even more fractional);
· - fluid withdrawal for the analyzed period from half of the area adjacent to a number of injection wells;
· - coefficient of reservoir elasticity in the adjacent area;
· - change in reservoir pressure in the adjacent area for the analyzed period;
· - reservoir volume within the adjacent area;
· - injection losses (leaks to other reservoirs due to leakage of the string, losses on the surface, etc.).
As with the distribution of oil and liquid production, the greatest complexity and conditionality is the distribution of injection between the layers of a multi-layer field using flow meter data. A simpler way is to distribute the injection in proportion to the cumulative fluid production of the reservoirs. Quantitative determination of the efficiency of HMF formations, i.e. oil production through the use of hydrodynamic impact is carried out by comparison with the indicators of the base case. The base case is a development option that would have been implemented at a given hydrodynamic impact facility if the formation HMF under consideration had not been used on it. The effect of hydrodynamic impact over a given time interval is defined as the difference between the actual oil production and the oil production under the base case. The forecast of indicators for the development of the base case (oil production, liquid production, water cut, number of wells, pressure drops, etc.) should be made for a period of one to six years, depending on the treatment technology used. It is desirable to determine the oil production (technological efficiency) due to the HMF formations on a quarterly basis. In cases where the increase in oil production for the quarter is insignificant compared to the total oil production from the target, the quarterly efficiency is estimated as a quarter of the annual effect. The efficiency of HMF formations should be determined as a whole by the object of influence. In cases where the effect is determined by individual wells (“well” characteristics), the effect of well mutual influence should be taken into account. The allocation of calculated objects of hydrodynamic impact to determine the effectiveness of the HMFN should be based on the results of a detailed geological and field analysis of the development of productive formations. If such areas have not been previously identified, their boundaries are established on the basis of geological field materials, the balance reserves in these areas are calculated, the degree and nature of the development of oil reserves from them is determined. At the objects of hydrodynamic impact, several HMFNs are usually used simultaneously or with a shift in time. In these cases, the overall technological efficiency of all methods of influence is determined. The allocation of the effect from each type of hydrodynamic impact can be carried out conditionally, taking into account the degree of impact and implementation. The value of the increase in the final oil recovery due to the methods of hydrodynamic impact is determined by the volume of additionally involved in the development of balance oil reserves. The use of hydrodynamic stimulation methods belonging to the first group mainly leads to an increase in the current oil recovery of the reservoirs, but in some cases it can also increase the final oil recovery factor (if these methods make it possible to involve poorly drained oil reserves in active development). In particular, the forced withdrawal of liquid leads to an increase in the final oil recovery due to an increase in the margin of profitability of well operation in terms of water cut. The methods of the second group are mainly aimed at involving in the active development of non-drained or poorly drained balance oil reserves and lead to an increase in the degree of oil recovery from the subsoil. When choosing and justifying hydrodynamic methods for enhanced oil recovery, the technical capabilities of surface and underground equipment (well design, wellhead equipment, surface facilities, well operation methods, pumping unit performance, etc.) should be taken into account. Types, volumes of implementation and expected efficiency are substantiated in technological schemes, projects for the development and additional development of oil fields, as well as in the work on the current geological and field analysis and on the cut. , possibly, subgas zones of gas and oil development facilities. It should be borne in mind that a change in the shape of the displacement characteristic can be associated both with the involvement in the active development of non-drained or poorly drained oil reserves (in dead-end zones, individual interlayers, lenses, etc.), and with the redistribution of fluid withdrawals and water injection along wells, i.e. hydrodynamic impact can affect both final and current oil recovery. Therefore, when assessing the technological effectiveness of measures, the results of the current geological and field analysis should be used in order to determine additional oil reserves introduced into development as a result of changing stimulation systems, drilling independent wells into separate interlayers, lenses, dead-end and poorly drained zones. Since the values of oil reserves in these zones are usually small compared to the total oil reserves of the development object, the impact of putting them into active development may be hardly noticeable on the shape of the displacement characteristic. In these cases, the volumes of oil production obtained from the additional balance oil reserves introduced into development should be determined separately and be fully related to the hydrodynamic impact method. The use of displacement characteristics for individual wells to assess the effectiveness of hydrodynamic methods of enhanced oil recovery is very conditional due to significant changes in the operating mode of each of them during the operation period and the mutual influence of the operation of surrounding wells. In this regard, the use of well displacement characteristics to assess the technological efficiency of hydrodynamic impact is not recommended. For methods of hydrodynamic stimulation, involving the active development of non-drained oil reserves, it is recommended to use differential displacement characteristics in the initial period of the development of the object due to the low water cut of the product. To determine the quantitative efficiency of hydrodynamic methods for increasing the current and final oil recovery, various types of displacement characteristics can be used, the main of which are the following:
1. (proposed by Nazarov S.N. and Sipachev N.V.)
2. (proposed by Kambarov G.S. et al.)
3. (proposed by Pirverdyan A.M. et al.)
4. 
(proposed by Kazakov A.A.)
5. (proposed by Cherepakhin N.A. and Movmyga G.T.)
6. 
(proposed by Sazonov B.F.)
7. 
(proposed by Maksimov M.I.)
8. 
(proposed by Garb F.A. and Zimmerman E.H.)
9. 
(proposed by the French Institute)
10. 
13. 
14. 
,
· - accumulated since the beginning of the development of oil, water, liquid, respectively;
· - oil, water, liquid production by years of development, respectively;
· - coefficients determined by statistical processing of actual data;
· - the average annual share of oil in the produced fluid;
· - annual oil production for the first year of the period under review;
- time, years;
· - balance reserves of oil in reservoir conditions;
· - oil recovery factor.
The integral displacement characteristics of the types (2), (3), (6), (13) and the differential displacement characteristics of the types (10), (11), (12) and (14) are the simplest and most convenient for “manual” data processing to determine the effectiveness of hydrodynamic action. Other types of displacement characteristics in the case of "manual" processing of actual data for a quantitative assessment of the effect of HMFN require much larger amounts of calculations or the use of methods for selecting various values and coefficients.
In these cases, "machine" processing of the initial data using a computer is recommended, for which it is necessary to create a program for the computer to select the best type of displacement characteristic. It is recommended to use differential displacement characteristics of the form (11) and (12) for constructing the base case and determining the effectiveness of hydrodynamic impact during dry oil production. It is advisable to determine the coefficients for these displacement characteristics, taking into account the existing coefficient of oil production decline in the object under consideration before the start of hydrodynamic impact. In some cases, the coefficient for the displacement characteristic of the form (11) is defined as the ratio of the average initial annual oil production of one well to the recoverable oil reserves per well. A physically meaningful mathematical model (geological and technological model) of the reservoir development process is a system of differential equations that reflect the fundamental laws of conservation of mass, momentum, energy, which describe the process under study with the greatest completeness today. The system of equations is supplemented with initial and boundary conditions, including control actions on the wells. It should be especially noted that the system of equations with additional conditions describes the filtration process in the area, which, in turn, is a model of a real geological object, which, as a rule, has a complex structure. This model is called the geological and mathematical model of the development object.
5. Safety and environmental friendliness of the project
5.1 Occupational health, safety and fire prevention
Oil product supply enterprises carry out operations for the storage, release and reception of petroleum products, many of which are toxic, evaporate well, are capable of electrification, fire and explosion hazard. When working at enterprises in the industry, the following main hazards are possible: fire and explosion in case of depressurization of process equipment or pipelines, as well as in case of violation of the rules for their safe operation and repair; poisoning of workers due to the toxicity of many petroleum products and their vapors, especially leaded gasolines; injury to workers by rotating and moving parts of pumps, compressors and other mechanisms in the absence or malfunction of the fence; electric shock in case of violation of the insulation of live parts of electrical equipment, grounding failure, non-use of personal protective equipment; increased or decreased surface temperature of equipment or air in the working area; increased level of vibration; insufficient illumination of the working area; the possibility of falling when servicing equipment located at a height. When servicing equipment and carrying out its repair, it is prohibited: the use of open fire for heating oil products, heating fittings, etc.; operation of faulty equipment; operation and repair of equipment, pipelines and fittings in violation of safety regulations, in the presence of oil product leaks through leaks in joints and seals or as a result of metal wear; the use of any levers (crowbars, pipes, etc.) to open and close shutoff valves; repair of electrical equipment not disconnected from the mains; cleaning of equipment and machine parts with combustible flammable liquids; work without appropriate personal protective equipment and overalls. In the event of an oil spill, the spill site should be covered with sand and then removed to a safe place. If necessary, remove oil-contaminated soil. In the premises where the spill occurred, degassing is carried out with dichloramine (3% solution in water) or bleach in the form of gruel (one part of dry bleach to two to five parts of water). To avoid ignition, degassing with dry bleach is prohibited. Smoking on the territory and in the production premises of the enterprise is prohibited, except for specially designated places for this (in agreement with the fire department), where the inscriptions "Smoking area" are posted. Entrances to fire hydrants and other sources of water supply must always be free for the unhindered passage of fire trucks. In winter, it is necessary to: remove snow and ice, sprinkle with sand to prevent slipping: decks, stairs, crossings, sidewalks, footpaths and roads; promptly remove icicles and ice crusts formed on equipment, roofs of buildings, metal structures.
5.2 Subsoil and environmental protection
At first, people did not think about what intensive oil and gas production was fraught with. The main thing was to pump them out as much as possible. And so they did. More recently, the echoes of intensive oil development occurred in Tataria, where in April 1989 an earthquake of up to 6 points was registered (Mendeleevsk). According to local experts, there is a direct relationship between increased pumping of oil from the bowels and the activation of small earthquakes. Cases of breakage of wellbores, collapse of columns have been recorded. Tremors in this area are especially alarming, because the Tatar nuclear power plant is being built here. In all these cases, one of the effective measures is also the injection of water into the productive formation, which compensates for the extraction of oil. Having started the exploitation of oil and gas fields, a man, without knowing it, let the genie out of the bottle. At first it seemed that oil only brings benefits to people, but it gradually became clear that its use also has a downside. Oil pollution creates a new ecological environment, which leads to a profound change in all parts of natural biocenoses or their complete transformation. A common feature of all oil-contaminated soils is a change in the abundance and limitation of the species diversity of pedobionts (soil meso- and microfauna and microflora). There is a massive death of soil mesofauna: three days after the accident, most species of soil animals completely disappear or make up no more than 1% of the control. The most toxic for them are light fractions of oil. The complex of soil microorganisms, after short-term inhibition, responds to oil pollution by increasing the gross population and increasing activity. First of all, this applies to hydrocarbon-oxidizing bacteria, the number of which sharply increases relative to uncontaminated soils. “Specialized” groups are developing, participating at different stages in the utilization of hydrocarbons. The maximum number of microorganisms corresponds to the horizons of fermentation and decreases in them along the soil profile as HC concentrations decrease. The main "explosion" of microbiological activity falls on the second stage of the natural degradation of oil. In the process of oil decomposition in soils, the total number of microorganisms approaches the background values, but the number of oil-oxidizing bacteria for a long time exceeds the same groups in unpolluted soils (southern taiga 10-20 years). Changes in the ecological situation lead to the suppression of the photosynthetic activity of plant organisms. First of all, this affects the development of soil algae: from their partial suppression and replacement of some groups by others to the loss of individual groups or the complete death of the entire algal flora. The development of algae is especially significantly inhibited by crude oil and mineral waters. The photosynthetic functions of higher plants, in particular cereals, change. Experiments have shown that under the conditions of the southern taiga at high doses of pollution - more than 20 l/m 2 plants cannot develop normally on polluted soils even after a year. Studies have shown that the activity of most soil enzymes decreases in polluted soils (N. M. Ismailov, Yu. I. Pikovsky, 2008). At any level of pollution, hydrolases, proteases, nitrate reductases, and soil dehydrogenases are inhibited, and the urease and catalase activities of soils slightly increase. Soil respiration is also sensitive to oil pollution. One of the most promising ways to protect the environment from pollution is the creation of a comprehensive automation of the processes of production, transportation and storage of oil. In our country, such a system was first created in the 70s. and applied in areas of Western Siberia. It was necessary to create a new unified oil production technology. Previously, for example, the fields did not know how to transport oil and associated gas together through one pipeline system. For this purpose, special oil and gas communications were built with a large number of facilities dispersed over vast territories. The fields consisted of hundreds of objects, and in each oil region they were built in their own way, this did not allow them to be connected by a single telecontrol system. Naturally, with such a technology of extraction and transport, a lot of product was lost due to evaporation and leakage. Using the energy of the subsoil and deep-well pumps, specialists managed to ensure the supply of oil from the well to the central oil gathering points without intermediate technological operations. The number of commercial objects decreased by 12-15 times. Other large oil-producing countries of the world are also following the path of sealing the systems of collection, transportation and preparation of oil.
Conclusion
The course project deals with the actual problems of developing oil fields using aquifer and in-loop flooding. Water injected into the reservoir cannot be considered as a virtual liquid that is unable to significantly change, for example, the permeability of the reservoir and is used only as a means of maintaining reservoir pressure (RPM). Water is the most important oil-replacing agent. In this regard, the issues of the quality of the injected water and its compliance with the reservoir properties of the reservoir are considered from a new perspective. The latter is especially important in the development of fields and reservoirs with degraded reservoir parameters, which contain significant oil reserves that cannot yet be displaced by commonly used water. The causes of self-colmation of a porous medium, modern requirements for the reservoir pressure maintenance system, methods and new technologies for the treatment of injected water are considered. The expediency of water purification using cascade technology, which provides maximum effect at minimum cost, is shown.
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The method of traditional (conventional) waterflooding is quite effective and is usually used to develop deposits with a relative viscosity of reservoir oil less than 30 - 40, with reservoir permeability more than 
. In recent years, in connection with the commissioning of many less productive reservoirs, waterflooding is designed for reservoirs with permeability 
and for deposits with relative oil viscosity up to 50 - 60 . at the same time, additional technological measures are envisaged.
The development of oil fields is understood as the control of the movement of oil in deposits to oil-producing wells by proper placement and sequential input of the entire set of oil-producing and water-gas injection wells in order to maintain the intended modes of their operation with uniform and economical consumption of reservoir energy.
Of all the possible development systems, it is necessary to choose the most rational one, in which the field is drilled with a minimum number of wells, providing the planned oil recovery rates and high final oil recovery with the minimum possible capital investments and operating costs.
The regulation of the balance of reservoir energy in oil deposits is carried out by acting on the reservoir as a whole. At present, the main method of intensifying oil production is maintaining reservoir pressure by artificial waterflooding. In some fields, gas is also injected into the gas cap.
The choice of waterflooding system is based on petrophysical analysis of reservoir rocks, determination of filtration parameters of the core, special experimental and theoretical studies, the feasibility of influencing the reservoir and the method of influencing the reservoir, and the density of the well pattern. There are several types of flooding systems.
End flooding. In this case, the reservoir is stimulated through a system of injection wells located behind the outer oil-bearing contour, along the entire perimeter of the deposit, as close as possible to the outer oil-bearing contour. The mechanism of displacement of oil from the formation by water is approximately the same as in the natural water drive regime. The method is applicable for the development of oil and gas and oil facilities. It is highly effective with a small width of the deposit (up to 4-5 km), mainly with a low relative viscosity of reservoir oil (up to 5), high reservoir permeability (0.4-0.5 or more), relatively homogeneous structure of the reservoir, good connectivity deposits with aquifer. The use of the considered type of waterflooding in the mentioned very favorable geological conditions makes it possible to achieve high oil recovery (up to 60-65%). Production wells can be located mainly within the inner contour of the oil. In this case, oil from the oil-water zone can be displaced to the bottomholes of producing wells by injected water. In this way, without a significant increase in oil losses in the reservoir, it is possible to reduce the number of wells for the development of the facility and the volume of produced water. To develop the oil part of an oil and gas deposit, it is more expedient to apply edge flooding while ensuring the immobility of the GOC by controlled gas extraction from the gas cap. In edge flooding, there are usually four to five production wells per injection well. (according to Kudinov - The distance between the injection wells is determined in the technological scheme for the development of this field. The line of injection wells is located approximately 400 - 800 m from the outer contour of the oil-bearing capacity in order to create a uniform impact on the deposit, prevent the formation of premature watering tongues and water breakthroughs to production wells. )
Edge flooding. With this type of flooding, injection wells are located near the outer contour of oil-bearing capacity within the water-oil zone of the deposit. It is used mainly for the same characteristics of deposits as edge flooding, but with poor hydrodynamic connection of the deposit with the edge zone. Poor connection of the deposit with the water-bearing part of the formation is due to the deterioration of the permeability of the formation near the OWC or the presence of a waterproof screen under it or at its level. The presence of such a screen is especially typical for deposits of carbonate reservoirs, where secondary geochemical processes can lead to blockage of voids with mineral salts, solid bitumen, etc.
According to the principles of well location, the ratio of the number of production and injection wells, the approach to the development of gas and oil deposits, the values of the achieved oil recovery, near-edge flooding is approaching edge flooding. (Additions from the Kudinov settlement - Edge flooding is used: - in small deposits; with insufficient hydrodynamic connection of the productive formation with the external area; in order to intensify the oil production process, since filtration resistances between injection and production wells are reduced due to their At the same time, the likelihood of flood tongues and uncontrolled water breakthroughs to individual oil wells increases.)
In-loop flooding. The impact on the formation in this case is carried out through a system of injection wells located according to one or another scheme inside the oil-bearing contour. This is a more intensive system for influencing an oil deposit, which makes it possible to reduce the time for developing reserves and quickly increase oil production. In-loop waterflooding makes it possible to increase the rate of oil recovery and reduce the development time of large oil fields. In some cases, to intensify the development of an oil field, a combined effect is used, i.e. contour (contour) flooding with intra-contour central flooding. For example, in a central flood, a battery or ring of injection wells is drilled in the center of an oil reservoir. In cases where the permeability of rocks in the peripheral areas of the oil reservoir is significantly reduced, then it is possible to apply axial flooding, when injection wells are drilled along the axis of the fold.
Currently, several in-loop waterflooding systems are used, which differ from each other in the location of injection wells, the sequence of putting them into operation, the rate of water injection into the reservoir, as well as oil withdrawals from oil producing wells.
In case of intraloop waterflooding, spot waterflooding is also used. Local flooding is used in cases where there is no influence from flooding in certain areas of the deposit, as a result of which reservoir pressure drops in this area and, accordingly, oil flow rates in production wells fall. In case of spot flooding, an oil producing well is selected in the center of the site, transferred to an injection well, and water injection is started, as a result of which the effect of the injected water on the surrounding oil producing wells is ensured.
A selective system of in-loop waterflooding is also used. The most intense reservoir stimulation system is considered to be areal flooding. Production and injection wells in this system are placed in regular geometric blocks in the form of five-, seven- or nine-point grids, in which injection and production wells alternate.
With a five-spot scheme, there is one production well per injection well, with a seven-spot scheme, two production wells, and with a nine-spot scheme, three production wells. Since injection wells do not produce production, the nine-spot scheme seems to be the most economical, but the intensity of impact on the deposit is much less and the probability of the appearance of oil pillars during water breakthrough into production wells is much greater. In order to intensify oil production and increase the final oil recovery, gas or air is injected into the productive formation, and water and gas are alternately injected into the formation.
(this was according to Kudinov).
The choice of the layout of injection wells is determined by specific geological conditions, economically viable terms for the development of reserves and the amount of necessary capital investments. Typically, injector lines are located in reservoir zones with improved reservoir properties and perpendicular to the dominant strike of lenses and permeable sandstones, which eliminates or reduces injection water blockage and increases reservoir coverage.
Edge flooding in the presence of in-loop flooding should prevent oil from being displaced into the outer - edge area, as well as intensify the process. From an energy point of view, the use of in-loop waterflooding is more efficient than in-loop and near-loop flooding, since almost all of the injected water is used in this case to displace oil on both sides of the cutting row. In case of in-loop waterflooding, the wells of the cutting rows are operated on oil "through one" to form a displacement front, i.e., a strip of the water-saturated part of the formation.
The above waterflooding systems are usually used in large delineated fields with established boundaries and fairly reliable data on reservoir characteristics.
Block waterflooding is expedient in large non-contoured fields, when, according to the data of exploration wells, commercial oil-bearing capacity is obvious in the area of their location. In this case, before the final exploration of the field and determination of the oil-bearing contours, it is possible to accelerate the commissioning of the object by cutting the field injection wells in rows into separate blocks with independent grids of production wells. Then, within each block, producing wells are drilled in the form of rows, the number and density of which on the area of the block are determined by hydrodynamic and feasibility calculations. During the final exploration and delineation of the field, the blocks put into operation earlier technologically fit into the overall development scheme and form an organic whole with it.
Spot flooding is used in conjunction with any other flooding system to improve sweep sweep, as well as to recover reserves from individual lenses or sections of the formation (stagnant zones) that are not affected by injection from nearby injection rows. As a rule, in case of spot flooding, one of the production wells is used for injection, located rationally in relation to the surrounding production wells and in the formation zone with increased permeability. However, for patch flooding, it is possible to drill a special well or even a group of wells to increase the impact coverage of a larger volume of the oil-saturated part of the reservoir or its low-permeability zones.
With a sufficiently detailed geological study of the development object, focal flooding can be used as an independent one at all stages of development and additional development of the field and, in a certain sense, is a means of controlling the displacement process.
The selective flooding system is used, as well as the focal one, in the development of oil reserves from highly heterogeneous discontinuous reservoirs both along strike and thickness. With this system, the drilling points of injection wells are determined taking into account a detailed study of the geological conditions, the distribution of the reservoir, its connections with the bottoms of the nearest production wells and in such a way as to ensure the maximum possible intensity of oil displacement by water and minimize the effect of heterogeneity and lenticular formation on the completeness of production and final oil recovery factor. As a result, the injection wells are randomly located on the area, reflecting the natural heterogeneity of the reservoir. This complicates the water supply system of injection wells. At the first stages of development, when geological information is limited or simply insufficient, this system cannot be applied. It is effective only at subsequent stages, when the details of the reservoir structure and the results of the influence on the wells of the injection of the main waterflooding system are revealed.
Area flooding is the most intensive reservoir stimulation system, providing the highest rates of field development. Production and injection wells with this system are located in regular geometric blocks in the form of five-, seven- or nine-point grids, also linear (Fig.). The ratio of injection and production wells is 1:1. An element of this system can be a rectangle with sides 2L and 2s n = 2s d = 2s. If 2L = 2s, then the linear system becomes a five-spot system with the same ratio of wells (1:1). The five-point system is symmetrical and the reverse placement of wells with an injection well in the center can also be chosen as an element (inverted five-point system). In a nine-point system, there are three injection wells per production well (the ratio of wells is 3: 1), since out of eight injection wells, four wells fall on two and four neighboring elements, respectively. In a reversed nine-spot system (with an injection well in the center of the square), the ratio of injection wells to production wells is 1:3. With a triangular well placement grid, we have a four-spot (inverted seven-spot) and a seven-spot (or inverted four-spot) system with a ratio of injection and production wells, respectively, 1:2 and 2:1. There is one production well per injection well, with a seven-spot scheme there are two production wells, and with a nine-spot scheme there are three production wells. Considering that injection wells do not give production, it becomes obvious that the nine-spot scheme is more economically profitable, however, the intensity of the impact on the deposit
 |
less and the probability of the existence of oil pillars during water breakthrough into production wells is greater.
Areal four-(a), five-(b), seven-(C), nine-point (d) and linear (e, f) flooding systems (with selected elements)
Historically, area flooding has been used in the later stages of development as a secondary oil recovery method. However, the area flooding system is of independent importance, it can be effectively used in the early stages of development if the reservoir is well known.
It should be noted that the above well placement schemes can be used not only for water injection, but also for gas injection or for pushing various solvents in the form of rims with gas or water. However, the scale of application of other stimulation methods, in comparison with water injection, is so small that one has to talk mainly about the placement of wells during waterflooding.
Control and regulation of deposit exploitation are reduced to a uniform contraction of water-oil and gas-oil contacts and to the rational use of reservoir energy. At the same time, it is very important that a high oil recovery factor is ensured in the zone of oil replacement by water or gas. Uniform contraction of oil-bearing contours is primarily achieved by proper placement of oil producing and injection wells along the deposit in accordance with the permeability of various sections of productive formations and by regulating the operating modes of each well separately.
In the process of developing deposits, they constantly monitor the flow rate of oil wells for oil, the percentage of water cut in oil, the gas factor, sand production, changes in bottomhole and reservoir pressure. The injectivity of water injection wells, the discharge pressure of pumps at cluster pumping stations are monitored daily and the amount of mechanical impurities in the water is systematically determined. Hydrothermodynamic studies of wells are systematically carried out.
Based on the results of all studies, maps of well water cut, isobars, permeability, specific productivity, etc. are built.
In case of premature water breakthrough into oil wells, either the extraction from this well is limited, or the injection of water into injection wells is limited. In the event of an increase in gas breakthrough into oil wells in the gas-pressure regime, it is recommended to close them. An increase in the GOR in oil wells in the water-driven mode indicates a drop in reservoir pressure in the zone of these wells. Therefore, it is necessary either to reduce oil production from these wells, or to increase the injection of water into the reservoir in this area.
According to the determination of the reduced reservoir pressure for wells, maps of isobars of a map of equal reservoir pressures are built quarterly. Comparison of water cut maps and isobar maps makes it possible to judge the progress of oil-bearing contours.
To determine the completeness of the development of productive strata between the oil and injection rows of wells, appraisal wells are drilled with continuous core sampling from the productive stratum, according to which, under laboratory conditions, the washing of rocks with water, i.e., residual oil content, is determined. Then these wells are used as control wells, equipped with special devices called piezographs, or bottomhole pressures in them are periodically measured.
To identify zones of weak or improved permeability of individual sections of the reservoirs, hydrodynamic studies of wells for interaction are carried out. In case of poor permeability, new oil or injection wells are drilled in these areas, which ensures greater completeness of oil recovery.
The rate of advancement of the oil-bearing contours can be monitored by the change in the light absorption coefficients of oil ksp and by the curves of bottomhole pressure recovery. The light absorption coefficient of such a substance is taken as unit ksp, when light penetrates through 1 cm of the layer of which the intensity of the light flux decreases by e (2.718) times. It has been established that ksp is sensitive to changes in the concentration of colored substances, such as resins and asphaltenes, in oil. Since the content of resins and asphaltenes in oil is higher in the zones located closer to the oil-bearing contour, it is possible to determine the speed of oil movement in each section of the reservoir by increasing in time ksp of oils extracted from intra-loop wells.
Based on the results of all the above studies, actual graphs of the main reservoir development indicators are built, which allow you to monitor the extraction of oil and water from the reservoir, the injection of water or gas into the reservoir, changes in reservoir pressure and gas factor. When the actual indicators lag behind the design ones, certain activities are carried out in order to regulate the development and achievement of design indicators.
The injectivity of a water injection well (in) is measured by a diaphragm type meter or flow meter installed at a cluster pumping station. Since one distributing conduit often provides water to two or three wells, the well injectivity should be measured when other wells fed from the same conduit are stopped. When using individual pumps for injection wells, their injectivity is determined individually.
The choice of an oil recovery system and the development of oil fields depends on dozens of factors: on the depth and quality of productive formations: the amount of recoverable reserves, their structure according to the degree of exploration (): reservoir characteristics; 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; positions of water-oil contact.
In addition to the listed main development indicators, natural and climatic characteristics, engineering and geological conditions are taken into account during the development of the field.
One of the main requirements for development is rationalization: ensuring the specified production rates with minimal capital investments and minimal impact on the environment. The most important component of field development design is the allocation of production facilities. The part of the oil deposit allocated for operation by an independent network of production and injection wells is called a production facility.
Explored deposits are considered prepared for industrial development subject to the following conditions:
Master plan requirements
The scheme of the general plan of the field provides for the placement of the mouths of oil, gas, injection single wells and clusters, GZU, BPS. installations for preliminary formation water discharge (UPS), cluster pumping stations (CPS), compressor stations, engineering communications (roads, oil and gas pipelines, water conduits, power lines, communication lines, cathodic protection, etc.), providing processes for collecting and transporting well products, as well as the supply of electricity, heat, water and air.
The placement of industrial and auxiliary buildings and structures must be carried out according to their functional and technological purpose, taking into account explosive and fire hazards. When placing oil production facilities in the coastal areas of reservoirs, the planning marks of the sites are taken 0.5 m above the highest water horizon with a probability of exceeding it once every 25 years (wellheads, gas logging) and once every 50 years (CS, CPS, BPS, UPS ).
Environmental measures and elements of EIA are included in the regulatory documents for the development of deposits. However, with the established practice of interaction between participants in the development of deposits, typical environmental problems are not solved in a preventive manner, but as they arise. There is a pattern - the more remote the deposit is located, the less severe environmental restrictions are imposed on it and the greater 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 already during the design of field development. The operation of oil fields harms the environment, regardless of the design features of structures and volumes of hydrocarbons produced. Carrying out costly environmental measures should be carried out in a timely manner (liquidation of wells, storage pits, land reclamation), and not be postponed for an indefinite period.
The technological safety of the operation of facilities in the chain "production - collection - preparation - transportation" is largely ensured by the uniformity of oil reserves development. To do this, it is necessary to have reliable information about the distribution of the energy potential of the reservoir, 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 the drilling of the well, since large bottomhole 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
A site of a natural or artificial area of the territory with wellheads, technological equipment, engineering communications and office premises located on it is allocated for well clusters. An enlarged cluster may include several dozen directional wells. The total oil flow rate of one well pad is taken up to 4000, and the gas factor - up to 200.
Well cluster technological structures usually include:
- wellhead sites of production and injection wells;
- measuring installations;
- supply units for reagents-demulsifiers and inhibitors;
- gas distribution and water distribution blocks;
- units for pumping water into injection wells;
- ESP and SRP pump control stations;
- foundations for pumping units;
- transformer substations;
- sites for the repair unit;
- collection tank and technological pipelines.
The structure of the well pad may include a wastewater treatment unit (SWSU) with local injection of water into the formation. In this case, there is no energy-intensive pumping of formation waters 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 downhole rod pumps due to the complications associated with pipe abrasion. In order to avoid accidents, when choosing pumping equipment, preference is given to ESP and hydraulically driven pumping systems in a closed oil and gas gathering system. Such systems allow the supply of inhibitors to prevent corrosion and wax formation.
The system of facilities for oil treatment, water discharge and injection is built depending on the distribution of reserves over the area of the deposit, production rates, degree of water cut and gas saturation of oil, pressure at the wellhead, location of well clusters (Fig. 5.1). These facilities must provide:
- pressurized collection and transportation of well products to the CPS;
- separation of gas from oil and non-compressor transportation of gas of the first stage of separation to collection points, gas processing plant and for own needs;
- measurement of production costs of individual wells and clusters, accounting for the total production of products from all wells;
- preliminary dehydration of oil.
Rice. 5.1.
Group metering stations
The gas-liquid mixture from the production wells enters the GZU, in which the periodic measurement in the measuring separator of the liquid and gas flow rates of each well is automatically performed. The number of installations is determined by calculations. Blocks for injection of a demulsifying agent and a corrosion inhibitor are located on the sites of the GZU.
Booster pumping station
In cases where the distance from the well pads to the CPS is large, and the wellhead pressure is not enough to pump fluids, a BPS is built. The mixture enters the BPS through oil-gathering pipelines after the GZU.
The DNS includes the following block structures:
- the first separation stage with preliminary gas extraction;
- preliminary dehydration and purification of formation water;
- measuring oil, gas and water;
- pumping and compressor air unit;
- reagent injection before the first separation stage;
- injection of inhibitors into gas and oil pipelines;
- emergency containers.
The construction of a booster pumping 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 fed to a flare or for local use. Oil and water with the dissolved remaining gas enter the second stage separators at the CPS and OTU.
Central collection point
At the CPS, crude oil goes through a full processing cycle, which includes two- or three-stage degassing of oil using separators and bringing the oil to the required conditions in terms of saturated vapor pressure. The gas after separation is cleaned from dropping liquids and fed for recycling or processing. The gas of the first and second separation stages is transported under its own pressure. The end stage gas needs to be compressed for further use.
Here, at the CPS, oil is dehydrated and desalted to marketable standards. Associated produced waters are separated from crude oil at an oil treatment unit (OTP) as part of the CPF. In a special tank, oil is settled, the oil emulsion is heated in tube furnaces and desalted. After that, the commercial oil enters the reservoir with subsequent pumping to the MN.
tank farms
The presence of a reserve fleet of tanks is an obligatory attribute of all technological schemes for the collection, preparation and transportation of oil and gas. Standard RVS type tanks are used to create reserves:
- raw materials supplied to the OTU, required in the amount of the daily volume of well production;
- commercial oil in the volume of the daily productivity of the OTU.
In addition, tanks of various volumes are needed to receive formation and waste water, as well as for emergency discharges.
To discharge paraffin deposits from stripping (steaming) of tanks, earthen storage pits are arranged. In addition, reservoirs are a source of atmospheric pollution due to the evaporation of hydrocarbons stored in them.
Compressor stations
CSs can be independent field development facilities or be part of the complex of technological facilities of the CPF. CS are designed to supply oil gas to the GPP, to compress gas in the gas lift production system and prepare it for transportation.
To remove gas from the cavity of the reciprocating compressor, a gas discharge candle is provided on the intake gas pipeline of each compressor compression stage with stop valves installed on it. The height of the candle is at least 5 m and is determined by gas dispersion calculations.
Flare system
Oil gas that cannot be accepted for transportation, as well as gas from purging equipment and pipelines, is sent to the emergency flaring 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 surface air layer, as well as the permissible thermal effects on humans and objects. The height of the pipe must be at least 10 m, and for gases containing hydrogen sulfide, not less than 30 m. The gas velocity at the mouth of the flare stack 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 products from production wells includes:
- flowlines from the wellhead to the gas pump;
- collectors that ensure the collection of products from the GZU to the points of the first stage of separation of the BPS or CPS;
- oil pipelines for supplying gas-saturated or degassed watered oil or dry oil from collection points and BPS to CPS;
- oil pipelines for transporting marketable oil from the CPS to the main PS of the main pipeline:
- gas pipelines for supplying petroleum gas from separation units to GTU, CS, CPS, GPP and own needs:
- gas pipelines for gas supply from the CPS to the main compressor station of the main pipeline.
