Waterflooding schemes. Coursework: Development of oil fields using contour and intra-circuit flooding

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 pressure control system

3. Design part

3.1 New equipment and technology for wastewater treatment

3.2 Ways to improve the technology of water injection into the reservoir

4. Calculation part

4.1 Calculation of oil reservoir development time

4.2 Calculation of the technical injection process. fluids into wells

5. Safety and environmental friendliness of the project

5.1 Occupational health, safety and fire prevention measures

5.2 Protection of subsoil and environment

Conclusion

Bibliography

Introduction

Reservoir 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 bodies. Therefore, formation water is pumped into productive or absorbing formations. Fresh water used in the technological process for oil desalination, as well as storm water entering the industrial sewer system, are also pumped in together with formation water. In general, all these waters are called wastewater. In the total volume of wastewater, the share of reservoir water is 85-88%, the share of fresh water is 10-12%, and the share of storm water is 2-3%. The use of oil field wastewater in the system for maintaining reservoir pressure during the water-pressure mode of field development is an important technical and environmental measure in the process of oil production, allowing 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. Currently, several types of water are used for RPM purposes, which are determined by local conditions. This is fresh water extracted from special artesian or sub-channel 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, therefore, in the effectiveness of influencing 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 multi-layered with high layer-by-layer heterogeneity of rocks in terms of permeability and small effective oil-saturated thicknesses. A number of fields are characterized by a hydrodynamic connection between reservoir layers, caused by the merger of layers or a small thickness of the sections between them with the presence of systems of fractures. Problems of efficient development of hard-to-recover reserves are solved by disaggregating production facilities, optimizing well patterns, improving waterflooding systems, optimizing reservoir and bottomhole pressures, and using 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 for a more rational use of its energy to displace oil. In the scientific and technical literature, studies concerning the role of the quality of injected water are not sufficiently covered. Under flooding conditions, the completeness of production of productive formations primarily depends on the degree of coverage of the development object both in area and in section, which is largely determined by the nature of the movement of injected water and formation water. Therefore, the main attention in geological and field analysis should be paid to the issues of formation coverage under the influence of injected water and the peculiarities of water movement through productive formations. The geological and physical factors influencing 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 liquids pumped 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 the Krasnokamsk and Dyurtyulinsky districts of the republic and partly on the territory of Udmurtia. The field was discovered in 1955 and put into development in 1958. Commercially oil-bearing deposits are 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. The main object of exploitation is the terrigenous formations of the Lower Carboniferous. For the further development of the Arlan deposit, the development of 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 is more than 100 km, with a width of up to 25 km, and 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 Kashiro-Podolsk productive strata of the Middle Carboniferous. The main reserves are concentrated in the sandstones of the Lower Carboniferous terrigenous strata (75% of the initial reserves) at a depth of 1400-1450 m. During development, reservoir flooding is used. The main method of operating production wells is mechanized. The total well stock 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 (LCNS) is more than 100 km, width - up to 30 km. Oil-bearing layers are the TTNK sandstone layers (Elkhovsky, Radaevsky, Bobrikovsky, Tula and Aleksinsky horizons of the Visean stage), carbonates of the Tournaisian stage, Vereisky, Kashira and Podolsky horizons of the Moscow stage of the Middle Carboniferous. The deposit is confined to a vast asymmetrical anticline with a northwestern direction. Its southwestern wing is steep (up to 4°), the northeastern wing is flatter (up to 1°). The amplitude of the structure along a closed isohypse of 1190 m is 90-100 m. In the core of the fold there is a giant barrier reef of Upper Devonian (Famennian) age. Along the roof 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 practically leveled out in the Permian deposits. The depth of the TTNK is 1250-1300 m, regionally plunging from south to north. In the TTNK section, nine sandstone layers are distinguished and clearly correlated: Aleksinsky horizon - layer C0; Tula horizon – layers C I, C II, C III, C IV0, C IV, C V and C VI0; Bobrikovsky-Radaevsky horizon - layer C VI. The thickness of the layers varies sharply from well to well. The main and most consistent in area are the layers C II, C III (in the northern part of the field) and C VI. The remaining layers are thinner and more heterogeneous. Sandstones are characterized by fairly high filtration and capacitance properties (FPP). The thickness of the TTNK ranges from 33 to 150 m. Its sharp increase is confined to zones of deep erosion of the carbonate strata of the Tournaisian stage. In some wells, limestones of Tournaisian age are completely eroded, and the resulting karst sinkholes are filled with a thick layer of terrigenous sediments. Carbonate reservoirs of the Middle Carboniferous (Kashiro-Podolsk and Tournaisian) have much worse reservoir 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 TTNK is 8 MPa, gas saturation is from 5 to 20 m3/t. The oil content of the Middle Carboniferous section was studied mainly in conjunction with the search and exploration of oil deposits in the terrigenous strata of the Lower Carboniferous. Stratigraphically, the Middle Carboniferous deposits include the upper part of the Bashkirian stage and the entire Moscovian stage. They are composed of carbonate rocks with subordinate interlayers of marls, mudstones and siltstones, found mainly in the Vereisky horizon. Based on the complex of geological and field geophysical materials, the sediments under consideration are divided into 11 units (I-XI), of which the II-VII units of the Kashira and Podolsk horizons are commercially oil-bearing, and the productivity of the latter has been established only in the Vyatskaya area. The identified units can be quite clearly traced not only within the field under consideration, but also on a significant territory of the Birsk saddle and the adjacent areas of the Permian-Bashkir arch and the Verkhnekamsk depression. Each of the members is a rhythmically constructed lithological complex, the lower part of which is made of carbonate rocks with a high content of porous-permeable varieties, and the upper part is predominantly composed of dense impermeable carbonates, clayey and clayey-carbonate sediments. According to standard logging, the bottoms of each member, as a rule, are characterized by negative SP readings, low GM, positive MS increments, low and average GPS values, and when subdividing and correlating the Middle Carboniferous section, they are conditionally identified as a productive formation. The upper, most dense part of the section of the considered packs, which is identified as a “dense section” and is assessed as oil-resistant, has the opposite electrical and radio logging characteristics. The marked productive layers are confined to: B1 (member XI) - to the Bashkirian stage, overlying B1-B3 (members VIII-X) - to the Vereisky, K1-K4 (members IV-VII) - to the Kashira stage, P1-P3 (members I and III ) - to the Podolian horizons. When comparing these productive formations, a complex lens-shaped distribution of the reservoir layers they contain is revealed, due to frequent changes in the mineralogical composition, structural and textural composition, capacitive and filtration properties of the rocks. As studies have shown, 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 (dissection) of the III-VI members sharply increases, the degree of their dolomitization and sulfatization increases, the intensity and variety of forms of manifestation of post-sedimentary transformations increases, 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 intensify in the southeast direction, and in the Yusupovsky section of the Arlanskoye deposit, the entire Middle Carboniferous section becomes unproductive. In the Arlanskaya and Nikolo-Berezovskaya areas, the III and IV units are industrially oil-bearing, confined respectively to the base of the Podolsk (P3) and the top of the Kashira (K1) horizon, and in the Novokhazinskaya area, and only in its northern half (Sharipovsky area), the underlying V and Members VI (K2 and K3), identified in the middle of the Kashira horizon section. In the northwestern part of the Arlanskoye field in the Vyatka area, the range of commercial oil content increases, covering II-III units of the Podolsk horizon (P2 and P3) and IV, V and VII members of the Kashira horizon (K1, K2 and K4), the total thickness of which reaches 110 m ( Fig. 1).

Fig.1. Diagram of the distribution of oil deposits in the Middle Carboniferous of the Arlanskoye 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; operational areas: 1 - Vyatskaya, 2 - Arlanskaya, 3 - Nikolo-Berezovskaya, 4 - Novokhazinskaya. In the process of prospecting and exploration work, oil shows were noted in the Arlanskoye field, and in the well. 92 and 210 in the Nikolo Berezovskaya area, oil inflows were obtained during the opening and testing of formations B2 and B3 (units IX and X), located in the lower part of the Vereisky horizon. However, their oil content is still not entirely clear. From the structural-facial analysis carried out, it follows that the prerequisites for the extremely heterogeneous (differentiated) spatial distribution of oil content of the Middle Carboniferous (more precisely, Kashirsko-Podolsk) sediments of the Arlanskoye field were laid during the period of accumulation and primary (sedimentation-diagenetic) transformation of sediments in the conditions of a shallow shelf sea 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 Kashirsko-Podolsk deposits took place with the combined participation of 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 layers of productive layers K 1 and P 3 is made of organogenic-relict (metasomatic) dolomites and biomorphic (mainly foraminiferal) dolomitized limestones, the emergence of pore space in which is due to the primary placement of shaped elements (mainly shells of organisms) of the sediment with the active participation of dolomite metasomatism. The transformation of sediments into subsequent phases took place mainly under the influence of leaching of calcareous relict areas not replaced by dolomite. A significantly different carbonate-accumulation environment in the Kashira-Podolsk time was on the territory of the Novokhazinskaya area, which was a vast sandbank, somewhat isolated from the main waters of the sea basin. Here, under the influence of high alkalinity, mineralization 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, optimal conditions for dolomite sedimentation are achieved at the moment of oversaturation of natural marine rocks under calcium sulfates. According to field geophysical studies of wells, in the Arlanskaya and Nikolo-Berezovskaya areas, up to six layers of porous-permeable rocks are distinguished in the productive formation K 1, 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 the 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 layers well saturated with oil, at elevated hypsometric elevations (above the OWC), there are often layers with highly porous rocks (more than 15%), which, due to low permeability (less than 0.005 μm 2) and their lens-shaped occurrence, turned out to be weakly 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 strata contain only buried water. The presence of water-saturated layers among well-saturated layers is confirmed by the production of water together with oil in wells located at high hypsometric elevations (Fig. 2).

Rice. 2. Schematic profile of the oil-bearing member of the Kashira-Podolsk deposits of the Arlan area. a - dense section between layers; interlayers: b - industrially oil-bearing, c - slightly oil-saturated, d - water-saturated; d - VNK; e - dense rocks in the productive formation; 1-8 wells

To assess the effective oil-saturated capacity 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 Kashira-Podolsk deposits is 9-11%. The determining factor here is the minimum oil saturation value. To determine the nature of the saturation of the formations, materials from studies of oil and gas condensate, BC (preferably with highly mineralized water) and soils were used according to generally accepted methods. Based on the obtained distributions of resistivity (rp) of the formations located in the known oil and aquifer parts of the deposit, and the distributions of the complex parameter Kp 2 rp for the same layers, their critical values ​​for oil-bearing formations were identified (rp = 7 Ohm-m and Kp 2 r p r p =0.41). Using specific dependencies r p = f (k p) and r p = 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 results of well testing, i.e. In none of the tested intervals from which commercial oil flows were obtained, formations with an oil saturation of less than 67% are identified. Thus, according to the described methodology, the following parameters were determined for each productive layer: h ef, r p, Kp and Kn. In some cases, to assess the nature of reservoir saturation, INK materials were used, confirming the established value of oil saturation by r point. The complex picture of the hypsometric distribution of oil content in the section in the presence of water-saturated layers often creates the appearance of a sharp fluctuation in the oil content. The boundary of an oil deposit or the oil-bearing contour in these conditions is the line of replacement of industrial oil-bearing reservoirs with impermeable rocks. Based on the nature of the distribution of oil-saturated strata within the entire area of ​​the field, extensive, medium-sized and small oil-bearing areas isolated from each other are distinguished. The identified features of the distribution of oil content and the structure of oil deposits in the carbonate deposits of the Middle Carboniferous of the Arlanskoye field made it possible to identify calculation objects, areas with different categories of reserves, determine 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 by industrial categories A, B and C 1. The field has been developed, oil deposits in the Middle Carboniferous are shallow, which allows them to be brought into commercial development quickly and at low cost.

2. Technological part

2.1 Current state of development and dynamics of the main technological indicators of the field

Let us analyze the technical and economic indicators of the Arlan UDNG presented in Table 1.

Table 1 - Main technical and economic indicators of the Arlan UDNG for 2006-2008.

Indicators	2006	2007	2008
Oil production thousand rubles	2168,5	2156	2181
Commercial oil t.t	2153,043	2140,664	2170,173
Gross output thousand rubles	1627180	1504413	1618174
Average daily production of oil wells per spent well of the existing stock, tons/day	2,3	2,2	2,2
Extraction of liquid t.t.	12119	13325	13913
	82,1	83,8	84,3
Commissioning of new oil wells via 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
incl. production drilling thousand rubles	82429	119800	173315
exploratory drilling	58183	124000	77706
Well construction	76762	173418	124632
Average annual cost of fixed industrial and production assets by core activity	2842535	3180431	3925996
Capital productivity (gross output per 1 rub. average annual value of industrial production capital) rub.	0,57	0,47	0,41

Let's start with an analysis of the production program. In 2008, the oil production plan was exceeded by 3.1%. The annual level of oil production in 2008, compared to 2007, increased by 25 thousand tons.

At the same time, the volume of commercial 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 NGDU Krasnokholmskneft.

Rice. 3 Fluid production dynamics

Rice. 4 Oil production dynamics

In recent years, against the backdrop of an increase in liquid production volumes, oil production has been gradually decreasing, which indicates an increase in the degree of water cut in wells. In 2008, more water was pumped in, which resulted in an increase in liquid production volumes by 462.7 thousand tons.

Let us analyze in more detail the change in oil production volume and the factors that influenced this change.

For clarity, let's draw up table 2 of changes in data 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 of oil wells per spent well of the existing stock tn/day	-0,1	0	95,7	100,0
Oil water cut (weight) %	2,2	0,5	102,7	100,6
Exploitation ratio of the existing oil well stock	-0,004	-0,006	99,58071	99,37238

The average daily production of oil 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 increasing (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 utilization rate 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 pressure control system

Natural regimes of occurrence of oil deposits are short-lived. The process of reducing reservoir pressure accelerates as fluid extraction from the reservoir increases. And then, even with a good connection of oil deposits with the supply circuit, its active influence on the deposit, depletion of reservoir energy inevitably begins. This is accompanied by a widespread decrease in dynamic fluid levels in wells and, consequently, a decrease in production. When organizing reservoir pressure maintenance (RPM), the most difficult theoretical issue, which has not yet been fully resolved, is achieving 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 the process of displacement is. The mechanism for displacing oil from a porous medium cannot be represented by simple piston displacement. Here there is a mixing of agents, and a rupture of the oil stream, 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 a field, the maximum value of which a technologist should strive to achieve, depends on all of 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 flooding pattern, which is divided into several types. Maintaining reservoir pressure, 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 included in development projects and is carried out at many fields in the country. Over the years, large-scale experiments have been carried out at the Arlanskoye field to test methods for increasing oil recovery. The largest of them was the long-term injection of a surfactant solution at the Nikolo-Berezovskaya area. Unfortunately, the result was negative and the experiment was stopped. One of the largest is also an experiment to study the dependence of oil recovery factor on the density of the grid of production wells in the Novokhazinskaya area. The scale of these works was unique. The results obtained clearly proved that the production of reserves is significantly determined by the grid density. In addition to the above experiments, work was carried out at the field on a pilot and industrial scale on in-situ combustion (it was possible to organize combustion, but due to the presence of acidic products, the results were negative), intensification of the production of undrained reserves of thin formations 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 Tournaisian stage has so far been carried out haphazardly, since there is no own network of wells for these objects, as well as a system for maintaining reservoir pressure (except for the Vyatka area, in which the deposits of the Kashiro-Podolsk horizon were drilled using its own well pattern using waterflooding). The development of these objects is mainly planned at the expense of the revolving fund. In total, about 9 thousand wells for various purposes were 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 taken out of operation. Liquid withdrawal also decreased from 160 to 80 million tons. Over the entire development period, 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 technological scheme of reservoir pressure maintenance at the Arlan UDNG is determined by the oil field development project and, first of all, by the number and location of injection wells. The following principal PPD systems of the Arlan UDNG can be distinguished:

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 a pumping station ensures the injection of an agent into a group of wells located at a considerable distance from the pumping station.

In turn, the centralized PPD system is divided into group and radial. With a group system, several wells are supplied with one injection pipeline: a variation of the group system is the use of distribution points (DP), in this case a group of wells is connected directly to the DP. With a radial system, a separate injection water pipeline 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 structure is a source of water supply: water is extracted here for the purpose of injection into the reservoir. Water intakes are divided into: a) under-channel; b) open. In under-channel water intakes along river beds, under-channel wells with a depth of 12...15 m and a diameter of 300 mm are drilled to the aquifer. The water is lifted by an artesian or electric pump lowered into the well. In siphon water intakes, water is pumped out from wells under the influence 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 injection facility. In open water intakes, a pumping unit is installed near a water source and pumps water from it to the injection site. In-ground pumping stations with pumps located below 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 injection facilities. 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, process piping, starting and control equipment. In recent years, block-type pump stations have become widespread at the Arlansky UDNG, which are manufactured at factories in the form of separate blocks and delivered to the installation site in assembled form.

3. Design part

3.1 New equipment and technology for wastewater treatment

Oilfield wastewater is a diluted disperse system with a density of 1040-1180 kg/m 3, the dispersion media of which are highly mineralized brines of the chlorine-calcium type (sodium chloride, calcium chloride). Dispersed phases of wastewater are oil droplets and solid suspensions. When extracting well production from the subsoil, the 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 emulsion separates 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 interfacial tension at the oil-water interface due to the introduction of a demulsifier reagent into the system and turbulization of the stratified flow, the dispersion of oil in water, as well as the washing and peptization of various sludge deposits (corrosion products, clay particles) with in the morning pipeline surfaces. In addition, an intermediate layer consisting of water droplets with undestroyed armor shells accumulates in water separators, 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 pollutants passes into the aquatic environment. As a result of mixing waters of different chemical compositions, the sulfate balance is disrupted, 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, to 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 wastewater can be contaminated with sulfate-reducing bacteria carried in stormwater, which contributes to the precipitation of calcium carbonate and iron sulfide. The presence of oil droplets and mechanical impurities in wastewater leads to a sharp decrease in the injectivity of productive and absorbent formations. Therefore, before pumping wastewater into productive or absorbent formations, it is necessary to purify it. The main quality indicators of water that make their use possible are:

4) concentration of hydrogen ions (pH) – 8.5...9.5;

These data are based on the experience of using pressure maintenance at the Tuymazinskoye field and should be reviewed when organizing pressure maintenance in other areas. At the Tuymazinskoye field, 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 permeability of the formations, the refusal to prepare water using the above technology did not cause significant complications in the operation of the system, for other areas it could be unacceptable. Then the injection of formation water began, which required its own approach. Reservoir waters are characterized by a high content of salts, mechanical impurities, dispersed oil, and high acidity. Thus, the water of formation D 1 of the Tuymazinsky oil field belongs to highly mineralized brines of the calcium chloride type with a density of 1040...1190 kg/cub.m. with salt content up to 300 kg/cub.m. (300 g/l). The surface tension of water at the interface 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 substances is characterized by a predominant content of particles up to 2 microns (more than 50% by weight). During the process of separation from oil, formation waters are mixed with fresh water, with demulsifiers, as well as with process water from oil treatment plants. It is this water, called waste water, that is pumped into the reservoir. A characteristic feature of wastewater is the content of petroleum products (up to 100 g/l), hydrocarbon gases up to 110 l/cub.m., suspended particles - up to 100 mg/l. Injection of such water into a reservoir 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 waste water for pressure maintenance purposes is widely used. The water must be pre-treated to remove mechanical impurities (up to 3 mg/l) and petroleum products (up to 25 mg/l). The most widely used cleaning method is gravity separation of components in tanks. In this case, a closed scheme is used. Waste water containing petroleum products up to 500 thousand mg/l and solids up to 1000 mg/l enters settling tanks from above. The layer of oil located at the top serves as a kind of filter and improves the quality of water purification from oil. Mechanical impurities settle down and, as they accumulate, are removed from the tank. From the tank, water flows into the pressure filter. Then a corrosion inhibitor is supplied to the pipeline, and the water is pumped out to the pumping station. Vertical steel tanks are used to accumulate and settle water. Anti-corrosion coatings are applied to the inner surface of the tanks to protect them from the effects of formation waters. The choice of technological scheme for wastewater treatment depends on many factors: type of production, feedstock, quality requirements and volumes of treated wastewater. The choice of treatment facilities involves a comprehensive assessment of production conditions: the availability of existing treatment equipment, the availability of production areas for upgrading existing and placing 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 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 bulk of oil and mechanical impurities from water II. Its operating principle is based on gravitational separation at low speed of wastewater (less than 0.03 m/s). At this speed of movement of wastewater, oil droplets with a diameter of more than 0.5 mm have time to float to the surface. Oil accumulated in the trap III is removed through an oil collection pipe and pump 2 supplied to the oil treatment plant for re-processing. After the oil trap, wastewater is supplied to settling ponds for further purification from oil and mechanical impurities. 4, where the duration of settling can be from several hours to two days. Sometimes, to speed up the process of sedimentation of solid suspended particles or neutralization of wastewater before settling ponds, chemicals are added to the water: lime, aluminum sulfate, ammonia, etc. After settling ponds, the oil content in wastewater is 30-40 mg/l, and mechanical impurities - 20-30 mg/l. This depth of wastewater treatment IV is usually sufficient for pumping it into absorbent formations, and in this case water through the chambers 5 And 6 is received by pumps 7, which pump it into absorption wells. Injecting water into injection wells requires deeper purification. In this case, the wastewater from the chamber 6 pump 8 sent to alternately operating filters 9 And 10. Quartz sand (0.5-1.5 mm fraction), anthracite chips, expanded clay sand, graphite, etc. are used as filter material. Waste water entering the filter must contain no more than 40 mg/l of oil and no more than 40 mg/l of mechanical impurities 50 mg/l. The residual content of oil and mechanical impurities after the filter is 2-10 mg/l. Purified water from filter V enters tank 11, from where it is pumped by a high pressure pump 14 is pumped into the 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 from the pump. 13 from container 11 and pumped through the filter in the opposite direction. The washing duration is 15 - 18 minutes. Water containing washed mud is discharged into a sludge tank 12. Closed wastewater treatment plants eliminate contact of water with atmospheric oxygen to prevent oxidative reactions. According to the principle of operation, closed-type installations 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, removed from settling tanks or demulsifier heaters of the oil treatment plant and containing a demulsifier reagent, passes through a dropletizer 1 and enters a settling tank with liquid hydrophilic filter 2 , in which preliminary water discharge is carried out. The settling tank with a liquid hydrophilic filter is made on the basis of a standard vertical tank and has a siphon device that ensures the maintenance of a given layer of water 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 demulsifier reagent and turbulent mixing in the drop former, enters the settling tank 2 under the layer of water through the distributor. Rising through a liquid hydrophilic filter (layer of water), oil droplets are freed from the emulsion water. In this way, preliminary dehydration of oil occurs and pre-dehydrated oil II is removed from the upper part of the settling tank 2. 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 standard vertical tank and has a siphon device that ensures the maintenance of a given oil layer above the water layer. Wastewater is introduced through a radial perforated distributor into the oil layer (liquid hydrophobic filter) and, falling down, is freed from oil droplets. The captured oil V (trap oil) is collected in a chamber, removed from the top of the settling tank and sent to the oil treatment plant. A layer of indestructible emulsion IV can form at the oil-water interface , which is periodically removed and also sent to the oil treatment unit. The water that has passed through the oil layer and is freed from the main part of the droplet oil is also subject to sedimentation in the water layer. All these operations provide sufficiently deep purification of formation water from dripping oil, and purified water VI, having passed through container 4 , pump 5 is pumped into absorption or injection wells. The main apparatus of closed-type wastewater treatment plants based on the filtration principle is a coalescing filter-settler type FZh-2973, developed by the BashNIPIneft Institute. Wastewater is first subjected to sedimentation in a horizontal settling tank, and then through the inlet pipe 6 enters the receiving compartment IN settling filter located in the middle part of the housing 3. Waste water from the receiving compartment through perforated partitions 10 enters the filtration compartments B. The filtration compartments are filled with a coalescing filter 5, which is used as granulated polyethylene with a granule size of 4-5 mm. Polyethylene has a hydrophobic property: oil wets it, but water does not. Therefore, oil droplets, lingering on the surface of the granules, merge (coalesce) and leave the filtration compartments B into settling compartments A in enlarged form. For this reason, rapid stratification of water and oil droplets occurs in the settling compartments, and oil is removed from above through oil outlet pipes 1, and purified water through pipes 7. Mechanical impurities deposited in the settling compartments are removed through pipes 8. The settling compartments are equipped with manhole hatches 2. Loading and unloading of granular polyethylene into the filtration compartments is carried out through hatches 4 And 9. If granular polyethylene is clogged, it is washed by feeding 10-15% kerosene dispersion into purified water for 30 minutes.

Technological diagram of a closed-type wastewater treatment plant based on the sedimentation principle

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 in the liquid. In a flotation tank, gas bubbles form in the flotation zone 5 due to the release of dissolved gas from gas-saturated wastewater as a result of a decrease in pressure when it enters this zone. Gas saturation pressure of water - 0.3-0.6 MPa; the amount of gas released from water is 25 l/m3. Gas-saturated water is introduced through inlet pipe 1 into the lower part of the flotation zone using a perforated distributor. Wastewater rises in the flotation zone at a speed that ensures that the water stays in the flotation zone for about 20 minutes. Emitted gas bubbles, rising, meet dispersed particles distributed in the water on their way. Dispersed particles that are poorly wetted by water (oil droplets) are captured by bubbles and float onto the surface, forming a layer of foam there. The captured oil is collected in the Yults trench 4 to collect oil and is discharged through a pipe 2. Water from flotation zone 5 flows into the settling zone 6, located in the annular space between the housing 3 tank and the flotation zone, where it slowly falls down. Dispersed particles, which are well wetted by water, are not captured by gas bubbles in the flotation zone, but, under the influence of gravity, settle down in the flotation and settling zones, from where the sediment is discharged through appropriate perforated pipes and pipes 9 And 10. Purified water is discharged through a ring perforated collector and pipe 8. The flotation tank is sealed, so the gas released from the water is removed from the top of the tank through pipe 7. The content of impurities (mg/l) in the wastewater entering the flotation tank for cleaning should be: oil - 300, mechanical impurities - up to 300. Residual The content in purified water leaving the flotation tank is (mg/l): oil - 4-30, mechanical impurities - 10-30.

Electroflotation is flotation with gas formed as a result of electrolysis. When water is electrolyzed, bubbles of oxygen and hydrogen are formed. The advantage of electroflotation over gas flotation is the possibility of obtaining finely dispersed gas bubbles of up to 16 * 10 7 pcs/(m 2 * min) during electrolysis, which leads to rapid clarification of oil-containing water. The essence of the electroflotation method of wastewater treatment is as follows. Electrodes are installed in the technological container and a constant electric current is passed through. As a result of electrolysis, gas bubbles are released on the electrodes, which rise upward, penetrating the layer of oil-containing water being treated. When moving in wastewater, bubbles collide with dispersed particles suspended in water, stick to them and float them. Thus, 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 pipe located at the bottom of the device. The process of wastewater treatment by electroflotation is significantly influenced by the location of the electrodes. It is recommended to place one electrode at the bottom of the device so that it covers the entire bottom if possible. This is necessary so that the bubbles released during electrolysis on this electrode penetrate the entire volume of water being treated and ensure 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. Electrodes are made in the form of plates, gratings; movable electrodes can be used to regulate 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 combination of tiny dispersed particles into fairly large compounds, followed by their sedimentation. The mechanism of action of a coagulant such 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+ + ZN 2 O “Al (OH)3 + ZN+.

The resulting aluminum hydroxide is a flaky gelatinous sediment, which, as it settles, carries with it dispersed particles (oil and mechanical impurities). Since this process takes place actively in an alkaline environment, ammonia water or lime milk (obtained by slaking lime) is added simultaneously with the coagulant. In addition to aluminum sulfate, coagulants are also ferric chloride and 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. Unlike 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 efficiency of coagulants and flocculants increases significantly when they are used together in the wastewater treatment process. Moreover, the dosage of flocculants is tens or even hundreds of times less than coagulants.

3.2 Ways to improve the technology of water injection into the reservoir

In many multi-layer fields of the Arlan UDNG and one injection well there are more than two already opened (perforated) production objects. This was done to maintain reservoir pressure (water injection volumes) while limiting capital investments for the construction of new injection wells. It is known that the joint injection of water into several layers, heterogeneous in permeability, leads to rapid watering of deposits, low coverage of their influence and the formation of water blockades of individual undeveloped zones. At the same time, the accelerated advance of the front of oil displacement by water through highly permeable formations leads to water breakthroughs to the bottoms of production wells and, as a result, the volume of produced water and the costs of its injection increase. This, at best, leads to an increase in the cost of oil production, and in the worst case, to the decommissioning of a waterlogged well along with the loss of untapped oil reserves remaining in low-permeability formations. The practice of joint injection of water into several layers also leads to the loss of information about the actual injection of water into each of the layers. The contradiction between “economic considerations” and subsoil protection when choosing production facilities can already be resolved if we use technology 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 UralGeoTech Research Institute and the Bashneft Research Institute. The main distinctive features of this technology are: alternate lowering of sections of formations, 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 differentiated repression. This will prevent flows both between selected intervals - layers through the packer at the time of injection (at 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 installation from wells for inspection or repair. This technology allows you to study each of the selected intervals separately and set the optimal repression value for them, taking into account existing restrictions. To implement the technology, a well installation is used, consisting of a pipe string with several packers, the number of which coincides with the number of sections, and each section includes at least one well chamber with a valve that regulates the flow. In this case, one or more packers on top are equipped with a pipe string disconnector without or with a thermal compensator, or with 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 a layout diagram for water injection at three production facilities (isolated formations). In the rules for the development of oil and gas-oil fields, an operational object is understood as “a productive formation, part of a formation or a group of formations allocated for development by an independent network of wells”, which does not exclude its combination with other objects, but has an individual impact system that provides differentiated control of filtration flows (field of reservoirs). pressure)". If, through one injection well, two heterogeneous and hydraulically isolated formations are affected by two different depressions, and completely independent values ​​of depressions are also created from production wells on the same formations, then these formations should be considered as separate production development objects.

Rice. 7 Scheme of the underground layout of the ORZ injection well

And vice versa, if, during the joint exploitation of several formations, some of these formations are not affected at all, for example, due to low permeability or due to the impossibility of creating a maximum pressure gradient on them, then they can hardly be classified as production objects, since in this In this case, they are no different from non-perforated formations. An independent well network at the level of each object is needed solely to ensure an 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 achieved using a combined well pattern for them. Currently, work has been carried out for injection wells with four isolated reservoir intervals, but there is a fundamental and technical opportunity to significantly increase the number of such intervals (objects). Successful implementation of this technology is possible on injection wells that have an open hole to productive formations, which allows you to change the water injection modes in each interval (formation) by changing control valves or fittings using rope 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 influence individual formations due to the operational (by changing wellhead regulators or downhole regulators in the corresponding sections) changing the regimes of each of the well layers in a wide range, which ultimately will increase the oil recovery factor. This technology makes it possible to optimize repression, change filtration directions, and perform non-stationary waterflooding even in winter. Thus, in multi-layer fields it is necessary to carry out large-scale implementation of ORRNEO technology in order to ensure a differentiated impact on various production objects (intervals and/or sections of the reservoir). Currently, work has been carried out for injection wells with four isolated reservoir intervals, but there is a fundamental and technical opportunity 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 SANDOR software package of the Ural branch of the Bashkirgaz Research Institute, depending on the geological and field characteristics of the corresponding operational facilities. Each subsequent section is lowered on a column of process pipes, and the upper section is lowered on a column of stock pipes. Specialized equipment for the implementation of ORRNEO technology is being developed by NTP Neftegaztekhnika LLC, 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 a packer installed in the well, as well as to compensate for changes in the length of the tubing string under thermobaric conditions (Fig. 8 ) PDSh type packer. The main advantage of this packer is the increase in its tightness, as well as the reliability of extraction from the well. At the same time, the number of hoisting operations and accidents during operation of a multi-packer installation is reduced. The packer includes an anchor on top that is triggered by both pipe and bottomhole pressure, which increases the reliability of the packer both during setting and during its operation. The packer also has a “cone-ram” anchoring device at the bottom, which is released both from the tension (8 - 12 tons) of the pipe string, and without tension, by moving (mechanically or hydraulically) the sliding sleeve in the barrel, without cutting off the shear screws of the ram holder .

Fig.8 Column disconnector RKSh

Downhole regulator type 5 RD. This regulator allows, depending on the reservoir parameters, to maintain a given bottomhole pressure or a given water flow rate during the injection process, even when the reservoir pressure and injectivity coefficient change. Wellhead regulator type 5 PP. This regulator, unlike traditionally used wellhead fittings, allows you to quickly change and maintain set values ​​of wellhead pressure, in particular when studying formations. The effectiveness of the technology for simultaneously separately pumping water into several layers at injection wells was tested at the following multi-layer fields: Vanyeganskoye, Ai-Eganskoye, Priobskoye, Tarasovskoye, Barsukovskoye, Yuzhno-Tarasovskoye, Festivalnoye, Vostochno-Yagtinskoye, Yuzhno-Kharampurskoye and others. The economic effect of this technology is mainly expressed in additional oil production or reduction in capital investments for drilling additional wells. Compared to the separate operation of several layers, the technology allows:

Reduce capital investments for drilling wells (2-3 times);

Reduce operating costs (variable costs) (by 20-40%);

Reduce the development period of a multi-layer field (by 30%);

Increase the cost-effective development period of watered and gas-filled formations by extending their operation with the connection of additional facilities;

Increase the oil recovery factor of reservoirs by increasing the period of their profitable development;

Reduce the likelihood of freezing of Christmas trees and flow manifolds of injection wells due to low permeability of the formation;

Increase the efficiency of using wells and downhole equipment;

Reduce the likelihood of production casing leaks.

Compared to the joint exploitation of several layers, the technology allows:

To increase the oil recovery factor of formations by disaggregating objects of different permeability and different saturation and increasing the degree of their flooding coverage;

Increase oil production by 30-40% due to differentiated and controlled impact on each of the formations;

Ensure accounting of injected water (agent) into each of the layers;

Prevent interlayer flows along the wellbore at the time of its shutdown and during small repressions;

Increase the efficiency of enhanced oil recovery methods by using one well simultaneously for reservoir pressure maintenance and selective injection of an agent to level the injectivity profile;

Unsteadily influence the formations, changing their regimes;

Ensure increased repression of low-permeability oil-saturated formations while simultaneously limiting water injection into high-permeability formations;

Regulate the directions and rates of filtration of formation fluids, quickly managing the field of formation pressures;

Reduce the likelihood of leakage in the production string;

Explore and control the development of individual layers. Currently, the technology has been successfully implemented at 37 injection wells, including 12 with 3 layers and 25 with 2 layers. The technology is most effectively implemented on gas-lift and injection wells.

4. Calculation part

4.1 Calculation of oil reservoir development time

In this regard, one of the tasks of development analysis is to confirm the operating mode of the field 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 date of analysis are considered. If it is discovered that the average reservoir pressure in the production zone is below the saturation pressure, and the bottomhole pressure in production wells has decreased relative to the saturation pressure by more than 25% with a significant increase in the gas factor, then there is no water pressure regime in the field and its development is carried out in the dissolved gas. It should be noted that at the current level of development of the oil field business, such a situation is extremely rare. If there is 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 extracted from the reservoir due to the elastic energy of the liquid and formation is determined

· - reservoir elastic energy reserve;

· - coefficient of elastic capacity of the formation;

· - formation volume;

· - decrease in pressure,

· - porosity;

· - coefficient of compressibility of liquid (oil);

· - coefficient of compressibility of the medium (rock);

· - initial average reservoir pressure;

· - current average reservoir pressure.

By comparing the current accumulated oil and water production with , one can be convinced that there is still elastic energy in the reservoir or that it is necessary to introduce pressure maintenance methods. To identify the regimes of an oil deposit, in addition to data on reservoir parameters, the ratio of saturation pressure and reservoir pressure, it is necessary to establish the hydrodynamic connection of this deposit with the aquifer region. 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 when analyzing reservoir pressures and in hydrodynamic calculations during design, provided that these fields are large in terms of production and injection, if they have been in operation for a long time and if water injection began with a lag in relation to the extraction or is systematically carried out in smaller volumes than liquid sampling. If necessary, this type of research is best carried out when drawing up a 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 made when analyzing the development. The influence of the development of neighboring fields is established by changes in reservoir pressure and displacement of the oil-water contact, and sometimes a movement of oil deposits is noted. It is easier to establish this before the development of the field in question begins based on the abnormally low initial reservoir pressure compared to neighboring deposits. During the work, the influence of neighboring deposits is determined by calculation using computer modeling. The hydrodynamic connection of this deposit with the boundary area also manifests itself during the operation of boundary and near-contour injection wells in the form of leaks of injected water into the boundary area. If during intra-circuit flooding all the injected water goes inside the reservoir, then in peripheral 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. The volume of leaks is determined by computer modeling or by elastic regime formulas (method of sequential change of stationary states) provided that the deposit is represented as an enlarged well:

· - leakage of injected water into the perimeter area;

· - average permeability of the formation;

· - formation thickness;

· - water viscosity;

· - correction factor, determined during 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;

· - piezoelectric conductivity coefficient.

4.2 Calculation of the technical injection process. fluids into wells

The total injection by rows of injection wells, by the field and its facilities is determined as the sum of the quantities of water injected by individual wells. The distribution of injection during intra-circuit flooding between adjacent areas or development blocks is carried out in accordance with the rate of fluid withdrawal or in accordance with the average hydraulic conductivity of adjacent areas or development blocks. It is recommended to distribute the volumes of injected water in wells of cutting rows between adjacent areas, taking into account fluid withdrawals and changes in reservoir pressure over the analyzed period in these areas according to the formula:

· - volume of injection for the analyzed period (can be by year or even more granular);

· - fluid selection for the analyzed period from half the area adjacent to a number of injection wells;

· - coefficient of elastic capacity of the formation in the adjacent area;

· - change in reservoir pressure in the adjacent area over the analyzed period;

· - reservoir volume within the adjacent area;

· - injection losses (leakage into other formations due to leakage of the column, losses on the surface, etc.).

As with the distribution of oil and liquid production, the greatest difficulty and convention is the distribution of injection between the layers of a multi-layer field using flow metering data. A simpler method is to distribute injection in proportion to the accumulated production of reservoir fluid. Quantitative determination of the efficiency of formation hydrodynamic pumping, i.e. oil production through the use of hydrodynamic impact is carried out by comparison with the indicators of the base option. The basic option is a development option that would have been implemented at a given hydrodynamic impact site if the considered reservoir hydrodynamic pumping had not been used there. The effect of hydrodynamic impact over a given time interval is defined as the difference between actual oil production and oil production under the base case. The forecast of development indicators for the basic option (oil production, liquids, water cut, number of wells, pressure drops, etc.) should be made for a period of one to six years, depending on the impact technology used. It is advisable to determine oil production (technological efficiency) due to hydrodynamic reservoir formations quarterly. In cases where the increase in oil production for the quarter turns out to be insignificant compared to the total oil production from the affected object, the quarterly efficiency is estimated as a quarter of the annual effect. The effectiveness of reservoir hydraulic pumping should be determined as a whole for the affected object. In cases where the effect is determined by individual wells (“well” characteristics), the effect of mutual influence of wells must be taken into account. The identification of calculated objects of hydrodynamic impact to determine the effectiveness of hydrodynamic pumping stations should be based on the results of a detailed geological and field analysis of the development of productive strata. If such areas have not been previously identified, their boundaries are established on the basis of geological and field materials, the balance reserves in these areas are calculated, and the degree and nature of the production of oil reserves from them is determined. At hydrodynamic impact sites, several hydrodynamic pressure pumps are usually used simultaneously or with a time shift. In these cases, the overall technological effectiveness of all methods of influence is determined. Isolation of the effect from each type of hydrodynamic impact can be done conditionally, taking into account the degree of impact and implementation. The amount of increase in final oil recovery due to hydrodynamic stimulation methods is determined by the volume of additional balance oil reserves involved in development. The use of hydrodynamic stimulation methods belonging to the first group leads mainly to an increase in current oil recovery, but in some cases can also increase the final oil recovery factor (if these methods allow poorly drained oil reserves to be brought into active development). In particular, forced fluid withdrawal leads to an increase in final oil recovery due to an increase in the profitability limit of well operation in terms of water cut. Methods of the second group are aimed mainly at involving undrained or poorly drained balance oil reserves into active development and lead to an increase in the degree of oil recovery from the subsoil. When selecting and justifying hydrodynamic methods for enhancing oil recovery, the technical capabilities of surface and underground equipment (well design, wellhead equipment, surface equipment, methods of well operation, performance of pumping units, etc.) must be taken into account. Types, volumes of implementation and expected efficiency are justified in technological schemes, projects for the development and additional development of oil fields, as well as in works on current geological and field analysis and cutting. Displacement characteristics can be used to assess the effectiveness of almost all methods of hydrodynamic stimulation of productive formations, with the exception of , possibly, sub-gas 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 of undrained or poorly drained oil reserves in the active development (in dead-end zones, individual layers, 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 current geological and field analysis should be used to determine additional oil reserves introduced into development as a result of changing impact systems, drilling independent wells into individual layers, 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 site, the effect of their introduction into active development may be poorly noticeable on the shape of the displacement characteristic. In these cases, the volumes of oil production obtained from additional balance oil reserves introduced into development must be determined separately and relate entirely to the hydrodynamic impact method. The use of displacement characteristics for individual wells to assess the effectiveness of hydrodynamic methods for increasing 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 stimulation is not recommended. For hydrodynamic stimulation methods that involve the active development of undrained oil reserves, the use of differential displacement characteristics is recommended during the initial period of object development due to the low water cut of the product. To determine the quantitative effectiveness of hydrodynamic methods for increasing current and final oil recovery, displacement characteristics of various types can be used, the main ones of which are the following:

1. (proposed by Nazarov S.N. and Sipachev N.V.)

2. (proposed by G.S. Kambarov et al.)

3. (proposed by A.M. Pirverdyan et al.)

4. (suggested by A.A. Kazakov)

5. (proposed by N.A. Cherepakhin and G.T. Movmyga)

6. (suggested by Sazonov B.F.)

7. (suggested by M.I. Maksimov)

8. (suggested by Garb F.A. and Zimmerman E.H.)

9. (proposed by the French Institute)

10.

13.

14. ,

· - oil, water, liquid production accumulated since the beginning of development, respectively;

· - production of oil, water, liquid by year of development, respectively;

· - coefficients determined by statistical processing of actual data;

· - average annual share of oil in the produced liquid;

· - annual oil production for the first year of the period under review;

· - time, years;

· - balance oil reserves in reservoir conditions;

· - oil recovery factor.

Integral characteristics of species displacement (2), (3), (6), (13) and differential characteristics of species displacement (10), (11), (12) and (14) are the simplest and most convenient for “manual” data processing to determine the effectiveness of hydrodynamic impact. Other types of displacement characteristics during “manual” processing of actual data to quantify the effect of GMPN require much larger amounts of calculations or the use of methods for selecting various quantities and coefficients.

In these cases, “machine” processing of the source 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) to construct the base case and determine the effectiveness of hydrodynamic impact during the period of water-free oil production. It is advisable to determine the coefficients and for these displacement characteristics taking into account the existing coefficient of decline in oil flow rates for the object under consideration before the onset of hydrodynamic impact. In some cases, the coefficient for the displacement characteristic of type (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-technological model) of the reservoir development process is a system of differential equations reflecting the fundamental laws of conservation of mass, momentum, and energy, which today most fully describe the process being studied. 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 a geological and mathematical model of the development object.

5. Safety and environmental friendliness of the project

5.1 Occupational health, safety and fire prevention measures

Petroleum product supply enterprises carry out operations for storing, dispensing and receiving petroleum products, many of which are toxic, evaporate easily, can become electrified, and are fire and explosive. When working at industry enterprises, the following main dangers are possible: the occurrence of a fire and explosion when process equipment or pipelines are depressurized, as well as when the rules for their safe operation and repair are violated; poisoning of workers due to the toxicity of many petroleum products and their vapors, especially leaded gasoline; injury to workers by rotating and moving parts of pumps, compressors and other mechanisms in the event of missing or faulty guards; electric shock in the event of a violation of the insulation of live parts of electrical equipment, faulty grounding, or failure to use personal protective equipment; increased or decreased temperature of the surface of equipment or air in the working area; increased level of vibration; insufficient illumination of the work area; possibility of falling when servicing equipment located at height. When servicing equipment and carrying out its repairs, it is prohibited: the use of open fire to heat oil products, warm fittings, etc.; operation of faulty equipment; operation and repair of equipment, pipelines and fittings in violation of safety regulations, in the presence of leaks of petroleum products through leaks in connections and seals or as a result of metal wear; the use of any levers (crowbars, pipes, etc.) to open and close shut-off valves; repair of electrical equipment not disconnected from the power grid; cleaning equipment and machine parts with flammable flammable liquids; work without appropriate personal protective equipment and protective clothing. When an oil product spill occurs, the spill site should be covered with sand and then removed to a safe place. If necessary, remove soil contaminated with oil products. In areas where a spill occurred, degassing is done with dichloramine (3% solution in water) or bleach in the form of a slurry (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, with the exception of specially designated places (in agreement with the fire department), where the signs “Smoking area” are posted. Entrances to fire hydrants and other water supply sources must always be clear for the unimpeded passage of fire trucks. In winter, it is necessary to: clear snow and ice, sprinkle with sand to prevent slipping: deckings, stairs, passages, sidewalks, pedestrian paths and roads; promptly remove icicles and ice crusts that form on equipment, roofs of buildings, and metal structures.

5.2 Protection of subsoil and environment

At first, people did not think about what intensive oil and gas production entailed. The main thing was to pump them out as much as possible. That's what they did. Very recent echoes of intensive oil development occurred in Tataria, where in April 1989 an earthquake with a magnitude of up to 6 points was recorded (Mendeleevsk). According to local experts, there is a direct relationship between increased pumping of oil from the subsoil and the intensification of small earthquakes. Cases of well bore breakage and column collapse 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, compensating for the extraction of oil. Having begun the exploitation of oil and gas fields, man, without knowing it, let the genie out of the bottle. At first it seemed that oil only brought benefits to people, but it gradually became clear that its use also had a downside. Oil pollution creates a new ecological situation, 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 number and limitation of 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. Light fractions of oil are the most toxic to them. The complex of soil microorganisms, after short-term inhibition, responds to oil pollution by increasing their total number and increasing activity. First of all, this applies to hydrocarbon-oxidizing bacteria, the number of which increases sharply relative to uncontaminated soils. “Specialized” groups are developing, participating at different stages in the utilization of hydrocarbons. The maximum number of microorganisms corresponds to fermentation horizons and decreases in them along the soil profile as hydrocarbon concentrations decrease. The main “explosion” of microbiological activity occurs in the second stage of natural oil degradation. During the process of oil decomposition in soils, the total number of microorganisms approaches background values, but the number of oil-oxidizing bacteria for a long time exceeds the same groups in uncontaminated soils (southern taiga 10 - 20 years). Changes in the environmental 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 inhibition and replacement of some groups by others to the loss of individual groups or the complete death of the entire algal flora. Crude oil and mineral waters especially significantly inhibit the development of algae. The photosynthetic functions of higher plants, in particular cereals, change. Experiments have shown that in the conditions of the southern taiga, with high doses of pollution - more than 20 l/m2, plants cannot develop normally on contaminated soils after a year. Studies have shown that in contaminated soils the activity of most soil enzymes decreases (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 activity of soils slightly increases. Soil respiration also reacts sensitively to oil pollution. One of the most promising ways to protect the environment from pollution is the creation of comprehensive automation of the processes of oil production, transportation and storage. In our country, such a system was first created in the 70s. and applied in the regions of Western Siberia. It was necessary to create a new unified oil production technology. Previously, for example, the fields were not able 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 facilities, and in each oil region they were built differently; 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. Specialists managed, using the energy of the subsoil and deep-well pumps, to ensure the supply of oil from the well to the central oil collection points without intermediate technological operations. The number of fishing facilities has decreased by 12-15 times. Other major oil-producing countries around the globe are also following the path of sealing oil collection, transportation and treatment systems.

Conclusion

The course project examines current problems in the development of oil fields using contour and intra-circuit flooding. Water injected into the reservoir cannot be considered in the form of a virtual fluid 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 displacing agent, replacing oil. In this regard, the issues of the quality of injected water and its compliance with the reservoir properties of the formation are considered from a new perspective. The latter is especially important when developing fields and formations with deteriorated reservoir parameters, which contain significant oil reserves that cannot yet be displaced by commonly used water. The reasons for self-colmatation of porous media, modern requirements for the pressure maintenance system, methods and new technologies for purifying injected water are considered. The feasibility of water purification using cascade technology, which provides maximum effect at minimal cost, is shown.

Bibliography

1. A.A.Gazizov, A.Sh.Gazizov (OJSC "NIIneftepromkhim"), A.I.Nikiforov (Institute of Mechanics and Mechanical Engineering KSC RAS) On one criterion for the efficiency of oil reservoir development by waterflooding

2. A.Kh. Shakhverdiev (JSC “VNIIneft”) Unified methodology for calculating the effectiveness of geological and technical measures

3. V.G.Panteleev, V.P. Rodionov (BashNIPIneft) Dependence of the oil recovery factor on the speed of fluid movement in the pore space of carbonates of the Bashkirian stage

4. V.I.Grayfer, V.D.Lysenko (RITEK JSC) On increasing the efficiency of field development when using chemical reagents

5. E.V. Lozin, E.M. Timashev, R.N. Enikeev, V.M. Sidorovich (BashNIPIneft) Regulation of geological, field, hydrodynamic and geophysical studies to control field development

6. E.N. Safonov, I.A. Iskhakov, K.Kh. Gainullin (ANK Bashneft), E.V. Lozin, R.Kh. Almaev (BashNIPIneft) Effective methods for increasing oil recovery in the fields of Bashkortostan

7. E.S. Makarova, G.G. Sarkisov (Roxar Software Solutions, Moscow) The main stages of three-dimensional hydrodynamic modeling of natural hydrocarbon field development processes

8. Z.M. Khusainov (NGDU Nizhnesortymskneft), R.Kh. Khazipov (NPP Biotsid LLC), A.I. Sheshukov (SurgutNIPIneft) Effective technology for enhanced oil recovery

9. L.N. Vasilyeva, Yu.N. Krasheninnikov, E.V. Lozin (BashNIPIneft) Assessment of the impact of well pattern compaction in pilot areas of the Novokhazinskaya area

10. L.S. Kaplan (Oktyabrsky branch of USPTU) Improving the technology of water injection into the reservoir

11. N.I. Khisamutdinov (NPO Neftegaztekhnologiya) Improving methods for solving engineering problems in oil production for the late stage of development

12. N.I. Khisamutdinov, I.V. Vladimirov (NPO “Neftegaztekhnologiya”), R.S. Nurmukhametov, R.K. Ishkaev (JSC Tatneft) Modeling of fluid filtration in a formation with highly permeable inclusions

13. R.G. Sarvaretdinov R.Kh. Gilmanova, R.S. Khisamov, N.Z. Akhmetov, S.A. Yakovlev (NPO Neftegaztekhnologiya, OJSC Tatneft) Formation of a database for the development of geological and technical measures to optimize oil production

14. Yu.P.Konoplev, B.A.Tyunkin (PechorNIPIneft) New method of thermal mine development of oil fields

15. Yu.Kh. Shiryaev, G.G. Danilenko, N.S. Galitsina (KAMA-NEFT LLC), A.V. Raspopov, T.P. Mikheeva (PermNIPIneft LLC) Increasing the efficiency of field development at the final stage by drilling additional shafts

Waterflooding

oil fields, injection of water into oil reservoirs in order to maintain and restore reservoir pressure (see Bottomhole pressure) and reservoir energy balance. With protection, high rates of oil production and a relatively high degree of oil extraction from the subsoil are ensured, since development takes place under the most efficient water-pressure regime of the formation (oil contained in the pores or cracks of rocks is replaced by water). In most oil regions there are sources of water suitable, after simple treatment, for injection into the reservoir. The efficiency of smelting (including economic) contributed to the widespread introduction of this method in oil production in the USSR (in the late 1960s, about 1/4 of the oil produced). Z. allows you to significantly reduce the number of oil wells and sharply increase their flow rates (daily productivity), which significantly reduces the cost of each ton of oil produced. A water supply system usually consists of water intake structures, tanks, treatment plants, pumping stations, water distribution networks, and injection wells. Water is pumped into oil reservoirs through a system of injection boreholes, usually drilled for this purpose. Depending on the location of the injection wells in relation to the oil deposit and on the relative position of the injection and production (production) wells, types of injection are distinguished: contour, in which all injection wells are located in purely water zones of the formation outside the oil deposit; in-circuit, in which injection wells are located in the area of ​​the oil deposit, and water is pumped into the oil-saturated part of the formation; areal, in which oil and injection wells located on a special grid alternate with each other in a certain way.

In the case of boundary water, development is close in nature to the natural water-pressure regime of the formation with active marginal (contour) waters. Contour protection only intensifies this process, bringing the reservoir feeding area closer to the deposit. For many oil deposits, such intensification is of decisive importance, since only in this case can the deposit be developed in the required time frame with the most effective regime of oil displacement by water. Sometimes they are distinguished by the so-called. near-contour protection, in which injection wells are located on the oil-bearing contour (used in fields where the permeability of the formation behind the contour or on the oil-bearing contour significantly deteriorates). A typical example of boundary mining is the exploitation of the Bavlinskoye deposit in the Tatar Autonomous Soviet Socialist Republic, where this process was completely carried out. As a result, the number of oil wells was reduced fourfold and long-term stable oil production was achieved.

With in-circuit injection, water is pumped directly into an oil reservoir, usually into injection wells located in rows (chains), due to which the reservoir is, as it were, “cut” by water into separate, smaller deposits that can be exploited independently. The number of production wells located in the high-pressure zone in the reservoir (close to injection wells) is increasing, due to which the rate of oil production is sharply increasing and the development time of fields is being reduced. A classic example of in-circuit recovery is the development of the Romashkinskoye Devonian oil field in the Tatar Autonomous Soviet Socialist Republic. The division of the huge deposits by chains of injection wells, carried out since 1954, has made it possible to reduce the period of extraction of the main oil reserves several times. For smaller deposits, longitudinal and transverse intra-circuit protection is used, depending on the direction of the “cutting” rows in relation to the structure.

Areal surveying is the most intensive method, in which the phenomenon of interference of wells (See Interference of wells) of the same purpose is minimized and the flow rate of wells is maximized, all other things being equal. Areal sealing is usually used either from the beginning of development in deposits with very low formation permeability, where other types of sealing are not effective enough, or after the development of a deposit without maintaining reservoir pressure as the so-called. secondary method of oil extraction.

In many oil deposits, combinations of the described types of sealing are used. During the development process, it is often necessary to modify the sealing system to further intensify oil production.

Lit.: Handbook of Oil Production, ed. I. M. Muravyova, vol. 1, M., 1958; Design of oil field development, M., 1962.

Yu. P. Borisov.

Great Soviet Encyclopedia. - M.: Soviet Encyclopedia. 1969-1978 .

Synonyms:

See what “Flooding” is in other dictionaries:

- (a. flooding; n. Fluten, Wasserfluten; f. inondation artificielle, injection d eau; i. inundacion) a method of influencing the formation during oil development. m niy, in which the maintenance and restoration of reservoir pressure and energy balance... ... Geological encyclopedia

A method of maintaining and restoring pressure to displace oil from a reservoir by injecting water. Contour, intra-circuit, areal, etc. waterflooding is used. Waterflooding achieves high rates of fluid withdrawal from formations and increased... ... Big Encyclopedic Dictionary

Noun, number of synonyms: 1 thermal flooding (1) ASIS Dictionary of Synonyms. V.N. Trishin. 2013… Synonym dictionary

flooding- - Topics oil and gas industry EN waterflooding ... Technical Translator's Guide

The most widely used method of influencing a productive formation in order to maintain reservoir pressure and increase final oil recovery is the method of injecting water into the formation (in the industrial literature this method is called waterflooding). 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 the productive formation from the very beginning of oil field development.

In this case, it is possible to prevent a decrease in reservoir pressure due to the withdrawal of fluid from the productive formation, maintain it at the original level, maintain high oil flow rates from wells, intensify field development and ensure high oil recovery factors. As noted, waterflooding is divided into peripheral, peripheral and intracircuit.

With contour flooding (Fig. 24), water is pumped into the reservoir through injection wells drilled beyond the outer oil-bearing contour along the perimeter of the deposit. The distance between injection wells is determined in the technological scheme for the development of a given field. The line of injection wells is distributed approximately 400–800 m from the outer oil-bearing contour in order to create a uniform impact on the deposit, prevent the formation of premature flood tongues and water breakthroughs to production wells.

Contour flooding is usually used in oil fields that are small in size and reserves, in deposits with good reservoir properties, both in terms of formation thickness and area. Under such conditions, edge waterflooding ensures more complete development of reserves, displacing oil to the contracting rows of production wells. The disadvantages of contour flooding include increased consumption of injected water due to partial departure from the injection line; slow response to the deposit due to the distance of the injection line from production wells, etc.

Rice. 24 Contour flooding

A more effective impact on an oil deposit is achieved when injection wells are placed (drilled) inside the oil-bearing contour, in the oil-water zone of the formation, in more permeable areas of the deposit. This type of flooding is called edge flooding.

Perimeter flooding is used:

– on small-sized deposits;

– in case of insufficient hydrodynamic connection of the productive formation with the external region;

– in order to intensify the oil production process

A more effective system for influencing oil deposits, which allows for a faster increase in oil production, a reduction in reserves depletion time and an increase in final oil recovery, is in-circuit waterflooding (Fig. 25).

With intra-circuit flooding, injection wells are located (drilled) inside the oil-bearing contour. The choice of layout and grid of injection wells is determined by specific geological conditions, physical and chemical properties of oil, etc.

Rice. 25 In-circuit flooding

In recent years, to intensify the development of oil fields, a widespread method has become the method of artificially “cutting” the deposit into separate areas or blocks by pumping water into rows of injection wells located along the intended cutting lines inside the natural oil-bearing contour. In this case, artificial supply circuits are created close to the production wells, and each area is developed independently. In the initial period, during intra-circuit flooding, water is injected into the oil deposit. Further, in the process of injecting water into the deposits, a water shaft is formed along the line of injection wells, dividing the deposit into parts. To more quickly master the process of in-circuit waterflooding, 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 withdrawal.

As water flows, these wells are developed and converted into injection wells. For the first time in our country, in-line waterflooding was carried out at the largest oil field in Tatarstan - the Romashkinskoye field, which was cut by rows of injection wells into 26 separate production areas.

In-line waterflooding makes it possible to increase the rate of oil extraction 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-circuit central flooding.

Currently, several in-circuit flooding systems are used, which differ from each other in the location of injection wells, the sequence of their commissioning, the rate of water injection into the formation, as well as oil extraction from oil producing wells.

For intracircuit flooding, focal flooding is also used. Focal waterflooding is used in cases where in certain areas of the reservoir there is no influence from waterflooding, as a result of which reservoir pressure drops in this area and, accordingly, oil flow rates in production wells fall. In focal flooding, an oil-producing well is selected in the center of the site, transferred to an injection well, and water injection begins, resulting in the effect of injected water on the surrounding oil-producing wells.

A selective in-circuit flooding system is also used. The most intensive system of impact on the formation is considered to be areal flooding. With this system, production and injection wells 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 final oil recovery, gas or air is injected into the productive formation, and water and gas are also 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 an analysis of the development of the Zhuravlevsko-Stepanovskoye field in the Orenburg region, a method of alternately injecting water and gas into an oil reservoir was justified 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. Gas, when injected into the productive formation, penetrates, first of all, into highly permeable interlayers, reduces their phase permeability to water, as a result of which, with the subsequent injection of water into the productive formation, the displacement front is leveled.

neniya and thereby increases the coverage of the formation by the influence. 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 entrainment displacement of gas. The method of alternately injecting water and gas into the formation is a variant of pulsed stimulation of the formation, since in this case more favorable conditions are created for the manifestation of capillary forces due to a doubling of the surface tension of water at the interface with oil. Partial dissolution of gas in oil, reducing its viscosity, also helps to increase the efficiency of the process of replacing oil with water. In the conditions of a fractured reservoir, these processes will proceed more efficiently, since gas solubility and gravitational redistribution of the displacing agent in oil are enhanced: solubility due to an increase in the contact surface, and gravitational redistribution due to free flows in open cracks. Gravitational redistribution of oil and injected gas along the thickness of the reservoir creates a condition that prevents advanced watering of the reservoir along the base 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 problems of protecting the environment and subsoil. Pilot work using 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 work, 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 hampered by the lack of small-sized, high-pressure and high-performance compressors.

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

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

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

Figure 2.5 Basic schemes of area flooding.

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

1 - production wells; 2 - injection wells.

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

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

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

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

Injecting water into an oil reservoir is the most popular method of developing oil fields. This method makes it possible to maintain high current flow rates of oil wells, and ultimately achieve a high percentage of recovery of recoverable oil reserves.

The main purpose of water injection into the reservoir is to effectively displace oil to production wells and increase the economic efficiency of field development by increasing the oil recovery factor from the reservoir.

The popularity of this method of developing oil deposits is explained by:

• Public availability of water
• The relative simplicity of the injection process due to the presence of hydraulic pressure of the liquid column in the well
• The ability of water to spread through oil-saturated formations
• High oil recovery when displacing oil

Waterflooding provides a high oil recovery rate due to two factors:

• Maintaining reservoir pressure at a level effective for field development
• Physical replacement of oil with water in the pores of the reservoir

Varieties of the flooding method include the injection of solvents, suspensions, and various reagents. In some cases, water is thickened by adding polymers and micellar solutions to it. But all these methods already belong to the so-called enhanced oil recovery (EOR) methods or tertiary methods of oil field development.

In what cases does it make sense to use the waterflooding method and organize a reservoir pressure maintenance (RPM) system at the field?

To answer this question, let's remember what natural operating modes of deposits exist. And we will consider the feasibility of organizing waterflooding in certain geological conditions.

Water pressure mode

How it works:

• Aquifer (aquifer) maintains reservoir pressure
• Liquid withdrawals are equal to the volumes of water inflow from the aquifer
• Oil is displaced vertically due to good water pressure. In this case, a uniform rise of the oil-water contact (OWC) occurs.

Possible problems:

• Reservoir heterogeneity may limit the ability of the aquifer to displace oil in some areas of the reservoir

Oil recovery factor:

High with skillful management of reservoir development (60-70%)

High-pressure, powerful aquifer can provide enough energy to displace oil

A weak aquifer requires support of reservoir pressure by water injection. In this case:

• It is possible to organize contour (near-contour) flooding
• In some cases, area flooding is possible

Dissolved gas mode

How it works

• Oil with a lot of dissolved gas is under high pressure
• If the reservoir pressure is higher than the saturation pressure, the expansion of the rock and the fluids saturating it provides energy to displace oil
• If the reservoir pressure is below the saturation pressure, then oil displacement occurs due to the release and expansion of gas

Possible problems

• When reservoir pressure is below saturation pressure, very high gas mobility becomes a problem
• Gas comes out bypassing oil
• High gas content in well production
• A sharp decrease in reservoir pressure

Oil recovery factor

Very low (10-30%)

Does waterflooding make sense?

Good candidate for waterflooding

Waterflooding is best carried out at reservoir pressure close to saturation pressure, so that gas release from oil is below the critical level

Gravity mode

How it works

• The extraction process occurs due to gravity and the difference in densities of fluids saturating the rock
• To implement the regime, the formation must be thick with high vertical permeability, or the strike of the formation must be with a large slope

Possible problems

• The slow process of oil migration determines low recovery rates
• Gas must move to the top of the reservoir to compensate for flowing oil
• The reservoir may contain heavy oil

Oil recovery factor

Very high (50-70%)

Does waterflooding make sense?

May be a good candidate for waterflooding, taking into account the low rates of natural withdrawals

Gas cap regime

How it works

• There is a large volume of compressed gas, which under the influence of gravity forms a so-called gas cap
• Expanding gas displaces oil

Possible problems

• Oil penetrating into the gas cap causes irreparable losses for production
• Gas coning and high gas/oil ratios limit oil production opportunities

Oil recovery factor

Does waterflooding make sense?

Not a suitable candidate for waterflooding

Evaluating the effectiveness of the waterflooding method

The economic efficiency of the waterflooding method depends on the increase in the oil recovery factor.

The costs of pumping water, constructing injection wells, and special water treatment facilities should be less than the income from the sale of additionally produced oil.