Hydraulic fracturing is a mechanical method of influencing a productive formation, consisting in the fact that the rock is torn along planes of minimum strength under the influence of excess pressure created by pumping fracturing fluid into the well at a flow rate that the well does not have time to absorb. The fluids through which the energy required for fracturing is transferred from the surface to the bottom of the well are called fracturing fluids. After rupture, under the influence of fluid pressure, the fracture enlarges, and its connection arises with a system of natural fractures not penetrated by the well, and with zones of increased permeability. Thus, the area of ​​the formation drained by the well expands. Granular material (proppant) is transported into the cracks formed by fracturing fluids, which secures the cracks in the open state after the excess pressure is removed.

As a result of hydraulic fracturing, the flow rate of production or injectivity of injection wells is multiplied by reducing hydraulic resistance in the bottom-hole zone and increasing the filtration surface of the well, and the final oil recovery is also increased by introducing poorly drained zones and interlayers into production.

The hydraulic fracturing method has many technological solutions, determined by the characteristics of a particular treatment object and the achieved goal. Hydraulic fracturing technologies differ, first of all, in the volume of injection of process fluids and proppants and, accordingly, in the size of the created cracks.

Local hydraulic fracturing has become the most widespread as an effective means of influencing the bottomhole zone of wells. In this case, it is sufficient to create fractures 10-20 m long with the injection of tens of cubic meters of liquid and several tons of proppant. In this case, the well production increases by 2-3 times.

In recent years, technologies for creating highly conductive fractures of relatively short length in medium- and high-permeability formations have been intensively developed, which makes it possible to reduce the resistance of the bottomhole zone and increase the effective radius of the well.

Carrying out hydraulic fracturing with the formation of extended cracks leads to an increase not only in the permeability of the bottom-hole zone, but also in the coverage of the formation by the influence, the involvement of additional oil reserves in the development and an increase in oil recovery in general. At the same time, it is possible to reduce the current water cut of the produced products. The optimal length of a fixed fracture with a formation permeability of 0.01-0.05 μm 2 is usually 40-60 m, and the injection volume is from tens to hundreds of cubic meters of liquid and from units to tens of tons of proppant.

Along with this, selective hydraulic fracturing is used, which makes it possible to involve low-permeable layers into development and increase the productivity.

Massive hydraulic fracturing technology is successfully used in the USA, Canada and a number of Western European countries to involve gas reservoirs with ultra-low permeability (less than 10 -4 µm2) into the industrial development. At the same time, cracks with a length of 1000 m or more are created with the injection of hundreds to thousands of cubic meters of liquid and from hundreds to thousands of tons of proppant.

The technology for using hydraulic fracturing is primarily based on knowledge of the mechanism of occurrence and propagation of cracks in rocks, which makes it possible to predict the geometry of the crack and optimize its parameters. Mathematical modeling of the crack formation process is based on the fundamental laws of the theory of elasticity, physics of oil and gas bearing formations, filtration, and thermodynamics. The first theoretical model of two-dimensional crack propagation, which received universal recognition, was proposed by S.A. Khristianovich, Yu.P. Zheltov and G.I. Barenblatt (model I). Somewhat later T.K. Perkins, L.R. Kern proposed a second model (Model II). These two main two-dimensional theoretical models of hydraulic fracture propagation differ in the physical formulation of the problems (Fig. 1.1). In both models, the height of the vertical crack is constant, but in Model I the vertical cross-section of the crack is a rectangle, and in Model II it is an ellipse. The horizontal section of a vertical crack in model I is an ellipse with sharp points at the ends of the crack, and in model II it is an ellipse. Vertical longitudinal sections of cracks in both models are rectangles. The vertical cross-section of a horizontal circular hydraulic fracture in model II is elliptical, and in model I it is elliptical with cusps at opposite ends. Both models are based on the linear theory of cracks in an elastic body. Differences in models lead to differences in the behavior of fracture pressure and other parameters of the hydraulic fracturing process. The areas of application for each of these models are indicated in R.P. Nordgren: Model I describes the propagation of a vertical crack in the horizontal plane, and Model II describes its growth in the vertical direction. At the early stage of crack propagation, when its length is much less than its height, model I is applicable; at a late stage, when the length of the crack significantly exceeds the height, model II is applicable. Currently, in oil field practice, pseudo-three-dimensional models have become widespread, which are a combination of two well-known two-dimensional models that describe the growth of a crack and the flow of fluid in it in two mutually perpendicular directions. Research on the mechanism of crack formation during hydraulic fracturing and mathematical modeling of this process is discussed in reviews by V.A. Reutova, M.J. Economides, K.G. Nolte, J.L. Gidley, S.A. Holditch, D.E. Nierode, R.W. Veatch, N.R. Warpinski, Z.A. Moschovidis, C.D. Parker,I. S. Abou-Sayed. This paper studies the influence of hydraulic fracturing on filtration processes in the reservoir and on the efficiency of development of oil and gas fields.

Model I Model II

Rice. 1.1. Vertical crack propagation models

The possibility of vertical or horizontal crack formation depends on the distribution of tectonic stresses. At shallow depths, the vertical stress may be significantly less than the horizontal effective stress, which favors the formation of a horizontal crack. It is believed that under normal conditions, horizontal cracks form at depths of up to 200 m, and vertical cracks form at depths above 400 m. At intermediate depths, where the principal stresses are approximately equal, the orientation of the cracks is determined by other factors, such as anisotropy. Since oil and gas reservoirs currently being developed are mostly confined to significant depths, most theoretical studies consider vertical fractures.

1.2. FOREIGN EXPERIENCE IN USING HYDRAULIC FRACTURING

For the first time in oil practice, hydraulic fracturing was performed in 1947 in the USA. Technology and theoretical concepts

Research on the hydraulic fracturing process was described in the work of J.B. Clark in 1949, after which this technology quickly became widespread. By the end of 1955, more than one hundred thousand hydraulic fracturing operations had been carried out in the United States. As theoretical knowledge of the process has improved and the technical characteristics of equipment, fracturing fluids and proppant materials have improved, the success rate of fracturing operations has reached 90%. By 1968, more than a million operations had been performed worldwide. In the United States, the peak number of hydraulic fracturing operations was carried out in 1955 and amounted to 4,500 hydraulic fracturing operations per month; by 1972, this number decreased to 1,000 hydraulic fracturing operations per month and by 1990 stabilized at 1,500 operations per month.

The technology for using hydraulic fracturing is primarily based on knowledge of the mechanism of initiation and propagation of cracks, which makes it possible to predict the geometry of the crack and optimize its parameters. The first fairly simple models that determined the relationship between fracturing fluid pressure, plastic deformation of the rock and the resulting length and opening of the fracture met the needs of practice until hydraulic fracturing operations did not require large investments. The introduction of deep-penetrating and massive hydraulic fracturing, which requires high consumption of fracturing fluids and proppant, has led to the need to create more advanced two- and three-dimensional models of fracturing, allowing more reliable prediction of treatment results.

The most important factor in the success of a hydraulic fracturing procedure is the quality of the fracturing fluid and proppant. The main purpose of the fracturing fluid is to transfer from the surface to the bottom of the well the energy necessary to open the fracture, and to transport the proppant along the entire fracture. The main characteristics of the “fracturing fluid - proppant” system are:

rheological properties of “pure” and proppant-containing fluid;

infiltration properties of the fluid, which determine its leakage into the formation during hydraulic fracturing and when proppant is transferred along the fracture;

the ability of the fluid to ensure the transfer of proppant to the ends of the fracture in suspension without its premature deposition;

the ability to easily and quickly remove fracturing fluid to ensure minimal contamination of the proppant pack and the surrounding formation;

compatibility of fracturing fluid with various additives provided by the technology, possible impurities and formation fluids;

physical properties of proppant.

Hydraulic fracturing fluids must have sufficient dynamic viscosity to create high-conductivity fractures due to their large opening and effective filling with proppant; have low filtration leaks to obtain cracks of the required sizes with minimal fluid consumption; be compatible with formation rocks and fluids; ensure a minimal reduction in the permeability of the formation zone in contact with the fracturing fluid; ensure low pressure losses due to friction in pipes; have sufficient thermal stability for the treated formation; have high shear stability, i.e. stability of the fluid structure under shear; easy to remove from the formation and hydraulic fractures after treatment; be technologically advanced in preparation and storage under field conditions; have low corrosiveness; be environmentally friendly and safe to use; have a relatively low cost.

The first fracturing fluids were petroleum-based, but since the late 50s. began to use water-based liquids, the most common of which are guar gum and hydroxypropyl guar. Currently, in the United States, more than 70% of all hydraulic fracturing is performed using these fluids. Petroleum-based gels are used in 5% of cases, foams with compressed gas (usually CO 2 and N 2) are used in 25% of all hydraulic fracturing operations. To increase the efficiency of hydraulic fracturing, various additives are added to the fracturing fluid, mainly anti-filtration agents and friction reducing agents.

Failures in hydraulic fracturing in low-permeability gas formations are often due to the slow removal of the fracturing fluid and its blocking of the fracture. As a result, the initial gas flow rate after hydraulic fracturing may be 80% lower than that established over time, since the increase in well productivity occurs extremely slowly as the fracture is cleaned - over weeks and months. In such formations, it is especially important to use a mixture of hydrocarbon fracturing fluid and liquefied carbon dioxide or liquefied CO 2 with the addition of nitrogen. Carbon dioxide is introduced into the formation in a liquefied state and removed as a gas. This makes it possible to accelerate the removal of fracturing fluid from the formation and prevent such negative effects, most pronounced in low-permeability gas reservoirs, as blocking of the fracture by the fracturing fluid, deterioration of the phase permeability for gas near the fracture, changes in capillary pressure and wettability of the rock. The low viscosity of such fracturing fluids is compensated for by a higher injection rate during hydraulic fracturing operations.

Modern materials used to secure cracks in the open state - proppants - are classified as follows: quartz sands and synthetic proppants of medium and high strength. The physical characteristics of proppants that affect fracture conductivity include parameters such as strength, granule size and particle size distribution, quality (presence of impurities, acid solubility), granule shape (sphericity and roundness) and density.

The main and most widely used material for fixing cracks is sand. Its density is approximately 2.65 g/cm2. Sands are usually used in hydraulic fracturing of formations in which the compressive stress does not exceed 40 MPa. Medium-strength ceramic proppants with a density of 2.7-3.3 g/cm 2 are used at compression stresses of up to 69 MPa. Ultra-strong proppants such as sintered bauxite and zirconium oxide are used at compressive stresses of up to 100 MPa, the density of these materials is 3.2-3.8 g/cm 2 . The use of heavy-duty proppants is limited by their high cost.

In addition, in the USA, the so-called supersand is used - quartz sand, the grains of which are coated with special resins that increase strength and prevent the removal of crumbled proppant particles from the fracture. The density of supersand is 2.55 g/cm2. Synthetic resin-coated proppants are also produced and used.

Strength is the main criterion when selecting proppants for specific reservoir conditions in order to ensure long-term conductivity of the fracture at the formation depth. In deep wells, the minimum stress is horizontal, so predominantly vertical cracks form. With depth, the minimum horizontal stress increases by approximately 19 MPa/km. Therefore, the following types of proppants are used for different depths: quartz sands

Up to 2500 m; medium strength proppants - up to 3500 m; High-strength proppant - over 3500 m.

Research in recent years conducted in the USA has shown that the use of medium-strength proppants is cost-effective even at depths of less than 2500 m, since the increased costs due to their higher cost compared to quartz sand are offset by the gain in additional oil production due to the creation of hydraulic fracturing of proppant packaging with higher conductivity.

The most commonly used proppants are with granule sizes of 0.85-0.425 mm (20/40 mesh), less often 1.7-0.85 mm (12/20 mesh), 1.18

0.85 mm (16/20 mesh), 0.425-0.212 mm (40/70 mesh). The choice of the required proppant grain size is determined by a whole range of factors. The larger the granules, the greater the permeability of the proppant pack in the fracture. However, the use of coarse proppant is associated with additional problems during its transfer along the fracture. The strength of the proppant decreases with increasing granule size. In addition, in weakly cemented reservoirs it is preferable to use proppant of a finer fraction, since due to the removal of fine particles from the formation, the package of coarse-grained proppant gradually becomes clogged and its permeability decreases.

The roundness and sphericity of proppant granules determines the density of its packing in a fracture, its filtration resistance, as well as the degree of destruction of granules under the influence of rock pressure. Proppant density determines proppant transport and location along the fracture. High density labor-density proppants

it is maintained in suspension in the fracturing fluid while being transported along the fracture. Filling a fracture with high-density proppant can be achieved in two ways: using high-viscosity fluids that

transport proppant along the length of the fracture with minimal sedimentation, or using low-viscosity fluids at an increased rate of injection. In recent years, foreign companies have begun to produce lightweight proppants characterized by reduced density.

Due to the wide variety of fracturing fluids and proppants available on the American market, the American Petroleum Institute (API) has developed standard procedures for determining the properties of these materials (API RP39; Prud'homme, 1984, 1985, 1986 - for fracturing fluids and API RP60 - for proppants ) .

Currently, the United States has accumulated vast experience in hydraulic fracturing. At the same time, increasing attention is paid to the preparation of each operation. The most important element of such preparation

Collection and analysis of primary information. The data required for the preparation of hydraulic fracturing can be divided into three groups:

geological and physical properties of the formation (permeability, porosity, saturation, formation pressure, position of gas-oil and water-oil contacts, rock petrography);

characteristics of the geometry and orientation of the crack (minimum horizontal stress, Young's modulus, Poisson's ratio, rock compressibility, etc.);

properties of fracturing fluid and proppant.

The main sources of information are data from geological, geophysical and petrophysical studies, laboratory core analysis, as well as field experiments consisting of micro- and mini-hydraulic fracturing.

In recent years, a technology has been developed for an integrated approach to hydraulic fracturing design, which is based on taking into account many factors, such as reservoir conductivity, well placement system, fracture mechanics, characteristics of fracturing fluid and proppant, technological and economic limitations. In general, the hydraulic fracturing optimization procedure should include the following elements:

calculation of the amount of fracturing fluid and proppant required to create a fracture of the required size and conductivity;

technology to determine optimal injection parameters taking into account proppant characteristics and process limitations;

a complex algorithm that allows you to optimize the geometric parameters and conductivity of a fracture, taking into account the productivity of the formation and the well placement system, ensuring a balance between the filtration characteristics of the formation and the fracture and based on the criterion of maximizing profit from well treatment.

Creating an optimal hydraulic fracturing technology implies compliance with the following criteria:

ensuring optimization of the production of field reserves; maximizing the depth of proppant penetration into the fracture; optimization of fracturing fluid and proppant injection parameters;

minimizing processing costs;

maximizing profits by obtaining additional oil and gas.

In accordance with these criteria, the following stages of optimization of hydraulic fracturing at the site can be distinguished:

1. Selection of wells for treatment, taking into account the existing or designed development system, ensuring maximization of oil and gas production while minimizing costs.

2. Determination of the optimal fracture geometry - length and conductivity - taking into account the permeability of the formation, the well placement system, and the distance of the well from the gas or oil-water contact.

3. Selection of a crack propagation model based on an analysis of the mechanical properties of the rock, stress distribution in the formation and preliminary experiments.

4. Selection of proppant with appropriate strength properties, calculation of the volume and concentration of proppant required to obtain a fracture with the specified properties.

5. Selection of fracturing fluid with suitable rheological properties taking into account the characteristics of the formation, proppant and fracture geometry.

6. Calculation of the required amount of fracturing fluid and determination of optimal injection parameters taking into account the characteristics of the fluid and proppant, as well as technological limitations.

7. Calculation of economic efficiency of hydraulic fracturing.

Through the joint efforts of the American Gas Research Institute (GRI) and the largest oil and gas companies in the United States (Mobil Oil Co., Amoco Production Co., Schlumberger, etc.), a new technological complex has been developed, including GRI mobile equipment for testing and quality control of hydraulic fracturing operations , a GRI rheology unit, a 3D fracture design computer program FRACPRO, formation stress profiling instruments and microseismic technology to determine fracture height and azimuth. The use of new technology allows you to select the fracturing fluid and proppant that best suit specific conditions, and control the propagation and opening of the fracture, the transportation of the proppant in suspension along the entire fracture, and the successful completion of the operation. Knowledge of the stress profile in the formation allows not only to determine the hydraulic fracturing pressure, but also to predict the geometry of the fracture. When there is a high difference in stress in the reservoir and in impermeable barriers, the crack propagates to a greater length and lower height than in a formation with an insignificant difference in these stresses. Taking into account all the information in a three-dimensional model allows you to quickly and reliably predict the geometry and filtration characteristics of a crack. Testing of the new hydraulic fracturing technology in six gas fields in Texas, Wyoming and Colorado showed its high efficiency for low-permeability reservoirs.

In some cases, hydraulic fracturing occurs at significantly lower pressures than the initial stresses in the formation. Cooling of the formation as a result of pumping cold water into injection wells, which is significantly different in temperature from the reservoir, leads to a decrease in elastic stresses and hydraulic fracturing in injection wells at bottomhole pressures used in waterflooding. Studies conducted at the Prudhoe Bay field (USA) showed that the half-length of the cracks that appeared in this way was 6-60 m. It is now generally accepted that in injection wells, when there is a large contrast in the temperatures of the formation and the injected water, hydraulic fracturing occurs.

When carrying out hydraulic fracturing in inclined wells, the direction of which deviates from the fracture plane, problems arise associated with the formation of several cracks from different perforation intervals and with the curvature of the crack near the well. To create a single flat crack in such wells, a special technology is used, based on limiting the number of perforations, determining their size, number and orientation in relation to the directions of the main stresses in the formation.

In recent years, technologies for using hydraulic fracturing in horizontal wells have been developed. The orientation of the fracture relative to the well axis is determined by the direction of the horizontal wellbore relative to the azimuth of the minimum principal stress in the formation. If the horizontal wellbore is parallel to the direction of the minimum principal stress, then transverse cracks are formed during hydraulic fracturing. Technologies have been developed to create several fractures in one horizontal well. In this case, the number of cracks is determined taking into account technological and economic limitations and is usually 3-4. The first field experiment to create multiple fractures in an inclined well was conducted by Mobil in the 60s. . Hydraulic fracturing in oil horizontal wells has been carried out in fields in the Danish part of the North Sea. In a gas field in the North Sea (Netherlands), two transverse fractures were created in a formation with a permeability of 0.001 µm 2 in a horizontal well. The largest project was carried out at the Solingen gas field in the North Sea (Germany), characterized by ultra-low permeability (10 -6 -10 -4 μm2), average porosity of 0.1-0.12 and average formation thickness of about 100 m. In a horizontal wellbore length Four transverse fractures were created at 600 m, the half-length of each of them being about 100 m. The peak flow rate of the well was 700 thousand m 3 /day, currently the well is operating with an average flow rate of 500 thousand m 3 / day. If the horizontal section of the well is parallel to the direction of the maximum horizontal stress, then the hydraulic fracture will be longitudinal with respect to the axis of the well. A longitudinal fracture may not provide a significant increase in the productivity of a horizontal well, but a horizontal well intersected by a longitudinal fracture can be considered a very high conductivity fracture. Considering that an increase in conductivity is a determining factor in increasing well productivity due to hydraulic fracturing in medium- and high-permeable formations, when developing such formations it is possible to use hydraulic fracturing in horizontal wells with the formation of longitudinal fractures. Experimental work to determine the effectiveness of longitudinal fractures, carried out in the Kuparuk River field (Alaska) on four horizontal wells, showed that productivity increased on average by 71%, and costs by 37%. In all cases, the choice between designing vertical wells with hydraulic fracturing, horizontal wells or horizontal wells with hydraulic fracturing is made based on an assessment of the economic efficiency of a particular technology.

Pulse hydraulic fracturing technology makes it possible to create several fractures in a well, radially diverging from the wellbore, which can be effectively used to overcome the skin effect in the near-wellbore zone, especially in medium- and high-permeable formations.

Hydraulic fracturing of medium- and high-permeability formations is one of the most intensively developing methods for stimulating wells at present. In high-permeability formations, the main factor in increasing well productivity due to hydraulic fracturing is the width of the fracture, in contrast to low-permeability formations, where such a factor is its length. To create short wide cracks, the technology of proppant deposition at the end of the crack (TSO-tip-screen-out) is used, which consists of pushing the proppant primarily to the end of the crack by gradually increasing its concentration in the working fluid during treatment. The deposition of proppant at the end of the fracture prevents its growth in length. Further injection of proppant-carrying fluid leads to an increase in the width of the fracture, which reaches 2.5 cm, whereas with conventional hydraulic fracturing the fracture width is 2-3 mm.

As a result, the effective fracture conductivity (the product of permeability and width) is 300-3000 µm 2 mm. To prevent proppant carryover during subsequent well production, TSO technology is typically combined with either a resin-coated proppant, which sets and resists viscous friction during production, or a gravel pack, where the proppant is retained in the fracture using a Frac-and-Pack. . The same technology is used to prevent crack propagation towards the oil-water contact. TSO technology is successfully used in the Prudhoe Bay field (USA), in the Gulf of Mexico, Indonesia, and the North Sea. Creating short, wide fractures in wells that penetrate medium- and high-permeability formations gives good results with a significant deterioration in reservoir properties in the near-wellbore zone as a means of increasing the effective radius of the well; in multilayer sand reservoirs, where a vertical fracture provides a continuous connection of thin sand layers with the perforation zone; in reservoirs with migration of small particles, where sand removal is prevented by reducing the flow velocity near the wellbore; in gas formations to reduce the negative effects associated with turbulence of flow near the well.

To date, more than one million successful hydraulic fracturing operations have been carried out in the United States, more than 40% of the well stock has been processed, as a result of which 30% of oil and gas reserves have been transferred from off-balance sheet to commercial. In North America, the increase in oil production as a result of hydraulic fracturing was about 1.5

At the end of the 70s. With the creation of new durable synthetic proppants, there has been a rise in the use of hydraulic fracturing in gas and oil fields of Western Europe, confined to dense sandstones and limestones located at great depths. By the first half of the 80s. coincided with the second peak period in hydraulic fracturing operations in the world, when the number of treatments per month reached 4800 and was aimed mainly at tight gas reservoirs. In Europe, the main regions where massive hydraulic fracturing has been and is being carried out are concentrated in the fields of Germany, the Netherlands and Great Britain in the North Sea and on the coast in Germany, the Netherlands and Yugoslavia. Local hydraulic fracturing is also carried out in the Norwegian fields of the North Sea, in France, Italy, Austria and in Eastern Europe.

The largest works on carrying out massive hydraulic fracturing were undertaken in Germany in gas-bearing formations located at a depth of 3000-6000 m at a temperature of 120-180 ° C. Mainly medium- and high-strength artificial proppants were used. In the period 1976-1985. Several dozen massive hydraulic fracturing operations were carried out in Germany. The proppant consumption in this case was in most cases 100 t/sq, in a third of cases - 200 t/sq, and during the largest operations it reached 400-650 t/sq. The length of the cracks varied from 100 to 550 m, the height - from 10 to 115 m. In most cases, the operations were successful and led to an increase in flow rate by 3-10 times. Failures during individual hydraulic fracturing operations were mainly due to high water content in the formation.

The strengthening of hydraulic fractures in oil-containing formations, in contrast to gas-containing ones, was carried out mainly using sand, since the depth of these formations is only 700-2500 m, only in some cases medium-strength proppants were used. In the oil fields of Germany and the Netherlands, the proppant consumption was 20-70 t/well, and in the Vienna Basin of Austria, the optimal proppant consumption was only 6-12 t/well. Both old and new production wells were successfully treated with good isolation of adjacent intervals.

The UK's gas fields in the North Sea provide about 90% of the country's gas needs. Proppant consumption during hydraulic fracturing in gas-bearing sandstones located at a depth of 2700-3000 m was 100-250 t/well. Moreover, if at first the cracks were fixed either with sand or with medium- or high-strength synthetic proppant, then from the beginning of the 80s. The technology of sequential injection of proppants into a fracture, differing both in fractional composition and other properties, has become widespread. According to this technology, 100-200 tons of sand with a grain size of 20/40 mesh were first pumped into the crack, then 25-75 tons of medium-strength proppant with a grain size of 20/40 or 16/20. In some cases, the three-fraction method was successfully used with sequential injection of proppants 20/40, 16/20 and 12/20 or 40/60, 20/40 and 12/20.

The most common version of two-fraction hydraulic fracturing consisted of injecting the main volume of sand or medium-strength proppant of the 20/40 type, followed by the injection of medium-to-high-strength proppant of the 16/20 or 12/20 type in an amount of 10-40% of the total volume. There are various modifications of this technology, in particular, good results are obtained by initially pumping fine-grained sand of the 40/70 or even 100 mesh type into the fracture, then the main amount of sand or proppant of the 20/40 type and completing the fracture with durable coarse-grained proppant 16/20 or 12/20 . The advantages of this technology are as follows:

fixing the fracture with high-strength proppant in the vicinity of the well, where the compressive stress is highest;

reduction in the cost of the operation, since ceramic proppant is 2-4 times more expensive than sand;

creating the highest fracture conductivity in the vicinity of the bottom, where the fluid filtration rate is maximum;

prevention of proppant carry-over into the well, ensured by special selection of the difference in grain sizes of the main and fracture-ending proppant, in which smaller grains are retained at the boundary between the proppants;

blocking with fine-grained sand the end of the crack and natural microcracks branching from the main one, which reduces the loss of fracturing fluid and improves the conductivity of the crack.

Proppants injected into different areas of the fracture can differ not only in fractional composition, but also in density. In Yugoslavia, massive hydraulic fracturing technology has been used, when first a light medium-strength proppant is pumped into a fracture, and then a heavy, higher-quality high-strength proppant.

Light proppant is maintained in suspension longer in the fluid transporting it, so it can be delivered to a longer distance along the fracture flaps. Injecting heavier, high-quality proppant at the final stage of hydraulic fracturing allows, on the one hand, to provide compression resistance in the area of ​​the highest stresses near the bottom, and, on the other hand, reduces the risk of failure of the operation at the final stage, since the light proppant has already been delivered to the fracture. The massive hydraulic fracturing carried out in Yugoslavia is one of the largest in Europe, since at the first stage 100-200 tons of light proppant were pumped into the fracture, and at the second stage 200-450 tons of heavier proppant. Thus, the total amount of proppant was 300-650 tons.

As a result of the oil crisis of 1986, the volume of hydraulic fracturing work decreased significantly, but after stabilization of oil prices in 1987-1990. An increasing number of fields are being targeted for hydraulic fracturing, and increased attention has been paid to the optimization of hydraulic fracturing technology and the effective selection of fracture and proppant parameters. The highest activity in carrying out and planning hydraulic fracturing in Western Europe is observed in the North Sea: in the British gas fields and oil-bearing chalk deposits in the Norwegian sector.

The importance of hydraulic fracturing technology for the fields of Western Europe is proven by the fact that the extraction of a third of the gas reserves here is possible and economically justified only with hydraulic fracturing. For comparison, in the United States, 30-35% of hydrocarbon reserves can only be recovered using hydraulic fracturing.

The specifics of the development of offshore fields determine the higher cost of operations to stimulate wells, therefore, to ensure higher reliability in 1989-1990. It was decided to completely abandon the use of sand as a proppant material in British fields in the North Sea.

Sand has been used especially for a long time and widely as a proppant material in Yugoslavia, Turkey, countries of Eastern Europe and b. The USSR, which had its own equipment for hydraulic fracturing, but did not have sufficient capacity for the production of expensive synthetic proppants. Thus, in Yugoslavia and Turkey, medium-strength proppant was used only to complete the fracture, and the main volume was filled with sand. However, in recent years, due to the creation of joint ventures, the expansion of sales of proppants by Western manufacturing companies to direct consumers, and the development of their own production, the situation is changing. In China, hydraulic fracturing is carried out with the injection of domestically produced bauxite proppant in a volume of up to 120 tons. It has been shown that even a low concentration of bauxite provides better fracture conductivity than a higher concentration of sand. There are broad prospects for the use of hydraulic fracturing technology in the fields of North Africa, India, Pakistan, Brazil, Argentina, Venezuela, and Peru. In the fields of the Middle East and Venezuela, confined to carbonate reservoirs, the main technology should be acid fracturing.

1.3. APPLICATION OF HYDRAULIC FRACTURING AT ROSS II SKIKH DEPOSITS

In domestic oil production, hydraulic fracturing began to be used in 1952. The total number of hydraulic fracturing in b. USSR during the peak period 1958-1962. exceeded 1,500 operations per year, and in 1959 reached 3,000 operations, which had high technical and economic indicators. Theoretical and field experimental studies to study the mechanism of hydraulic fracturing and its effect on well productivity date back to the same time. In the subsequent period, the number of hydraulic fracturing operations performed decreased and stabilized at approximately 100 operations per year. The main centers for hydraulic fracturing were concentrated on the fields of the Krasnodar Territory, Volga-Urals, Tataria (Romashkinskoye and Tuymazinskoye fields), Bashkortostan, Kuibyshev and Grozny regions, Turkmenistan, Azerbaijan, Dagestan, Ukraine and Siberia. Hydraulic fracturing was carried out mainly for the development of injection wells during the introduction of in-line waterflooding and, in some cases, in oil wells. In addition, hydraulic fracturing has been used to isolate groundwater inflows in wells with monolithic formations; in this case, a horizontal hydraulic fracture created in a pre-selected interval was used as a waterproofing screen. Massive hydraulic fracturing in b. The USSR was not carried out. With the equipping of fields with more powerful equipment for water injection, the need for widespread hydraulic fracturing in injection wells disappeared, and after the large high-yield fields of Western Siberia were put into development, interest in hydraulic fracturing in the industry practically disappeared. As a result, from the early 70s to the late 80s. In domestic oil production, hydraulic fracturing was not used on an industrial scale.

The revival of domestic hydraulic fracturing began in the late 80s. V

due to a significant change in the structure of oil and gas reserves.

Until recently, only natural sand was used as proppant in Russia in quantities up to 130 t/well, and in most cases 20-50 t/well were pumped. Due to

Due to the very shallow depth of the treated formations, there was no need to use synthetic high-quality proppants. Until the end of the 80s. When carrying out hydraulic fracturing, mainly domestic or Romanian equipment was used, in some cases - American.

Now there are wide potential opportunities for introducing large-scale hydraulic fracturing operations in low-permeability gas-bearing formations in the fields of Siberia (depth - 2000-4000 m), Stavropol (2000-3000 m) and Krasnodar (3000-4000 m) territories, Saratov (2000 m) , Orenburg (3000-4000 m) and Astrakhan (Karachaganak field (4000-5000 m)) regions.

In Russian oil production, much attention is paid to the prospects for using the hydraulic fracturing method. This is due, first of all, to the growing trend in the structure of oil reserves and the share of reserves in low-permeability reservoirs. More than 40% of the industry's recoverable reserves are located in reservoirs with permeability less than 0.05 µm 2 , of which about 80% are in Western Siberia. By 2000, such reserves in the industry are expected to increase to 70%. Intensification of the development of low-productive oil deposits can be carried out in two ways: by compacting the network of wells, which requires a significant increase in capital investments and increases the cost of oil, or by increasing the productivity of each well, i.e. intensification of the use of both oil reserves and the wells themselves.

World oil production experience shows that one of the effective methods for intensifying the development of low-permeability reservoirs is the hydraulic fracturing method. Highly conductive hydraulic fracturing cracks make it possible to increase well productivity by 2-3 times, and the use of hydraulic fracturing as an element of the development system, i.e. the creation of a hydrodynamic system of wells with hydraulic fractures, increases the rate of extraction of recoverable reserves, increases oil recovery due to the involvement of poorly drained zones and interlayers in the active development and increases the coverage of waterflooding, and also allows the development of deposits with a potential well productivity 2-3 times lower than the level profitable production, therefore, transfer part of the off-balance reserves to industrial reserves. The increase in well productivity after hydraulic fracturing is determined by the ratio of the conductivity of the formation and the fracture and the size of the fracture, and the productivity coefficient of the well does not increase unlimitedly with increasing fracture length; there is a limit value of the length, exceeding which practically does not lead to an increase in fluid flow rate. For example, with a formation permeability of the order of 10 -2 μm 2, the maximum half-length is approximately 50 m. Taking into account the increase in the zones of influence of wells as a result of the creation of hydraulic fractures, when designing a development using hydraulic fracturing, a sparser well pattern can be planned.

For the period 1988-1995. More than 1,600 hydraulic fracturing operations have been carried out in Western Siberia. The total number of development objects covered by hydraulic fracturing exceeded 70. For a number of objects, hydraulic fracturing has become an integral part of development and is carried out in 50-80% of the stock of producing wells. Thanks to hydraulic fracturing, it was possible to achieve a profitable level of oil production at many sites. The increase in flow rates amounted to an average of 3.5, fluctuating for various objects from 1 to 15. The success of hydraulic fracturing exceeds 90%. The overwhelming number of well operations were carried out by specialized joint ventures using foreign technologies and foreign equipment. By 1995, the volume of hydraulic fracturing in Western Siberia reached the level of 500 well operations per year. The share of hydraulic fracturing in low-permeability reservoirs (Jurassic deposits, Achimov member) amounted to 53% of all operations.

Over the years, certain experience has been accumulated in carrying out and assessing the effectiveness of hydraulic fracturing in various geological and physical conditions.

JSC Yuganskneftegaz has accumulated extensive experience in hydraulic fracturing. Analysis of the effectiveness of more than 700 hydraulic fracturing carried out by the joint venture “YUGANSKFRAKMASTER” in 1989-1994. on 22 layers of 17 fields of Yuganskneftegaz JSC, showed the following. The main targets for hydraulic fracturing were deposits with low-permeability reservoirs: 77% of all treatments were carried out on objects with formation permeability less than 0.05 µm 2 , of which 51% were less than 0.01 µm 2 and 45% were less than 0.005 µm 2 . First of all, hydraulic fracturing was carried out on ineffective wells: on idle wells (24% of the total volume of work), on low-yield wells with a fluid flow rate of less than 5 tons/day (38%) and less than 10 tons/day (75%). Anhydrous and low-water (less than 5%) well stock accounts for 76% of all hydraulic fracturing. On average, over the period of generalization, for all treatments as a result of hydraulic fracturing, the liquid flow rate was increased from 8.3 to 31.4 tons/day, and for oil - from 7.2 to 25.3 tons/day, i.e. V

3.5 times with an increase in water cut by 6.2%. As a result, additional oil production due to hydraulic fracturing amounted to about 6 million tons over 5 years. The most successful results were obtained when hydraulic fracturing was carried out in purely oil objects with a large oil-saturated thickness (Achimov formation and formations B 4-5 of the Prirazlomnoye field), where the fluid flow rate increased from 3.5-6.7 to 34 t/day with an increase in water cut of only 5-6%.

Large-scale hydraulic fracturing at the largest Samotlor field began in 1992 by the Samotlor Services JV. By the beginning of 1997, 432 operations were carried out, the success rate was 94%, and more than 4 million tons of oil were additionally produced. The half-length of hydraulic fracturing cracks is on average about 40 m. Massive hydraulic fracturing has made it possible to change the established trend of falling oil production: for some objects there is not only a decrease in the rate of decline, but also stabilization and even an increase in production. The effect of hydraulic fracturing is quite stable; its duration is not limited to the period under consideration (4 years). For all objects, there is a decrease in the water cut of produced products in the first years after hydraulic fracturing, and this effect is most significant for intermittent reservoirs, which is associated with the involvement of previously undrained reserves in the development and, consequently, an increase in oil recovery.

Experience in hydraulic fracturing of discontinuous formations, represented mainly by individual reservoir lenses, was also obtained at the LUKoil-Kogalymneftegaz TPP at the Povkhovskoye field. Interlayers of the discontinuous zone are penetrated by two adjacent wells at an average distance of 500 m only in 24% of cases. The main task of regulating the development system of the Povkhovskoye field is to involve the intermittent zone of the BV 8 formation in the active work and accelerate the rate of reserve development along it. For this purpose, at the field in 1992-1994. carried out by JV “KATKONEFT” 154 GRP. The success rate of treatments was 98%. At the same time, on average, a fivefold increase in flow rate was obtained for the treated wells. The volume of additional oil produced amounted to 1.6 million tons. The expected average duration of the technological effect is 2.5 years. At the same time, additional production due to hydraulic fracturing per well should amount to 16 thousand tons. According to SibNIINP, by the beginning of 1997, 422 hydraulic fracturing operations had already been carried out at the field, the success rate of which was 96%, the volume of additional oil produced was 4.8 million tons, the average increase in well flow rate was 6.5 times. The average ratio of fluid flow rate after hydraulic fracturing in relation to the maximum flow rate achieved before hydraulic fracturing and characterizing the potential capabilities of the well was 3.1.

At the fields of the LUKoil-Langepasneftegaz TPP during 1994-1996. 316 hydraulic fracturing operations were carried out, and in 1997 - another 202 hydraulic fracturing operations. Processing is carried out in-house and by the joint venture “KATKONEFT”. Additional oil production amounted to about 1.6 million tons, the average increase in production rate was 7.7 tons/day per well.

In 1993, pilot work began on hydraulic fracturing at the fields of Noyabrskneftegaz OJSC; 36 operations were carried out during the year. The total volume of hydraulic fracturing production by the end of 1997 amounted to 436 operations. Hydraulic fracturing was carried out, as a rule, in low-yield wells with low water content, located in areas with deteriorated filtration and reservoir properties. After hydraulic fracturing, oil production increased by an average of 7.7 times, and liquid production by 10 times. As a result of hydraulic fracturing, in 70.4% of cases, water cut increased on average from 2% before hydraulic fracturing to 25% after treatment. The success rate of treatments is quite high and averages 87%. Additional oil production from hydraulic fracturing at OJSC Noyabrskneftegaz by the end of 1997 exceeded 1 million tons.

Dowell Schlumberger is one of the world's leading well stimulation companies. Therefore, her work on hydraulic fracturing in Russian fields is of great interest. This company prepared a project for the first Soviet-Canadian experiment to conduct massive hydraulic fracturing at the Salym field. For example, in one of the wells in a formation with a permeability of 10 -3 μm 2, a fracture with a half length of 120 m and a total height of 36.6 m was designed. After hydraulic fracturing in the Bazhenov formation in the summer of 1988, the well began to flow with a flow rate of 33 m 3 / day, which after 17 days decreased to 18 m 3 /day. Before hydraulic fracturing, the inflow was “non-overflowing”, i.e. the fluid level in the well did not rise to its mouth.

In 1994, Dowell Schlumberger carried out several dozen hydraulic fracturing operations at the Novo-Purpeiskoye, Tarasovskoye and Kharampurskoye fields of Purneftegaz OJSC. In the period until October 1, 1995, 120 hydraulic fracturing operations were carried out at the fields of OJSC Purneftegaz. The average daily flow rate of the treated wells was 25.6 t/day. Since the beginning of hydraulic fracturing, 222.7 thousand tons of additional oil have been produced. The work provides data on well flow rates approximately a year after hydraulic fracturing: in the second half of 1994, 17 operations were carried out at the fields of Purneftegaz OJSC; The average oil production rate of a well before hydraulic fracturing was 3.8 tons/day, and in September 1995 - 31.3 tons/day. Some wells showed a decrease in water cut. The introduction of hydraulic fracturing made it possible to stabilize the falling oil production at the Tarasovskneft oil and gas production unit.

Experience in carrying out hydraulic fracturing of partially depleted Jurassic formations of oil fields, which are characterized by a rapid decline and low production rates, ineffective waterflooding and a low current oil recovery factor, has been accumulated at Varyeganneftegaz OJSC. The analysis showed that the use of water-based fracturing fluids with the injection of a small amount of proppant (up to 10 tons) at low concentrations leads to the formation of short fractures with low conductivity and allows only a short-term increase in well productivity. The transition to the use of oil-based fluid with the injection of 25-35 tons of proppant while preventing contact of the formation with water after hydraulic fracturing gave much better results: an increase in fluid flow rate by 5 times compared to its 2-fold increase when using fluid on water, a decrease in water cut , reducing the duration of bringing the well into operation, increasing the duration of the effect. Such hydraulic fracturing turned out to be cost-effective and made it possible to reduce the payback period for capital investments in carrying out these works by 3-4 times compared to operations in which water-based fluids were used. Out of 180 hydraulic fracturing carried out in the period 1995-1997, 30 hydraulic fracturing was carried out using injection stock, which led to an increase in well injectivity by an average of 5 times and, with proper selection of wells for treatment, turned out to be an effective means of increasing oil recovery.

An analysis of the results of introducing hydraulic fracturing in the fields of Western Siberia shows that this method is usually used in single selected production wells. The generally accepted approach to assessing the effectiveness of hydraulic fracturing is to analyze the dynamics of oil production from only treated wells. In this case, the production rates before hydraulic fracturing are taken as the base ones, and additional production is calculated as the difference between the actual and base production for a given well. When making a decision to carry out hydraulic fracturing in a well, the effectiveness of this measure is often not considered, taking into account the entire reservoir system and the arrangement of production and injection wells. Apparently, this is related to the negative consequences of using hydraulic fracturing, noted by some authors. For example, according to work estimates, the use of this method in certain areas of the Mamontovskoye field caused a decrease in oil recovery due to a more intense increase in water cut in some treated and surrounding wells. An analysis of the hydraulic fracturing technology at the fields of OJSC “Surgutneftegas” showed that failures are often associated with an irrational choice of treatment parameters, when the injection rate and volumes of process fluids and proppant are determined without taking into account such factors as the optimal length and width of the fixed fracture, calculated for given conditions; rupture pressure of clay screens separating the productive formation from the overlying and underlying gas- and water-saturated formations. As a result, potential opportunities are reduced

Hydraulic fracturing as a means of increasing production increases the water cut of produced products.

Experience with acid hydraulic fracturing is available in the Astrakhan gas condensate field, the productive deposits of which are characterized by the presence of dense porous-fractured limestone with low permeability (0.1-5)-10 -3 μm 2 and porosity 0.07-0.14. The use of hydraulic fracturing is complicated by the large depths of production wells (4100 m) and high bottomhole temperatures (110 °C). During the operation of the wells, local depression craters formed and the reservoir pressure decreased in some cases to 55 MPa from the initial 61 MPa. As a result of these phenomena, condensate may fall out in the bottomhole zone, incomplete removal of fluid from the wellbore, etc. To improve the filtration characteristics of the bottomhole zone of low-yield wells, massive acid treatments are periodically carried out with injection parameters close to hydraulic fracturing. Such operations make it possible to reduce working depressions by 25-50% of the initial ones, slow down the growth rate of depression funnels and the rate of decrease in wellhead and bottomhole pressures.

Hydraulic fracturing at the Astrakhan field was carried out using special equipment from Frackmaster. The technology for carrying out the work, as a rule, was as follows. Initially, the well's injectivity was determined by injecting methanol or condensate. Then, in order to level the injectivity profile and create conditions for treating less permeable areas with an acid composition and connecting the formation to work, a gel was injected throughout its entire thickness. A mixture of hydrochloric acid with methanol or a hydrophobic acid emulsion (“hydrochloric acid in a hydrocarbon medium”) was used as an active fluid that reacts with the formation. When performing interval hydraulic fracturing, highly permeable zones or perforation channels were sealed using either gel or balls with a diameter of 22.5 mm together with gel. The moment of hydraulic fracturing was recorded on the indicator diagram by a sharp increase and subsequent drop in pressure with a simultaneous increase in injectivity. It is possible that already existing cracks opened in some wells, since the fact of hydraulic fracturing was not noted on the indicator diagrams, and the pressures corresponded to the pressure gradient of crack opening. The practice of hydraulic fracturing at the Astrakhan gas condensate field has shown its high efficiency, subject to the correct selection of wells and technological processing parameters. A significant increase in production rate was obtained even in cases where several acid treatments were carried out on the well before hydraulic fracturing, the last of which were unsuccessful.

1.4. SUCCESS FACTORS IN HYDRAULIC FRACTURING OPERATIONS

The main factors determining the success of hydraulic fracturing are the correct selection of the object for the operation, the use of hydraulic fracturing technology that is optimal for the given conditions, and the competent selection of wells for treatment.

The decision to carry out hydraulic fracturing in each specific case is made taking into account mining and geological conditions. However, as a rule, when analyzing the geological and physical properties of a potential object, the following features are taken into account:

heterogeneity of the formation along the strike and dissected thickness, ensuring high efficiency of hydraulic fracturing due to the inclusion of previously undrained zones and interlayers into development;

permeability of the formation, which usually should not exceed

0.03 µm 2 at oil viscosity up to 5 mPa-s and 0.03-0.05 µm 2 at oil viscosity up to 50 mPa-s (In formations of higher permeability, local hydraulic fracturing is effective, which gives a significant effect mainly as a means of treatment bottomhole zone.);

the thickness and consistency of lithological screens separating the productive formation from gas- or water-saturated reservoirs, which must be at least 4.5-6 m;

formation depth, which, as a rule, should not exceed 3500 m and determines the requirements for hydraulic fracturing technology, in particular for the strength of the proppant used;

reserve of reservoir energy and effective oil-saturated thickness of the reservoir, sufficient for a significant and long-term increase in well production after hydraulic fracturing and, therefore, ensuring recoupment of the costs of hydraulic fracturing;

depletion of recoverable reserves, which, as a rule, should not exceed 30%.

Research in the field of hydraulic fracturing technology, devoted primarily to the issues of selecting proppant and fracturing fluid, determining the required amount of these agents and the conditions for their injection, is currently being actively conducted. The current state of this problem is covered in sufficient detail in the works.

The highest efficiency of hydraulic fracturing can be achieved if the selection of wells for treatment and optimization of fracture parameters, ensuring a balance between the filtration characteristics of the formation and the fracture, are carried out taking into account the geological and physical properties of the object, the stress distribution in the formation, which determines the orientation of the fractures, the flooding system and the placement of wells. The effect of hydraulic fracturing is manifested differently in the operation of individual wells, so it is necessary to consider not only the increase in the production rate of each well due to hydraulic fracturing, but also the influence of the relative position of wells, the specific distribution of formation heterogeneity, the energy capabilities of the object, etc. Such an analysis is only possible on the basis of mathematical modeling of the process development of a section of a reservoir or an object as a whole using an adequate geological and production model that reveals the features of the geological heterogeneity of the object.

Hydraulic fracturing consists of three fundamental operations:

1. creation of artificial cracks in the reservoir (or expansion of natural ones);

2. injection of fluid with fracture filler through the tubing into the CCD;

3. pressing liquid with filler into cracks to secure them.

For these operations three liquid categories:

• rupture fluid,
• sand carrier liquid
• squeezing liquid.

Work agents must meet the following requirements:

1. Should not reduce the permeability of the CCD. At the same time, depending on the category of the well (production; injection; production, converted to water injection), working fluids of different nature are used.

2. Contact of working fluids with rock formations or with reservoir fluids should not cause any negative physical and chemical reactions, except in cases of the use of special working agents with controlled and targeted action.

3. Should not contain a significant amount of foreign mechanical impurities (i.e. their content is regulated for each working agent).

4. When using special working agents, for example, oil-acid emulsion, the products of chemical reactions must be completely soluble in the formation product and not reduce the permeability of the reservoir zone.

5. The viscosity of the working fluids used must be stable and have a low pour point in winter (otherwise the hydraulic fracturing process must be carried out using heating).

6. Must be easily accessible, not in short supply and inexpensive.

Hydraulic fracturing technology :

• Well preparation- an inflow or injectivity study, which allows you to obtain data for estimating the burst pressure, the volume of the burst fluid and other characteristics.
• Well flushing- the well is washed with a flushing fluid with the addition of certain chemical reagents. If necessary, decompression treatment, torpedoing or acid treatment are carried out. In this case, it is recommended to use pump-compressor pipes with a diameter of 3-4" (pipes of a smaller diameter are undesirable, since friction losses are high).
• Injection of fracturing fluid– the pressure necessary to rupture the rock is created to form new cracks and open existing cracks in the CZ. Depending on the properties of the CCD and other parameters, either filterable or low-filtration liquids are used.

Fluid rupture:

in production wells

Degassed oil;

Thickened oil, oil and fuel oil mixture;

Hydrophobic petroleum acid emulsion;

Hydrophobic oil-water emulsion;

Acid-kerosene emulsion, etc.;

in injection wells

Clean water;

Aqueous solutions of hydrochloric acid;

Thickened water (starch, polyacrylamide - PAA, sulfite-alcohol stillage - SSB, carboxymethylcellulose - CMC);

Thickened hydrochloric acid (a mixture of concentrated hydrochloric acid with SSB), etc.

When choosing a fracturing fluid, it is necessary to take into account and prevent the swelling of clays by introducing chemical reagents into it that stabilize clay particles during wetting (clay hydrophobization).

As already noted, burst pressure is not a constant value and depends on a number of factors.

An increase in bottomhole pressure and achievement of the burst pressure value is possible when the injection rate exceeds the rate of fluid absorption by the formation.

In low-permeability rocks, burst pressure can be achieved by using low-viscosity fluids as fracturing fluids at a limited injection rate. If the rocks are sufficiently permeable, then when using low-viscosity injection fluids, a higher injection rate is required; When injection rates are limited, it is necessary to use high-viscosity fracturing fluids. If the CZ is a high-permeability reservoir, then high injection rates and high-viscosity fluids should be used. In this case, the thickness of the productive horizon (interlayer), which determines the well’s injectivity, must also be taken into account.

• An important technological issue is determining the moment of crack formation and its signs. The moment of crack formation in a monolithic reservoir is characterized by a break in the relationship “volume injection fluid flow rate - injection pressure” and a significant decrease in injection pressure. The opening of cracks that already existed in the CZ is characterized by a smooth change in the flow-pressure relationship, but no decrease in injection pressure is observed. In both cases, a sign of crack opening is an increase in the well's injectivity coefficient. Injection of sand carrier fluid.

These requirements are dictated by the conditions for effective filling of cracks with filler and the exclusion of possible settling of the filler in individual elements of the transport system (wellhead, tubing, bottom hole), as well as premature loss of mobility by the filler in the crack itself. Low filterability prevents the filtration of sand-carrying fluid into the fracture walls, maintaining a constant concentration of filler in the fracture and preventing filler from clogging the fracture at its beginning. Otherwise, the concentration of filler at the beginning of the crack increases due to the filtration of the sand-carrying fluid into the walls of the crack, and the transfer of filler in the crack becomes impossible.

Viscous liquids or oils, preferably with structural properties, are used as sand-carrying fluids in production wells; oil and fuel oil mixtures; hydrophobic oil-water emulsions; thickened hydrochloric acid, etc. In injection wells, SSB solutions are used as sand-carrying fluids; thickened hydrochloric acid; hydrophilic oil-water emulsions; starch-alkaline solutions; neutralized black contact, etc.

To reduce friction losses when these fluids with filler move through the tubing, special additives (depressors) are used - soap-based solutions; high molecular weight polymers, etc.

• Injecting displacement fluid – pushing the sand-carrying liquid to the bottom and pressing it into the cracks. In order to prevent the formation of plugs from the filler, the following condition must be met:

where is the speed of movement of the sand-carrying fluid in the tubing string, m/s;

Viscosity of sand carrier fluid, mPa s.

As a rule, liquids with minimal viscosity are used as squeezing fluids. Production wells often use their own degassed oil (if necessary, it is diluted with kerosene or diesel fuel); injection wells use water, usually commercial water.

The following can be used as crack filler:

Sorted quartz sand with a grain diameter of 0.5 +1.2 mm, which has a density of about 2600 kg/m3. Since the density of sand is significantly greater than the density of the sand-carrying liquid, the sand can settle, which predetermines high injection rates;

Glass balls;

Agglomerated bauxite grains;

Polymer balls;

Special filler - proppant.

Basic requirements for the filler:

High compressive strength (crushing);

Geometrically correct spherical shape.

It is quite obvious that the filler must be inert in relation to the formation products and not change its properties for a long time. It has been practically established that the filler concentration varies from 200 to 300 kg per 1 m3 of sand-carrying liquid.

• After pumping the filler into the cracks, the well left under pressure. The holding time must be sufficient for the system (CCD) to move from an unstable to a stable state, in which the filler will be firmly fixed in the crack. Otherwise, during the process of inducing inflow, development and operation of the well, the filler is carried out from the cracks into the well. If the well is operated by pumping, the removal of filler leads to failure of the submersible unit, not to mention the formation of filler plugs at the bottom. The above is an extremely important technological factor, neglect of which sharply reduces the efficiency of hydraulic fracturing, up to a negative result.
• Calling influx, well development and hydrodynamic testing. Conducting a hydrodynamic study is a mandatory element of the technology, because its results serve as a criterion for the technological efficiency of the process.

A schematic diagram of well equipment for hydraulic fracturing is presented in rice. 5.5. When carrying out hydraulic fracturing, the tubing string must be sealed and anchored.

Important issues during hydraulic fracturing are: determining the location, spatial orientation and size of cracks. Such definitions should be mandatory when carrying out hydraulic fracturing in new regions, because allow us to develop the best process technology. The listed problems are solved based on the method of monitoring changes in the intensity of gamma radiation from a crack into which a portion of filler activated by a radioactive isotope, for example, cobalt, zirconium, or iron, is pumped. The essence of this method is to add a certain portion of activated filler to a clean filler and carry out gamma ray logging immediately after the formation of cracks and injection of a portion of activated filler into the cracks; By comparing these gamma ray logging results, the number, location, spatial orientation and size of the formed cracks are judged. These studies are carried out by specialized field geophysical organizations.

Rice. 5.5. Schematic diagram of well equipment for hydraulic fracturing:

1 - productive formation; 2 - crack; 3 - shank; 4 - packer; 5 - anchor; 6 - casing; 7 - tubing column; 8 - wellhead equipment; 9 - rupture fluid; 10 - sand-carrying liquid; 11 - squeezing liquid; 12 - pressure gauge.

Problems of using hydraulic fracturing. ASS is where there are layers containing water next to the productive formation. These may be aquifers, if there is bottom water. In addition, there may be formations near the treated formation that are flooded.

In such cases, vertical cracks formed during hydraulic fracturing create a hydrodynamic connection between the well and the aquifer zone. In most cases, the aquifer zone has greater permeability compared to the productive formation where hydraulic fracturing is carried out. This is why hydraulic fracturing can lead to complete watering of wells. In old fields, many wells are in disrepair. Carrying out hydraulic fracturing under such conditions leads to rupture of the production string. Theoretically, in such wells a packer is used to protect the string, but due to dents on the string and corrosion, it is in such wells that the packer does not fulfill its role. In addition, due to hydraulic fracturing, cement stone can be destroyed.

During hydraulic fracturing, cracks are created in layers with different permeability, but very often it is easier to rupture a high-permeability layer than a low-permeability layer. In a layer with higher permeability, the crack may be longer. With this option, after hydraulic fracturing, the well's oil production rate increases, but the water cut increases if the well was water-cut. That is why, before and after hydraulic fracturing, it is necessary to analyze the produced water in order to find out where the water came from in the well.

With hydraulic fracturing, as with any stimulation methods, the question always arises of compensating for large extractions by injection.

Introduction

1. Hydraulic fracturing as a means of maintaining well productivity

2. The essence of the hydraulic fracturing method

2.1 Hydraulic fracturing

2.2 Hydraulic fracturing tools

3 Technology and equipment for hydraulic fracturing

4 Selection of hydraulic fracturing technology

5 Equipment used during hydraulic fracturing

6 Example of hydraulic fracturing calculation

Conclusion

List of used literature

INTRODUCTION

Oil extraction from the reservoir and any impact on it is carried out through wells. The bottomhole zone of the well (BZZ) is the area in which all processes occur most intensively. Here, as if in a single unit, current lines converge when extracting liquid or diverge during injection. The efficiency of field development, production flow rates, injection capacity, and the portion of reservoir energy that can be used to lift fluid directly in the well depend significantly on the state of the bottomhole zone of the formation.

Mechanical impact methods are effective in hard rocks, when the creation of additional cracks in the CZ makes it possible to introduce new remote parts of the formation to the filtration process.

One of the most common methods for intensifying oil production or gas recovery is hydraulic fracturing (HF).

It is used to create new fractures, both artificial and to expand old (natural) ones, in order to improve connectivity with the wellbore and increase the system of fractures or channels to facilitate inflow and reduce energy losses in this limited area of ​​the formation.

Hydraulic fracturing is carried out at pressures reaching up to 100 MPa, with high fluid flow and using complex and varied equipment.

1. HYDRAULIC FRACTURING AS A MEANS OF MAINTAINING WELL PRODUCTIVITY

The essence of the hydraulic fracturing method is that high pressures are created at the bottom of the well by injecting a viscous fluid, exceeding reservoir pressure by 1.5-2 times, as a result of which the formation stratifies and cracks form in it.

Field practice shows that the productivity of wells after hydraulic fracturing sometimes increases several tens of times. This indicates that the formed cracks are connected to pre-existing ones, and the influx of fluid to the well occurs from remote highly productive zones isolated from the well before the formation rupture. The opening of natural or formation of artificial cracks in the formation is judged by graphs of changes in flow rate Q and pressure P during the process. The formation of artificial fractures in the graph is characterized by a drop in pressure at a constant injection rate, and when natural fractures open, the flow rate of the fracturing fluid increases disproportionately to the increase in pressure.

Hydraulic fracturing is carried out to maintain well productivity, as practice has shown that hydraulic fracturing is more profitable than constructing a new well, both from an economic and development point of view. But carrying out hydraulic fracturing requires a very careful study of the thermodynamic conditions and state of the wellbore zone, the composition of rocks and fluids, as well as a systematic study of the accumulated field experience in a given field. Hydraulic fracturing is recommended in the following wells:

1. Those that gave a weak influx during testing

2. With high reservoir pressure, but with low reservoir permeability

3. With a contaminated bottomhole zone

4. With reduced productivity

5. With a high gas factor (compared to others)

6. Low-injection injection pumps

7. Pressure to expand the absorption interval

The purpose of hydraulic fracturing is to increase the productivity of wells, with an impact on the bottomhole zone of the well - changing the properties of the porous medium and liquid (the properties of the porous medium change during hydraulic fracturing due to the formation of a system of cracks).

Let us assume that we associate the success or failure of hydraulic fracturing with two factors: the previous well flow rate and the thickness of the formation. In reality, the effectiveness of hydraulic fracturing depends, of course, not on two, but on many factors: the pressure of the injected fluid, the injection rate, the percentage of sand in this fluid, etc.

2. ESSENCE OF THE FRACTURING METHOD

Hydraulic fracturing of the formation is carried out as follows: liquid is pumped into the permeable formation at a pressure of up to 100 MPa, under the influence of which the formation is split, either along bedding planes or along natural cracks. To prevent the cracks from closing when the pressure is removed, coarse sand is pumped into them along with the liquid, which maintains the permeability of these cracks, which is a thousand times greater than the permeability of the undisturbed formation.

To prevent the closure of cracks formed in the formation and to keep them open after the pressure is reduced below the burst pressure, sorted coarse-grained quartz sand is injected into the cracks formed along with the liquid. Sand supply is required both into newly created and existing cracks in the formation opened during hydraulic fracturing. Studies show that during hydraulic fracturing, cracks with a width of 1-2 mm appear. Their radius can reach several tens of meters. Fractures filled with coarse sand have significant permeability, as a result of which, after hydraulic fracturing, the productivity of the well increases several times.

Hydraulic fracturing (HF) is carried out to form new or open existing cracks in order to increase the permeability of the bottomhole zone of the formation and increase the productivity of the well.

Hydraulic fracturing is achieved by injecting fluid into the formation under high pressure. To prevent closure after the end of the operation and reduce the pressure to the initial one, porous material is pumped into them along with the liquid - quartz sand, corundum.

One of the most important parameters for hydraulic fracturing is the hydraulic fracturing pressure at which cracks form in the rock. Under ideal conditions, the opening pressure p p should be less than the rock pressure p g created by the strata of overlying rocks. However, in real conditions the inequality r g * r n can be satisfied< р р, что объясняется наличием в пласте глинистых пропластков, обладающих пластичными свойствами. В процессе бурения, когда цикл скважины не обсажен, под действием веса вышележащих пород может произойти выдавливание глины из пласта в скважины и частичное разгружение пласта, расположенного под глинистыми пропластками, что и приводит к снижению давления гидроразрыва.

Thus, the burst pressure depends on the drilling process preceding the well operation. Therefore, the burst pressure cannot be calculated. However, with similar technologies for drilling wells in a given area, we can talk about the average fracturing pressure, determining it from hydraulic fracturing data in neighboring wells.

2.1 Hydraulic fracturing

Hydraulic fracturing is carried out using the following technology. First, fracturing fluid is pumped under high pressure. After the formation is ruptured, liquid with sand is pumped in to fix the cracks. Typically, both the fracturing fluid and the sand-carrying fluid when treating production wells are prepared on a hydrocarbon basis, and when treating heating wells - on a water basis. As a rule, various emulsions, as well as hydrocarbon liquids and aqueous solutions are used for these purposes. The concentration of sand in the sand carrier fluid usually ranges from 100 to 500 kg/m3 and depends on its filterability and holding capacity.

The mechanism of hydraulic fracturing of a formation, i.e. the mechanism of formation of cracks in it, can be presented as follows. All rocks that make up a particular layer have natural microcracks, which are in a compressed state under the influence of the weight of the overlying rock mass or, as it is commonly called, rock pressure. The permeability of such cracks is small. All rocks have some strength. Therefore, in order to form new cracks in the formation and expand existing ones, it is necessary to remove the stresses created by rock pressure in the formation rocks and overcome the tensile strength of the rocks.

The burst pressure, even within one formation, is not constant and can vary widely. Practice has confirmed that in most cases the burst pressure P p at the bottom of the well is lower than the rock pressure and amounts to (15...25) * N, kPa (1.5...2.5 kgf/cm 2).

Here H is the depth of the well in m.

For low-permeability rocks, this pressure can be achieved by injecting low-viscosity fracturing fluids at limited injection rates. If the rocks are highly permeable, a high injection rate is required, and if the injection rate is limited, it is necessary to use fluids of high viscosity. Finally, in order to achieve burst pressure in the case of particularly high permeability of the formation rocks, even higher injection rates of high-viscosity fluids should be used. The hydraulic fracturing process consists of the following sequential operations: 1) injection of fracturing fluid into the formation to form cracks; 2) injection of sand-carrying fluid with sand intended for fixing cracks; 3) injection of squeezing fluid to force sand into cracks.

2.2 Hydraulic fracturing tools

Typically, the same fluid is used as fracturing fluid and sand-carrying fluid, so they are combined under one name - fracturing fluid. For hydraulic fracturing, various working fluids are used, which, according to their physicochemical properties, can be divided into two groups: hydrocarbon-based fluids and water-based fluids.

High-viscosity oil, fuel oil, diesel fuel or kerosene thickened with naphthenic soaps are used as hydrocarbon liquids.

Solutions used in injection wells include: an aqueous solution of sulfite and alcohol stillage, solutions of hydrochloric acid, water thickened with various reagents, as well as thickened solutions of hydrochloric acid.

The fracturing process is highly dependent on the physical properties of the fracturing fluid and, in particular, the viscosity, filterability and ability to hold sand grains in suspension.

The following requirements apply to the fracturing fluid. Firstly, it must be highly viscous so that it does not quickly penetrate deep into the formation, otherwise the increase in pressure near the well will be insufficient. Secondly, if there are several productive layers in the well section, it is necessary to ensure as uniform an injectivity profile as possible. Newtonian fluids are not suitable for this, since the amount of fluid entering each layer will be proportional to its permeability. Therefore, highly permeable layers will be better processed and, consequently, the effect of hydraulic fracturing will be reduced. For hydraulic fracturing, it is necessary to use a fluid whose viscosity depends on the filtration rate. If viscosity increases with increasing filtration rate, then when moving in a highly permeable interlayer, the viscosity of the liquid will be higher than in a low-permeable one. As a result, the pickup profile becomes more uniform. Viscoelastic fluids have a similar filtration characteristic, the filtration law for which can be written in the form.

V=(kDp)/(m k L),……………………………………………………….................(1)

where m k is the apparent viscosity, determined by the formula

m k /m o = 1 + A Dp/L,……………………………………………………….(2)

m o is the maximum apparent viscosity of the liquid at v ® 0; A is a constant depending on the viscoelastic properties of the fluid (at A=0 we obtain Darcy’s law).

2.3 Necessary parameters for hydraulic fracturing

When pumping liquid into two layers with permeabilities k 1 and k 2, the mobility ratio at the same pressure gradients is equal to

(k/m k) 1: (k/m k) 2 = k 1 /k 2 * (1+A (Dp/L)*)/1+A(Dp/L)*),…….(3)

Let, for example, A(Dp/L)*) =2

Then at k 1 /k 2 =25 A (Dp/L)*=0.4

And the mobility ratio is approximately 11.7 instead of 25.

For hydraulic fracturing, pipes are lowered into the well, through which the Liquid enters the formation. To protect the casing from high pressures, a packer is installed above the fractured formation, and a hydraulic anchor is installed above it to increase the tightness. Under the influence of pressure, the armature pistons move apart and are pressed against the casing, preventing the packer from moving.

With a very low viscosity of the fracturing fluid, achieving the fracturing pressure requires pumping a large volume of fluid into the formation, which is associated with the need to use several simultaneously operating pumping units.

When the viscosity of the fracturing fluid is high, high pressures are required for crack formation. Depending on the permeability of the rocks, the optimal viscosity of the fracturing fluid ranges from 50-500 cP. Sometimes when pumping through a casing, a fluid with a viscosity of up to 1000 cP and even up to 2000 cP is used.

The fracturing fluid must be low-filtration and have a high holding capacity for sand suspended in it, which prevents the possibility of its settling in the pump cylinders, piping elements, pipes and at the bottom of the well.

In this case, maintaining a constant concentration of sand in the fracture fluid and good conditions for its transfer into the depths of the crack are achieved. Filterability is checked using a device to determine the fluid loss of a clay solution. Filterability is considered low if it is less than 10 cm 3 of liquid in 30 minutes.

The ability of a fracturing fluid to hold sand in suspension is directly related to its viscosity.

More viscous liquids, such as fuel oils, have satisfactory viscosity at temperatures below 20°C; crude oils and water have low viscosity, are generally well filtered, and are not recommended for use in pure form in hydraulic fracturing.

An increase in viscosity, as well as a decrease in the filterability of fluids used in hydraulic fracturing, is achieved by introducing appropriate thickeners into them. Such thickeners for hydrocarbon liquids are salts of organic acids, high-molecular and colloidal compounds of oils (for example, oil tar) and other oil refining wastes.

Some oils, kerosene-acid, oil-acid, and water-oil emulsions have significant viscosity and high sand-carrying ability. These fluids are used as fracturing fluids and sand-carrying fluids for fracturing oil wells.

In injection wells, hydraulic fracturing uses thickened water. For thickening, sulfite-alcohol stillage (SSB) and other cellulose derivatives, which are highly soluble in water and have low filterability, are used.

Depending on the concentration of dry substances, SSB is of two types - liquid and solid. The viscosity of the initial liquid concentrate is 1500-1800 cP. The addition of water to SSB solutions leads to a rapid decrease in viscosity and promotes good washing of SSB with water from the porous space and restoration of injectivity. The SSB solution has good retention capacity and low filterability. For rupture, a solution of SSB with a viscosity of 250-800 cP is mainly used.

Recently, concentrated hydrochloric acid thickened with SSB (40% HCl and 60% SSB) has been used as a sand-carrying liquid. The use of such a fracturing fluid makes it possible to combine the hydraulic fracturing process with chemical impact on the bottomhole zone. When mixed with SSB, hydrochloric acid reacts slowly with carbonates (2-2.5 hours versus 30-40 minutes when using a pure HCl solution). This makes it possible to push chemically active hydrochloric acid deep into the formation along cracks formed during hydraulic fracturing and treat the bottom-hole zone of the formation at a great distance from the wellbore.

During hydraulic fracturing under conditions of high reservoir temperatures (130-150°C), the viscosity of 20- and 24% SSB solutions sharply decreases to 8-0.6 cP with an increase in temperature to 90°C.

At higher temperatures, the viscosity of these solutions approaches the viscosity properties of water. Therefore, as an effective fracturing fluid and sand carrier, which has good sand-holding ability and low filterability, aqueous solutions of CMC-500 (carboxymethylcellulose) are used in the range of 1.5-2.5% with the addition of sometimes sodium chloride up to 20-25%. Under all conditions, the displacement fluid must have a minimum viscosity in order to reduce pressure losses during pumping.

The purpose of filling cracks with sand is to prevent them from closing and keep them open after the pressure is removed below the burst pressure. Therefore, the following requirements are imposed on sand:

1) the sand must have sufficient mechanical strength so as not to collapse in cracks under the influence of the weight of the rock;

2) maintain high permeability.

Well-rolled homogeneous quartz sand satisfies these requirements.

Sand of the following fractions is used: 0.25-0.4 mm; 0.4-0.63; 0.63-0.79; 0.79-1.0; 1.0-1.6MM. The most acceptable fraction for hydraulic fracturing is sand with a grain size from 0.5 to 1.0 mm.

The degree of effectiveness of hydraulic fracturing is determined by the diameter and extent of the fractures created and therefore the increased permeability. The larger the diameter and length of the cracks, the higher the processing efficiency. The creation of long-term fractures is achieved by pumping large quantities of sand. In practice, from 4 to 20 tons of sand are pumped into the well. The concentration of sand in the sand carrier fluid depends on the filterability and holding capacity of the fluid and ranges from 100 to 600 kg per 1 m 3 of fluid.

3. TECHNOLOGY AND TECHNIQUE FOR FRAFTING

Hydraulic fracturing is carried out in formations with different permeability in the event of a drop in flow rate or injectivity of injection wells.

Before hydraulic fracturing, a well is tested for inflow, its absorption capacity and absorption pressure are determined. For this purpose, oil is pumped with one unit until a certain excess pressure is obtained at the wellhead, at which the well begins to accept liquid. The flow rate is measured for 10-20 minutes at a constant discharge pressure. After connecting the second unit and increasing the amount of pumped liquid, the pressure is raised by 2-3 MPa and the flow rate is determined again.

The process of increasing fluid flow and pressure is repeated several times, and at the end of the study, the maximum possible pressure is created, at which the flow is measured again. Based on the data obtained, a curve is drawn to plot the dependence of the well's injectivity on the injection pressure. Based on the data on the absorption capacity of the well before and after fracturing, the amount of fluid and pressure required to carry out the fracturing is determined, and the quality of the fracturing and changes in the permeability of the near-wellbore zone formations after the fracturing are judged. The formation rupture pressure is conventionally taken to be the pressure at which the well's injectivity coefficient increases by 3-4 times compared to the initial one.

The bottom of the well is cleaned of dirt by drainage and then washed. In some cases, to increase the filtration properties of formations, it is recommended to pre-treat the well with hydrochloric or mud acid and carry out additional perforation. The implementation of these measures helps to reduce the burst pressure and increase its efficiency.

After washing, cleaning and checking with a special template, pump and compressor pipes with a diameter of 75 or 100 mm are lowered into the well, through which the fracturing fluid is pumped. To protect the casing from exposure to high pressure, a packer is installed above the fractured formation, which separates the filter zone of the formation from its overlying part. Due to this, the pressure created by the pumps is transmitted only to the filter zone and to the lower surface of the packer.

Various packer designs are used. The most common are slip packers, produced for various diameters of production strings and designed for a pressure of 50 MPa (Fig. 1).

Sealing of the casing is carried out by deformation of the rubber sealing collars from the weight of the tubing string when the cone is supported on the slips of the packer, which is centered by a lantern. The locking device of the lantern opens when the lantern rubs against the walls of the casing pipes during packer rotation.

The axial load during hydraulic fracturing is perceived by the packer head with a support ring and is transmitted to the anchor, which holds the packer and tubing string from moving upward. The packer head has a left-hand thread at the junction with the anchor.

In case of jamming of the cuffs in the casing, the anchor can be unscrewed from the packer by right rotation and raised to the surface.

The design of the ram hydraulic action is shown in Fig. 2

During the process of pumping working fluid for hydraulic fracturing, the pressure difference created between the inside of the anchor and the annular gap in the production string deforms the rubber tube, pushing the rams all the way into the column wall. The rams, cutting into the walls of the pipes with their sharp teeth, keep the anchor and, accordingly, the packer from being pushed up the well.

Along with slip packers, self-sealing PS packers are used. In this design, sealing is achieved by self-sealing rubber cuffs under the influence of fracturing fluid.

Unlike other types of packers, the PS packer design includes a bypass valve designed to bypass hydraulic fracturing fluid into the annulus during packer lowering, thereby relieving pressure on the self-sealing collars. The bypass valve is connected through a sub and installed above the hydraulic armature.

After running the pipes with a packer and anchor, the wellhead is equipped with a special head, to which units are connected to inject fracturing fluid into the well.

3.1 Piping and equipment for hydraulic fracturing

Figure 2 shows a general diagram of the piping and arrangement of equipment for hydraulic fracturing. At the first stage, fracturing fluid is pumped in by pumping units, as a result of which the pressure gradually increases and, upon reaching a certain value, the formation ruptures. The moment of rupture is judged by the pressure gauge on the flow line. This moment is characterized by a sharp drop in pressure and increased flow of injected liquid.

After fracturing the formation, they proceed to the second stage - supplying sand-carrying fluid with sand into the crack at high flow rates and high injection pressure. The sand-carrying fluid with sand is pressed into the crack with a squeezing fluid at maximum pressure and at maximum injection speed. This is achieved by connecting the largest number of units. Oil is used as a displacement fluid for oil wells and water is used for injection wells. The amount of this liquid must be equal to the capacity of the pipe string. Injecting displacement fluid is the last, third stage of the continuous hydraulic fracturing process.

After forcing, the wellhead is closed and the well is left alone until the wellhead pressure drops to zero. Then the well is washed, cleared of sand and development begins.

Of interest is the technique of hydraulic fracturing in wells whose productive horizons lie at depths of 2800-3400 m. The technology of formation fracturing in such wells differs from the usual one in that the hydraulic fracturing process takes place under constant back pressure on the tubing and on the upper end of the rubber element of the packer. The value of back pressure is determined as the difference between the calculated value of hydraulic fracturing pressure and the maximum permissible pressure on the packer. For such wells, the working pressure in the annular space (annulus) is determined experimentally. An auxiliary unit is used to pump up the fracturing fluid. Features of the arrangement of equipment and piping of the wellhead during hydraulic fracturing using this technology are shown in Fig. 3

It is recommended to carry out hydraulic fracturing work on a well in the following sequence. The surface equipment is pressurized to a pressure of 70 MPa and the water in the well is replaced with oil, after which the packer is lowered. Then, using pumping units used for hydraulic fracturing, the maximum possible pressure is created by pumping liquid in the tubing and under the packer. By pumping liquid with an auxiliary cementing unit, the pressure in the annular space (annulus) is raised and the well is left alone for 30 minutes. This at the first stage allows for the formation of cracks in the formation.

At the second stage, an operation is carried out to fix the cracks with sand. After testing the well for injectivity, a sand-carrying liquid is pumped into the formation.

Rice. 3. Equipment piping diagram for hydraulic fracturing in deep wells:

1 - sand mixer; 2 - unit TsA-400; 3- unit CHAN-700;

4 - auxiliary unit; 5 - container for working fluids

The pressure at the wellhead during injection and forcing into the formation can increase to 60-80 MPa. Hydraulic fracturing using this technology can significantly increase well productivity.

If there is a large filter zone in the wells or several exposed productive layers, multiple interval hydraulic fracturing is performed.

Recently, a new method of interval hydraulic fracturing has been developed and implemented, which makes it possible to carry out hydraulic fracturing of certain formations in any sequence in one run of downhole equipment. When carrying out hydraulic fracturing using this technology in one layer, the perforated holes against the overlying layers are covered with sinking ones, and against the underlying layers - with elastic balls floating in the fracturing fluid. The downhole equipment used is simple in design and can be manufactured in field workshops. It consists of two hollow cylinders, coaxially mounted on pump and compressor pipes. The cylinder with holes in the bottom is open at the top, and the cylinder with holes in the lid is open at the bottom. The pipe on which the cylinders are placed and welded is plugged from below and has holes above the lower cylinder.

Preparatory work for interval hydraulic fracturing is carried out in the following sequence. Cylinders, a packer and an anchor are lowered into the well using tubing. Special elastic balls with a diameter of 18-20 mm with a specific gravity lower than that of fluids used in hydraulic fracturing (floating balls) are placed under the lower cylinder; therefore, in the liquid they will always be pressed against the cover of the lower cylinder. The diameter of the cylinder is selected so that the balls cannot get into the gap between it and the production string. The number of balls loaded into the lower cylinder is slightly greater than the number of perforations located below the uppermost interval targeted for fracturing.

Sinking balls are placed in the upper cylinder. Moreover, their number should also be greater than the number of holes located above the lower interval planned for hydraulic fracturing. To prevent the balls from falling under the packer when going down or when the column is not sealed, a special disc-breaker is installed. The packer is installed in such a way that the interval intended for hydraulic fracturing is located between the cylinders with balls. After this, hydraulic fracturing of the targeted formation is carried out in the usual way. If, during a rupture, the above or underlying layers begin to accept liquid, then their perforation holes are blocked by balls, which are carried away by the fluid flow from the cylinders to these holes. Thus, hydraulic fracturing will occur only in the intended interval. After the injection stops, the balls, due to the corresponding difference in their specific gravities, will be collected in their cylinders. By raising or lowering the equipment and placing cylinders with balls at the desired interval, it is possible to hydraulically fracture any formation.

4. SELECTION OF FRACTURING TECHNOLOGY

Hydraulic fracturing technology is carried out as follows. Since during hydraulic fracturing in most cases (with the exception of small wells) pressures arise that exceed those permissible for casing strings, tubing capable of withstanding this pressure is first lowered into the well. Above the roof of the formation or interlayer in which it is planned to rupture, a packer is installed that isolates the annular space and the string from pressure, and a device that prevents its displacement and is called an anchor. First, fracturing fluid is injected through lowered tubing in such volumes as to obtain at the bottom hole pressure sufficient to fracturing the formation. The moment of rupture on the surface is noted as a sharp increase in fluid flow (absorption capacity of the well) at the same pressure at the wellhead or as a sharp decrease in pressure at the wellhead at the same flow rate. Rock pressure is equal to:

Р g = r П gН (4)

The adhesion force of rock particles is equal to:

Р р = Р g + s Z (5)

a more objective indicator characterizing the moment of hydraulic fracturing is the absorption capacity coefficient

k p = Q/(p z – p p) (6)

where Q is the flow rate of the injected liquid;

p p - reservoir pressure in the area of ​​a given well;

rz is the pressure at the bottom of the well during hydraulic fracturing.

During hydraulic fracturing, there is a sharp increase in kp. However, due to the difficulties associated with continuous monitoring of the value of pz, and also due to the fact that the pressure distribution in the formation is a significantly unsteady process, the hydraulic fracturing moment is judged by the conditional coefficient k.

k = Q/р у (7)

where p y is the pressure at the wellhead.

A sharp increase in k during the injection process is also interpreted as the hydraulic fracturing moment. Instruments are available to measure this value.

After fracturing the formation, a sand-carrying liquid is pumped into the well at pressures that keep the cracks formed in the formation in an open state. This is a more viscous liquid mixed (180-350 kg of sand per 1 m 3 of liquid) with sand or other filler. Sand is introduced into the open cracks to the greatest possible depth to prevent the cracks from closing during the subsequent release of pressure and the well being put into operation. Sand-carrying fluids are pushed into the tubing and into the formation using a displacement fluid, which is any low-viscosity, non-deficient fluid.

To design the hydraulic fracturing process, it is very important to determine the burst pressure p p that needs to be created at the bottom of the well.

A large amount of statistical material has been accumulated on the value of formation rupture pressure p p for various fields of the world and at different well depths, which indicates the absence of a clear connection between the depth of the formation and the rupture pressure. However, all actual values ​​of рр lie within the range between the values ​​of the total rock and hydrostatic pressures. Moreover, at shallow depths (less than 1000 m) рр is closer to rock pressure and at greater depths - to hydrostatic pressure.

for shallow wells (up to 1000 m)

r r = (1.74 - 2.57) r st,………………………………………………………(8)

for deep wells (H > 1000m)

r r =(1.32 - 1.97) r st,…………………………………………….(9)

where p st is the hydrostatic pressure of the liquid column, the height of which is equal to the depth of the formation.

The tensile strength of rocks is usually low and lies in the range s p = 1.5 ... 3 MPa, so it does not significantly affect p p.

The rupture pressure at the bottom p p and the pressure at the wellhead p y are related by the obvious relationship

r r = r y + r st – r tr,………………………………………………………………………………........ (10)

where p tr – pressure loss due to friction in the tubing.

From equation (10) it follows:

r y = r r + r tr - r st,……………………………………………………….....(11)

p st - static pressure, determined taking into account the curvature of the well

r st = r f g N cos b,………………………………………………………(12)

where H is the depth of the well; b - angle of curvature (averaged);

rf is the density of the liquid in the well, and if the liquid contains filler (sand, glass beads, polymer powder, etc.), then the density is calculated as a weighted average

r=r f (1–n/r n)+n,……………………………………………………………………(13)

where n is the number of kilograms of filler in 1 m 3 of liquid;

pH - density of the filler (for sand pH = 2650 kg/m 3).

Friction losses are more difficult to determine, since the fluids used sometimes have non-Newtonian properties. The presence of filler (sand) in the liquid increases friction losses.

In American practice, various graphs of pressure loss due to friction are used for every 100 feet of tubing of different diameters when pumping various liquids with a given volumetric flow rate. At high injection rates corresponding to turbulent flow, the structural properties of the fluids used (with various thickeners and chemical reagents) usually disappear, and the friction losses for these fluids can be determined fairly approximately using the usual formulas of pipe hydraulics.

r tr = l(N/d) * (w 2 /2g) * rga,…………………………………………....(14)

where l is the friction coefficient, determined by the corresponding formulas depending on the Reynolds number;

w - linear flow velocity in the tubing;

d – internal diameter of the tubing; r - fluid density, N - tubing length;

g = 9.81 m/s 2 ; a is a correction factor that takes into account the presence of a filler in the liquid (for pure water a = 1) and depends on its concentration.

5. EQUIPMENT USED FOR fracturing

When hydraulic fracturing, a whole complex of surface equipment is used: pumping units of the 2AN-500 or 4AN-700 type, a 4PA sand mixing unit. To transport fracturing fluid, 4TSR or TsR-20 tank trucks are used.

The 4AN-700 unit designed by Azinmash is the main one in the set of ground equipment. It features increased power and performance and is easy to use. The operating pressure of the unit allows for hydraulic fracturing and hydrosandblasting processes in deep wells. All its components are mounted on a KrAZ-257 three-axle truck with a lifting force of 100-120 kN and consist of the following: power plant; gearbox; triple plunger pump; manifold, control system.

On the frame of the car, directly behind the driver’s cabin, there is a power plant of the unit, consisting of an engine with a multi-disc friction clutch and a centrifugal fan, power systems, lubrication and cooling, an air cleaner installation and other auxiliary components.

The engine of the unit is a twelve-cylinder, four-stroke diesel engine with a power of 588 kW at a crankshaft speed of 2000 rpm. The engine is connected to the transmission input shaft using a multi-plate friction clutch.

Pump 4R-700 is a three-plunger, horizontal, single-acting pump. The plungers are provided in sizes of 100 and 120 mm, which ensures operation of the pump at pressures of up to 70 and 50 MPa, respectively. The productivity of the unit at a pressure of 70 MPa is 6.3 l/s and at 20 MPa - 22 l/s. Unit weight 20200 kg, overall dimensions 9800 x 2900 x 3320 mm. The unit is controlled from a central console located in the vehicle's cabin, where the control pedals for the fuel pump and engine friction clutch, the gearbox control handle and the necessary instrumentation are located.

To transport sand of the required fractions to the well where hydraulic fracturing is planned, and for the subsequent mechanical preparation of the sand-liquid mixture, special sand mixing units of the 4PA type are used.

On the self-propelled chassis of the KrAZ-257 vehicle, a hopper 1 for bulk material with a loading auger 2 and a working auger 3, a hydraulic displacement chamber 5, a mixer 7 with a float level regulator 6, as well as a receiving manifold 11 and a distribution manifold 10 with a pump 9 for pumping sand are mounted . A rotary valve 4 is installed in the upper unloading part of the auger 3, connected to a float regulator 6. Pneumatic vibrators are attached to the walls and bottom of the hopper 1, ensuring reliable flow of bulk material by gravity into the auger 3 receiver.

The loading and working augers, as well as the paddle mixer, are driven by hydraulic motors using an oil pump 8. All units of the installation are controlled from a remote control located in the vehicle cabin.

A sand-liquid mixture with a small concentration of sand is prepared as follows. The liquid through the receiving manifold 11 enters the hydraulic displacement chamber 5, into which bulk material is supplied from hopper 1 by auger 3. The amount of bulk material is regulated by the rotation speed of the working auger and damper 4 using a float level regulator 6, depending on the level of the mixture in mixer 7. The excess amount of bulk material flows back into the hopper through the outlet pipe. In the hydraulic mixing chamber 5, a solution of the required concentration is prepared, which enters the mixer 7, where a uniform sand concentration is maintained using a paddle mixer. From mixer 7, the solution is supplied by sand pump 9 through distribution manifold 10 to the point of consumption.

When preparing a sand-liquid mixture with a high concentration of bulk material, the hydraulic mixing chamber is replaced by a through pipe, and the liquid from the collector 11 and the bulk material from the hopper 1 enter directly into the mixer 7, through a replaceable pipe (indicated by the dotted line). The finished mixture is selected in the same way as in the first case.

Rice. 4. Scheme of the sand mixing unit

Hopper capacity 6.5 m3. The maximum productivity of the working auger (for sand) is 50 t/h, the maximum lifting force is 90 kN, the productivity of the loading auger is 12-15 t/h. The mass of the unit with a load is 23,000 kg, overall dimensions are 8700 x 2625 x 3600 mm. The sand mixing unit is serviced by one driver-motorist. When carrying out hydraulic fracturing, the sand mixing unit is connected to tank trucks and pumping units using flexible hoses. Two tank trucks and four pumping units (two on each side) can be connected to the 4PA unit at the same time.

The 4TSR tank truck is designed to transport fluid used for hydraulic fracturing and supply it to a sand mixing or pumping unit. The 4TSR tank truck (Fig. 5) is mounted on the chassis of a KrAZ-219 vehicle with a lifting force of 120 kN and consists of a tank 1, a vertical plunger pump 2, a pump piping system with fittings 3, a power take-off 4, a transmission unit 5, a rigid towing unit b and spark arrester 7.

The tank is equipped with a special device for heating the liquid with steam. To determine the amount of liquid taken from the tank, a float level indicator is mounted inside it. The liquid is pumped from the tanker using a three-plunger vertical pump with a capacity of 16.7 l/s and a maximum pressure of 2.0 MPa.

The volume of the tank is 9 m3. Depending on the density of the liquid in it, the mass of the tank truck reaches 21,435 kg. Overall dimensions 10100 x 2700 x 2740 mm. The time for heating the fluid from 20° to 50°C is 2 hours. Currently, tank trucks for fracturing fluid with a capacity of 17 m 3 are produced.

coded TsR-20, the tank was mounted on a tractor with a trailer. In addition to a heating device and a vertical pump, the tanker is equipped with a centrifugal pump. pump with a water capacity of 100 l/s with a maximum developed pressure of 0.2 MPa.

To regulate the operation of the entire complex of equipment and unit during hydraulic fracturing, a self-propelled manifold unit type 1BM-700 is used, which consists of pressure and distribution manifolds, a lifting boom and a set of 60 mm tubing pipes with swivel and quick-assembly joints. All equipment of the manifold unit is mounted on the chassis of an off-road truck (ZIL-157K).

The pressure manifold consists of a valve box with six outlets for connection to pumping units; a central pipe with a sensor for instrumentation (pressure gauge, density meter and flow meter) for working with a process monitoring and control station, two bends for connecting to the fittings at the wellhead; plug valves and safety valve. The distribution manifold serves to distribute working fluids (squeezing solution, water, sand-liquid mixture, etc.) to pumping units.

A set of 60 mm pump and compressor pipes is used to connect the pressure manifold to the wellhead and supply pressure solution, water and other liquids to the distribution manifold. To mechanize the loading and unloading of valves at the mouth of the manifold block, there is a rotating boom with manual control.

Fig.5

6. CALCULATION OF HYDRAULIC FRACTURING

1. Calculation of hydraulic fracturing pressure

P razr = R v.g.

– Р pl + s р;

where R v.g. – vertical rock pressure;

Рpl – reservoir pressure;

s р – rock separation pressure. Vertical rock pressure Р v.g.

– determined by the formula:

R v.g. = r p gН,

where H is the depth of the formation;

r p = 2500 kg/m 3 – average density of overlying rocks.

R v.g. = 2500*9.81*2250 = 55.181 MPa

If the rock separation pressure s p = 1.5 MPa, then the formation rupture pressure will be:

P resolution = 55.181 – 17 + 1.5 = 39.681 MPa.

The bottom hole burst pressure can be determined approximately using the empirical formula:

P size = 10 4 * NK,

where K = 1.5 – 2. We take the average value K = 1.75. Then

P resolution = 10 4 * 2250 * 1.75 = 39.375 MPa.

2. Calculation of working wellhead hydraulic fracturing pressure. The permissible wellhead hydraulic fracturing pressure is determined by the formula:

R d.u =

- rgH + P tr,

where l is the coefficient of hydraulic resistance of pipes, determined from the ratio l = 0.3164/Re 0.5 for turbulent or l = 64/Re for laminar modes of fluid movement in a pipe. Here Re (Reynolds number) is a parameter that determines the flow regime; at Re<2300 поток считается ламинарным, а при

Re >2300 turbulent.

Re = ndr cm /m cm

where m cm is the viscosity of the sand-liquid mixture:

m cm =90*e 3.18*0.091 = 120 mPa*s;

n - speed of fluid movement through pipes, m/s is determined from the expression

where Q is the rate of injection of hydraulic fracturing fluid, m 3 /day (0.015 m 3 /day),

F – tubing internal cross-sectional area:

F = pD B 2 /4 = 3.14 * 0.144 2 /4 = 0.0162, m 2.

Fluid speed:

n = 0.015/0.0162 = 0.926 m/s.

r cm = (r p - r l)C + r l – mixture density (oil + sand),

C = C 0 /(C 0 +r p) - volumetric sand content, C 0 – sand concentration,

C = 250/(250+2500) = 0.091

r cm = (2500-895)*0.091 + 895 = 1041 kg/m 3

Reynolds number:

Re = 0.926*0.144*1041/(120*10 -3) = 1156.76 then l = 64/ Re = 0.055

Pressure loss due to friction in pipes

R tr = 0.055*(1041*0.926 2 *2250)/(2*9.81*0.144) = 0.039 MPa.

Therefore, the permissible wellhead pressure is:

R d.u. = (0.173 2 -0.144 2)/(0.173 2 +0.144 2)*(650/1.75)+17-1041*9.81*2250*10 -6 =

The permissible pressure at the wellhead, depending on the strength of the threads of the upper part of the pipe string against shear forces, is determined by the formula

where P str is the shear load for casing pipes made of steel of strength group L, equal to 1.59 MN,

G – tightening force when tying the casing (taken according to the drilling log), equal to 0.5 MN; k – safety factor, which is taken equal to 1.5. Then the permissible wellhead pressure is:

R d.u. =

34.4 MPa.

From the obtained two values ​​of P d.u.

we accept the smaller one (34.4 MPa).

Possible bottomhole pressure at an allowable wellhead pressure of 34.4 MPa will be:

R z = R d.u.

+ rGН – P tr = 34.4*10 6 + 1041*9.81*2250 – 0.039*10 6 = 57.34 MPa

Taking into account that the required rupture pressure at the bottom P raz = 39.375 MPa is less than R z = 57.34 MPa, we determine the working pressure at the wellhead

The amount of fracturing fluid cannot be accurately calculated. It depends on the viscosity of the fracturing fluid and filterability, the permeability of the rocks in the bottomhole zone of the well, the rate of fluid injection and the fracturing pressure. According to experimental data, the volume of fracturing fluid varies from 5 to 10 m 3 . Let us assume for our well V p = 7.5 m 3 of oil.

The amount of sand-carrying liquid depends on the properties of this liquid, the amount of sand pumped into the formation and its concentration. In practice, 20 - 50 m 3 of liquid (V l) and 8 - 10 tons of sand (G sand) are prepared.

The sand concentration C depends on the viscosity of the sand carrier fluid and the rate of its injection. For oil with a viscosity of 90 mPa*s, we take C = 250 kg/m3. Under this condition, the volume of sand carrier liquid:

V pz = G pes / C = 8000/250 = 32 m 3.

The volume of sand-carrying liquid should be slightly less than the capacity of the pipe string, since when this liquid is pumped in a volume exceeding the capacity of the column, the pumps at the end of the injection process will operate at high pressure necessary to force sand into the cracks. And injection of liquid with abrasive particles at high pressures leads to very rapid wear of the cylinders and valves of the pumps.

The capacity of a 168 - mm casing string with a length of 1800 m is 34 m 3, and the accepted amount of sand carrier fluid is 29 m 3

The optimal sand concentration can be determined based on the falling speed of sand grains in the adopted working fluid using the formula

Where C is the concentration of sand, kg/m3;

n - the falling speed of sand grains with a diameter of 0.8 mm in m/h depending on the viscosity of the liquid is found graphically. For a sand carrier fluid viscosity of 90 MPa*s n = 15 m/h, therefore

C = 4000/15 = 267 kg/m3.

G = 267*29 = 7743 kg.

To avoid leaving sand at the bottom, the volume of the displacement fluid should be 1.2 - 1.3 greater than the volume of the column through which sand is pumped. Required volume of displacement fluid:

V pr = =3.14*0.144^2*2250*1.3/4 =47.6 m 3

4. Timing of hydraulic fracturing

T = (V r +V zhp +Vpr)\ Q =(7.5+32+47.6)/ 1500=0.06 days

Where Q is the daily flow rate of working fluid, m³

5. Horizontal crack radius

rt=c(Q√(10^-9*μ*tр)/κ)^0.5,m

where c is an empirical coefficient depending on rock pressure (c = 0.02);

Q - fracturing fluid flow rate; μ-viscosity of the fracturing fluid; tр-download time;

K-permeability of the rock.

rt=0.02*(1020√(10^-9*0.05*7.2)/75*10^-15)^0.5=5.3m

6. Horizontal fracture permeability

Kt=ω^2/10^4*12,

where ω is the width of the crack (ω = 0.1 cm).

Kt=0.1^2/10^4*12=83.3*10^-9 m².

7. Permeability of the bottomhole zone

Kp.z=(kp*h+kt*ω)/(h+ω),

where kp is the permeability of the formation, h is the effective thickness of the formation (h = 22 m), ω = 0.001 m.

KP.Z=(75*10^-15*22+83.33*10^-9*0.001)/(22+0.001)=3.8*10^-12m²

8. Permeability of the entire drainage system

Kd.s=[kp*kp.z*lg(Rk/rc)]/(kp.z*lg(Rk/rT)+kp*lg(rT/rc))

where Rk is the radius of the well supply circuit (Rк = 250m), rc is the radius of the well bottom

(rc=0.075m), rt-crack radius, (rt=5.3m)

cd.s=/=1.5*10^-13m².

9. Well production after hydraulic fracturing

Q=(2π*cd.c*h* p)/(μ*log(Rк/rt)

where Q is the maximum flow rate, m³/s; kd.s - formation permeability after hydraulic fracturing, h - effective thickness of the formation, Δр - depression at the bottom, Δр = rpl - рз, (Δр = 2.8 MPa), μ - dynamic viscosity of oil, (μ = 1sPs * s).

Q=(2*3.14*1.5*10^-13*22*2.8*10^6)/(10^-2*lg(250/5.3))=34.7*10^-4m³/s

10. Number of pumping units

where qag=5.1l/s is the productivity of one unit at the second speed at

p=18.2 MPa (CA-400)

N=(17/5.1)+1=4.3~5

11. Efficiency of hydraulic fracturing

The expected effect of hydraulic fracturing can be preliminarily determined using the approximate formula of G.K. Maksimovich, in which the well radius rc after hydraulic fracturing is assumed to be equal to the fracture radius rt.

n=Q2/Q1=lg(Rк/rс)/log(Rк/rt)

where Q1 and Q2 are well production rates before and after hydraulic fracturing, respectively, Rк=250 m,

rc=0.075m, rt=5.3m.

n=lg(250/0.075)/lg(250/5.3)=2.1(times).

The actual efficiency may be slightly lower, since when the fluid moves through cracks filled with sand, small pressure losses are observed that are not taken into account by the formula.

CONCLUSION

In the course of the calculations of hydraulic fracturing, it can be said that with the correct choice of components: the composition of the fracturing fluid (the concentration of the sand carrier fluid, formation fluid, their viscosity, the granulometric composition of the sand), high-quality equipment: sand mixing units, piping and wellhead equipment, the choice of packers for their correct use It can be noted, based on calculations, that with hydrodynamic fracturing, the productivity of the well, the permeability of the formation increases, the drainage zone expands, which makes it possible to increase the flow rates of wells, after hydraulic fracturing, almost twice under the same other conditions.

LIST OF REFERENCES USED

1. A.M. Yurchuk, A.Z. Istomin, “Calculations in oil production”, Moscow, “Nedra”

2. P.M. Usachev, “Hydraulic fracturing” Moscow, “Nedra”, 1986, 165 p.

3. I.M. Muravyov, R.S. Andriasov, Sh.K. Gimatudinov, V.T. Polozkov “Development and operation of oil fields”, Moscow, “Nedra” 1970, 445 p.

Introduction

1. Hydraulic fracturing as a means of maintaining well productivity

2. The essence of the hydraulic fracturing method

2.1 Hydraulic fracturing

2.2 Hydraulic fracturing tools

3 Technology and equipment for hydraulic fracturing

4 Selection of hydraulic fracturing technology

5 Equipment used during hydraulic fracturing

6 Example of hydraulic fracturing calculation

Conclusion

List of used literature

INTRODUCTION

Oil extraction from the reservoir and any impact on it is carried out through wells. The bottomhole zone of the well (BZZ) is the area in which all processes occur most intensively. Here, as if in a single unit, current lines converge when extracting liquid or diverge during injection. The efficiency of field development, production flow rates, injection capacity, and the portion of reservoir energy that can be used to lift fluid directly in the well depend significantly on the state of the bottomhole zone of the formation.

Mechanical impact methods are effective in hard rocks, when the creation of additional cracks in the CZ makes it possible to introduce new remote parts of the formation to the filtration process.

One of the most common methods for intensifying oil production or gas recovery is hydraulic fracturing (HF).

It is used to create new fractures, both artificial and to expand old (natural) ones, in order to improve connectivity with the wellbore and increase the system of fractures or channels to facilitate inflow and reduce energy losses in this limited area of ​​the formation.

Hydraulic fracturing is carried out at pressures reaching up to 100 MPa, with high fluid flow and using complex and varied equipment.

1. HYDRAULIC FRACTURING AS A MEANS OF MAINTAINING WELL PRODUCTIVITY

The essence of the hydraulic fracturing method is that high pressures are created at the bottom of the well by injecting a viscous fluid, exceeding reservoir pressure by 1.5-2 times, as a result of which the formation stratifies and cracks form in it.

Field practice shows that the productivity of wells after hydraulic fracturing sometimes increases several tens of times. This indicates that the formed cracks are connected to pre-existing ones, and the influx of fluid to the well occurs from remote highly productive zones isolated from the well before the formation rupture. The opening of natural or formation of artificial cracks in the formation is judged by graphs of changes in flow rate Q and pressure P during the process. The formation of artificial fractures in the graph is characterized by a drop in pressure at a constant injection rate, and when natural fractures open, the flow rate of the fracturing fluid increases disproportionately to the increase in pressure.

Hydraulic fracturing is carried out to maintain well productivity, as practice has shown that hydraulic fracturing is more profitable than constructing a new well, both from an economic and development point of view. But carrying out hydraulic fracturing requires a very careful study of the thermodynamic conditions and state of the wellbore zone, the composition of rocks and fluids, as well as a systematic study of the accumulated field experience in a given field. Hydraulic fracturing is recommended in the following wells:

1. Those that gave a weak influx during testing

2. With high reservoir pressure, but with low reservoir permeability

3. With a contaminated bottomhole zone

4. With reduced productivity

5. With a high gas factor (compared to others)

6. Low-injection injection pumps

7. Pressure to expand the absorption interval

The purpose of hydraulic fracturing is to increase the productivity of wells, with an impact on the bottomhole zone of the well - changing the properties of the porous medium and liquid (the properties of the porous medium change during hydraulic fracturing due to the formation of a system of cracks).

Let us assume that we associate the success or failure of hydraulic fracturing with two factors: the previous well flow rate and the thickness of the formation. In reality, the effectiveness of hydraulic fracturing depends, of course, not on two, but on many factors: the pressure of the injected fluid, the injection rate, the percentage of sand in this fluid, etc.

2. ESSENCE OF THE FRACTURING METHOD

Hydraulic fracturing of the formation is carried out as follows: liquid is pumped into the permeable formation at a pressure of up to 100 MPa, under the influence of which the formation is split, either along bedding planes or along natural cracks. To prevent the cracks from closing when the pressure is removed, coarse sand is pumped into them along with the liquid, which maintains the permeability of these cracks, which is a thousand times greater than the permeability of the undisturbed formation.

To prevent the closure of cracks formed in the formation and to keep them open after the pressure is reduced below the burst pressure, sorted coarse-grained quartz sand is injected into the cracks formed along with the liquid. Sand supply is required both into newly created and existing cracks in the formation opened during hydraulic fracturing. Studies show that during hydraulic fracturing, cracks with a width of 1-2 mm appear. Their radius can reach several tens of meters. Fractures filled with coarse sand have significant permeability, as a result of which, after hydraulic fracturing, the productivity of the well increases several times.

Hydraulic fracturing (HF) is carried out to form new or open existing cracks in order to increase the permeability of the bottomhole zone of the formation and increase the productivity of the well.

Hydraulic fracturing is achieved by injecting fluid into the formation under high pressure. To prevent closure after the end of the operation and reduce the pressure to the initial one, porous material is pumped into them along with the liquid - quartz sand, corundum.

One of the most important parameters for hydraulic fracturing is the hydraulic fracturing pressure at which cracks form in the rock. Under ideal conditions, the opening pressure pp should be less than the rock pressure pp created by the overlying rock mass. However, in real conditions the inequality rg * rn may be satisfied< рр, что объясняется наличием в пласте глинистых пропластков, обладающих пластичными свойствами. В процессе бурения, когда цикл скважины не обсажен, под действием веса вышележащих пород может произойти выдавливание глины из пласта в скважины и частичное разгружение пласта, расположенного под глинистыми пропластками, что и приводит к снижению давления гидроразрыва.

Thus, the burst pressure depends on the drilling process preceding the well operation. Therefore, the burst pressure cannot be calculated. However, with similar technologies for drilling wells in a given area, we can talk about the average fracturing pressure, determining it from hydraulic fracturing data in neighboring wells.

2.1 Hydraulic fracturing

Hydraulic fracturing is carried out using the following technology. First, fracturing fluid is pumped under high pressure. After the formation is ruptured, liquid with sand is pumped in to fix the cracks. Typically, both the fracturing fluid and the sand-carrying fluid when treating production wells are prepared on a hydrocarbon basis, and when treating heating wells - on a water basis. As a rule, various emulsions, as well as hydrocarbon liquids and aqueous solutions are used for these purposes. The sand concentration in the sand carrier fluid usually ranges from 100 to 500 kg/m3 and depends on its filterability and holding capacity.

The mechanism of hydraulic fracturing of a formation, i.e. the mechanism of formation of cracks in it, can be presented as follows. All rocks that make up a particular layer have natural microcracks, which are in a compressed state under the influence of the weight of the overlying rock mass or, as it is commonly called, rock pressure. The permeability of such cracks is small. All rocks have some strength. Therefore, in order to form new cracks in the formation and expand existing ones, it is necessary to remove the stresses created by rock pressure in the formation rocks and overcome the tensile strength of the rocks.

The burst pressure, even within one formation, is not constant and can vary widely. Practice has confirmed that in most cases the burst pressure Pp at the bottom of the well is lower than the rock pressure and amounts to (15...25) * N, kPa (1.5...2.5 kgf/cm2).

Here H is the depth of the well in m.

For low-permeability rocks, this pressure can be achieved by injecting low-viscosity fracturing fluids at limited injection rates. If the rocks are highly permeable, a high injection rate is required, and if the injection rate is limited, it is necessary to use fluids of high viscosity. Finally, in order to achieve burst pressure in the case of particularly high permeability of the formation rocks, even higher injection rates of high-viscosity fluids should be used. The hydraulic fracturing process consists of the following sequential operations: 1) injection of fracturing fluid into the formation to form cracks; 2) injection of sand-carrying fluid with sand intended for fixing cracks; 3) injection of squeezing fluid to force sand into cracks.

2.2 Hydraulic fracturing tools

Typically, the same fluid is used as fracturing fluid and sand-carrying fluid, so they are combined under one name - fracturing fluid. For hydraulic fracturing, various working fluids are used, which, according to their physicochemical properties, can be divided into two groups: hydrocarbon-based fluids and water-based fluids.

High-viscosity oil, fuel oil, diesel fuel or kerosene thickened with naphthenic soaps are used as hydrocarbon liquids.

Solutions used in injection wells include: an aqueous solution of sulfite and alcohol stillage, solutions of hydrochloric acid, water thickened with various reagents, as well as thickened solutions of hydrochloric acid.

The fracturing process is highly dependent on the physical properties of the fracturing fluid and, in particular, the viscosity, filterability and ability to hold sand grains in suspension.

The following requirements apply to the fracturing fluid. Firstly, it must be highly viscous so that it does not quickly penetrate deep into the formation, otherwise the increase in pressure near the well will be insufficient. Secondly, if there are several productive layers in the well section, it is necessary to ensure as uniform an injectivity profile as possible. Newtonian fluids are not suitable for this, since the amount of fluid entering each layer will be proportional to its permeability. Therefore, highly permeable layers will be better processed and, consequently, the effect of hydraulic fracturing will be reduced. For hydraulic fracturing, it is necessary to use a fluid whose viscosity depends on the filtration rate. If viscosity increases with increasing filtration rate, then when moving in a highly permeable interlayer, the viscosity of the liquid will be higher than in a low-permeable one. As a result, the pickup profile becomes more uniform. Viscoelastic fluids have a similar filtration characteristic, the filtration law for which can be written in the form.

V=(kDp)/(mk L),……………………………………………………….................(1)

where mk is the apparent viscosity, determined by the formula

mk/mo = 1 + A Dp/L,……………………………………………………….(2)

mo is the maximum apparent viscosity of the liquid at v ® 0; A is a constant depending on the viscoelastic properties of the fluid (at A=0 we obtain Darcy’s law).

2.3 Necessary parameters for hydraulic fracturing

When pumping liquid into two layers with permeabilities k1 and k2, the ratio of mobilities at the same pressure gradients is equal to

(k/mk)1: (k/mk)2 = k1 /k2 * (1+A (Dp/L)*)/1+A(Dp/L)*),…….(3)

Let, for example, A(Dp/L)*) =2

Then at k1 /k2 =25 A (Dp/L)*=0.4

And the mobility ratio is approximately 11.7 instead of 25.

For hydraulic fracturing, pipes are lowered into the well, through which the Liquid enters the formation. To protect the casing from high pressures, a packer is installed above the fractured formation, and a hydraulic anchor is installed above it to increase the tightness. Under the influence of pressure, the armature pistons move apart and are pressed against the casing, preventing the packer from moving.

With a very low viscosity of the fracturing fluid, achieving the fracturing pressure requires pumping a large volume of fluid into the formation, which is associated with the need to use several simultaneously operating pumping units.

When the viscosity of the fracturing fluid is high, high pressures are required for crack formation. Depending on the permeability of the rocks, the optimal viscosity of the fracturing fluid ranges from 50-500 cP. Sometimes when pumping through a casing, a fluid with a viscosity of up to 1000 cP and even up to 2000 cP is used.

The fracturing fluid must be low-filtration and have a high holding capacity for sand suspended in it, which prevents the possibility of its settling in the pump cylinders, piping elements, pipes and at the bottom of the well.

In this case, maintaining a constant concentration of sand in the fracture fluid and good conditions for its transfer into the depths of the crack are achieved. Filterability is checked using a device to determine the fluid loss of a clay solution. Filterability is considered low if it is less than 10 cm3 of liquid in 30 minutes.

The ability of a fracturing fluid to hold sand in suspension is directly related to its viscosity.

More viscous liquids, such as fuel oils, have satisfactory viscosity at temperatures below 20°C; crude oils and water have low viscosity, are generally well filtered, and are not recommended for use in pure form in hydraulic fracturing.

An increase in viscosity, as well as a decrease in the filterability of fluids used in hydraulic fracturing, is achieved by introducing appropriate thickeners into them. Such thickeners for hydrocarbon liquids are salts of organic acids, high-molecular and colloidal compounds of oils (for example, oil tar) and other oil refining wastes.

Some oils, kerosene-acid, oil-acid, and water-oil emulsions have significant viscosity and high sand-carrying ability. These fluids are used as fracturing fluids and sand-carrying fluids for fracturing oil wells.

In injection wells, hydraulic fracturing uses thickened water. For thickening, sulfite-alcohol stillage (SSB) and other cellulose derivatives, which are highly soluble in water and have low filterability, are used.

Depending on the concentration of dry substances, SSB is of two types - liquid and solid. The viscosity of the initial liquid concentrate is 1500-1800 cP. The addition of water to SSB solutions leads to a rapid decrease in viscosity and promotes good washing of SSB with water from the porous space and restoration of injectivity. The SSB solution has good retention capacity and low filterability. For rupture, a solution of SSB with a viscosity of 250-800 cP is mainly used.

Recently, concentrated hydrochloric acid thickened with SSB (40% HCl and 60% SSB) has been used as a sand-carrying liquid. The use of such a fracturing fluid makes it possible to combine the hydraulic fracturing process with chemical impact on the bottomhole zone. When mixed with SSB, hydrochloric acid reacts slowly with carbonates (2-2.5 hours versus 30-40 minutes when using a pure HCl solution). This makes it possible to push chemically active hydrochloric acid deep into the formation along cracks formed during hydraulic fracturing and treat the bottom-hole zone of the formation at a great distance from the wellbore.

During hydraulic fracturing under conditions of high reservoir temperatures (130-150°C), the viscosity of 20- and 24% SSB solutions sharply decreases to 8-0.6 cP with an increase in temperature to 90°C.

At higher temperatures, the viscosity of these solutions approaches the viscosity properties of water. Therefore, as an effective fracturing fluid and sand carrier, which has good sand-holding ability and low filterability, aqueous solutions of CMC-500 (carboxymethylcellulose) are used in the range of 1.5-2.5% with the addition of sometimes sodium chloride up to 20-25%. Under all conditions, the displacement fluid must have a minimum viscosity in order to reduce pressure losses during pumping.

The purpose of filling cracks with sand is to prevent them from closing and keep them open after the pressure is removed below the burst pressure. Therefore, the following requirements are imposed on sand:

1) the sand must have sufficient mechanical strength so as not to collapse in cracks under the influence of the weight of the rock;

2) maintain high permeability.

Well-rolled homogeneous quartz sand satisfies these requirements.

Sand of the following fractions is used: 0.25-0.4 mm; 0.4-0.63; 0.63-0.79; 0.79-1.0; 1.0-1.6MM. The most acceptable fraction for hydraulic fracturing is sand with a grain size from 0.5 to 1.0 mm.

The degree of effectiveness of hydraulic fracturing is determined by the diameter and extent of the fractures created and therefore the increased permeability. The larger the diameter and length of the cracks, the higher the processing efficiency. The creation of long-term fractures is achieved by pumping large quantities of sand. In practice, from 4 to 20 tons of sand are pumped into the well. The concentration of sand in the sand carrier fluid depends on the filterability and holding capacity of the fluid and ranges from 100 to 600 kg per 1 m3 of fluid.

3. TECHNOLOGY AND TECHNIQUE FOR FRAFTING

Hydraulic fracturing is carried out in formations with different permeability in the event of a drop in flow rate or injectivity of injection wells.

Before hydraulic fracturing, a well is tested for inflow, its absorption capacity and absorption pressure are determined. For this purpose, oil is pumped with one unit until a certain excess pressure is obtained at the wellhead, at which the well begins to accept liquid. The flow rate is measured for 10-20 minutes at a constant discharge pressure. After connecting the second unit and increasing the amount of pumped liquid, the pressure is raised by 2-3 MPa and the flow rate is determined again.

The process of increasing fluid flow and pressure is repeated several times, and at the end of the study, the maximum possible pressure is created, at which the flow is measured again. Based on the data obtained, a curve is drawn to plot the dependence of the well's injectivity on the injection pressure. Based on the data on the absorption capacity of the well before and after fracturing, the amount of fluid and pressure required to carry out the fracturing is determined, and the quality of the fracturing and changes in the permeability of the near-wellbore zone formations after the fracturing are judged. The formation rupture pressure is conventionally taken to be the pressure at which the well's injectivity coefficient increases by 3-4 times compared to the initial one.

The bottom of the well is cleaned of dirt by drainage and then washed. In some cases, to increase the filtration properties of formations, it is recommended to pre-treat the well with hydrochloric or mud acid and carry out additional perforation. The implementation of these measures helps to reduce the burst pressure and increase its efficiency.

After washing, cleaning and checking with a special template, pump and compressor pipes with a diameter of 75 or 100 mm are lowered into the well, through which the fracturing fluid is pumped. To protect the casing from exposure to high pressure, a packer is installed above the fractured formation, which separates the filter zone of the formation from its overlying part. Due to this, the pressure created by the pumps is transmitted only to the filter zone and to the lower surface of the packer.

Various packer designs are used. The most common are slip packers, produced for various diameters of production strings and designed for a pressure of 50 MPa (Fig. 1).

Sealing of the casing is carried out by deformation of the rubber sealing collars from the weight of the tubing string when the cone is supported on the slips of the packer, which is centered by a lantern. The locking device of the lantern opens when the lantern rubs against the walls of the casing pipes during packer rotation.

The axial load during hydraulic fracturing is perceived by the packer head with a support ring and is transmitted to the anchor, which holds the packer and tubing string from moving upward. The packer head has a left-hand thread at the junction with the anchor.

In case of jamming of the cuffs in the casing, the anchor can be unscrewed from the packer by right rotation and raised to the surface.

The design of the ram hydraulic action is shown in Fig. 2

During the process of pumping working fluid for hydraulic fracturing, the pressure difference created between the inside of the anchor and the annular gap in the production string deforms the rubber tube, pushing the rams all the way into the column wall. The rams, cutting into the walls of the pipes with their sharp teeth, keep the anchor and, accordingly, the packer from being pushed up the well.

Along with slip packers, self-sealing PS packers are used. In this design, sealing is achieved by self-sealing rubber cuffs under the influence of fracturing fluid.

Unlike other types of packers, the PS packer design includes a bypass valve designed to bypass hydraulic fracturing fluid into the annulus during packer lowering, thereby relieving pressure on the self-sealing collars. The bypass valve is connected through a sub and installed above the hydraulic armature.

After running the pipes with a packer and anchor, the wellhead is equipped with a special head, to which units are connected to inject fracturing fluid into the well.

3.1 Piping and equipment for hydraulic fracturing

Figure 2 shows a general diagram of the piping and arrangement of equipment for hydraulic fracturing. At the first stage, fracturing fluid is pumped in by pumping units, as a result of which the pressure gradually increases and, upon reaching a certain value, the formation ruptures. The moment of rupture is judged by the pressure gauge on the flow line. This moment is characterized by a sharp drop in pressure and increased flow of injected liquid.

After fracturing the formation, they proceed to the second stage - supplying sand-carrying fluid with sand into the crack at high flow rates and high injection pressure. The sand-carrying fluid with sand is pressed into the crack with a squeezing fluid at maximum pressure and at maximum injection speed. This is achieved by connecting the largest number of units. Oil is used as a displacement fluid for oil wells and water is used for injection wells. The amount of this liquid must be equal to the capacity of the pipe string. Injecting displacement fluid is the last, third stage of the continuous hydraulic fracturing process.

After forcing, the wellhead is closed and the well is left alone until the wellhead pressure drops to zero. Then the well is washed, cleared of sand and development begins.

Of interest is the technique of hydraulic fracturing in wells whose productive horizons lie at depths of 2800-3400 m. The technology of formation fracturing in such wells differs from the usual one in that the hydraulic fracturing process takes place under constant back pressure on the tubing and on the upper end of the rubber element of the packer. The value of back pressure is determined as the difference between the calculated value of hydraulic fracturing pressure and the maximum permissible pressure on the packer. For such wells, the working pressure in the annular space (annulus) is determined experimentally. An auxiliary unit is used to pump up the fracturing fluid. Features of the arrangement of equipment and piping of the wellhead during hydraulic fracturing using this technology are shown in Fig. 3

It is recommended to carry out hydraulic fracturing work on a well in the following sequence. The surface equipment is pressurized to a pressure of 70 MPa and the water in the well is replaced with oil, after which the packer is lowered. Then, using pumping units used for hydraulic fracturing, the maximum possible pressure is created by pumping liquid in the tubing and under the packer. By pumping liquid with an auxiliary cementing unit, the pressure in the annular space (annulus) is raised and the well is left alone for 30 minutes. This at the first stage allows for the formation of cracks in the formation.

At the second stage, an operation is carried out to fix the cracks with sand. After testing the well for injectivity, a sand-carrying liquid is pumped into the formation.

Rice. 3. Equipment piping diagram for hydraulic fracturing in deep wells:

1 - sand mixer; 2 - unit TsA-400; 3- unit CHAN-700;

4 - auxiliary unit; 5 - container for working fluids

The pressure at the wellhead during injection and forcing into the formation can increase to 60-80 MPa. Hydraulic fracturing using this technology can significantly increase well productivity.

If there is a large filter zone in the wells or several exposed productive layers, multiple interval hydraulic fracturing is performed.

Recently, a new method of interval hydraulic fracturing has been developed and implemented, which makes it possible to carry out hydraulic fracturing of certain formations in any sequence in one run of downhole equipment. When carrying out hydraulic fracturing using this technology in one layer, the perforated holes against the overlying layers are covered with sinking ones, and against the underlying layers - with elastic balls floating in the fracturing fluid. The downhole equipment used is simple in design and can be manufactured in field workshops. It consists of two hollow cylinders, coaxially mounted on pump and compressor pipes. The cylinder with holes in the bottom is open at the top, and the cylinder with holes in the lid is open at the bottom. The pipe on which the cylinders are placed and welded is plugged from below and has holes above the lower cylinder.

Preparatory work for interval hydraulic fracturing is carried out in the following sequence. Cylinders, a packer and an anchor are lowered into the well using tubing. Special elastic balls with a diameter of 18-20 mm with a specific gravity lower than that of fluids used in hydraulic fracturing (floating balls) are placed under the lower cylinder; therefore, in the liquid they will always be pressed against the cover of the lower cylinder. The diameter of the cylinder is selected so that the balls cannot get into the gap between it and the production string. The number of balls loaded into the lower cylinder is slightly greater than the number of perforations located below the uppermost interval targeted for fracturing.

Sinking balls are placed in the upper cylinder. Moreover, their number should also be greater than the number of holes located above the lower interval planned for hydraulic fracturing. To prevent the balls from falling under the packer when going down or when the column is not sealed, a special disc-breaker is installed. The packer is installed in such a way that the interval intended for hydraulic fracturing is located between the cylinders with balls. After this, hydraulic fracturing of the targeted formation is carried out in the usual way. If, during a rupture, the above or underlying layers begin to accept liquid, then their perforation holes are blocked by balls, which are carried away by the fluid flow from the cylinders to these holes. Thus, hydraulic fracturing will occur only in the intended interval. After the injection stops, the balls, due to the corresponding difference in their specific gravities, will be collected in their cylinders. By raising or lowering the equipment and placing cylinders with balls at the desired interval, it is possible to hydraulically fracture any formation.

4. SELECTION OF FRACTURING TECHNOLOGY

Hydraulic fracturing technology is carried out as follows. Since during hydraulic fracturing in most cases (with the exception of small wells) pressures arise that exceed those permissible for casing strings, tubing capable of withstanding this pressure is first lowered into the well. Above the roof of the formation or interlayer in which it is planned to rupture, a packer is installed that isolates the annular space and the string from pressure, and a device that prevents its displacement and is called an anchor. First, fracturing fluid is injected through lowered tubing in such volumes as to obtain at the bottom hole pressure sufficient to fracturing the formation. The moment of rupture on the surface is noted as a sharp increase in fluid flow (absorption capacity of the well) at the same pressure at the wellhead or as a sharp decrease in pressure at the wellhead at the same flow rate. Rock pressure is equal to:

Рг = rПgН (4)

The adhesion force of rock particles is equal to:

Рр = Рг + sZ (5)

a more objective indicator characterizing the moment of hydraulic fracturing is the absorption capacity coefficient

kп = Q/(pз – рп) (6)

where Q is the flow rate of the injected liquid;

рп-reservoir pressure in the area of ​​a given well;

rz-pressure at the bottom of the well during hydraulic fracturing.

During hydraulic fracturing there is a sharp increase in kp. However, due to the difficulties associated with continuous monitoring of the value of рз, and also due to the fact that the pressure distribution in the formation is a significantly unsteady process, the hydraulic fracturing moment is judged by the conditional coefficient k.

where p is the pressure at the wellhead.

A sharp increase in k during the injection process is also interpreted as the hydraulic fracturing moment. Instruments are available to measure this value.

After fracturing the formation, a sand-carrying liquid is pumped into the well at pressures that keep the cracks formed in the formation in an open state. This is a more viscous liquid mixed (180-350 kg of sand per 1 m3 of liquid) with sand or other filler. Sand is introduced into the open cracks to the greatest possible depth to prevent the cracks from closing during the subsequent release of pressure and the well being put into operation. Sand-carrying fluids are pushed into the tubing and into the formation using a displacement fluid, which is any low-viscosity, non-deficient fluid.

To design the hydraulic fracturing process, it is very important to determine the burst pressure pp that needs to be created at the bottom of the well.

A large amount of statistical material has been accumulated on the value of formation rupture pressure pp in various fields of the world and at different well depths, which indicates the absence of a clear connection between the formation depth and rupture pressure. However, all actual pp values ​​lie within the range between the values ​​of the total rock and hydrostatic pressures. Moreover, at shallow depths (less than 1000 m), pp is closer to rock pressure and at greater depths - to hydrostatic pressure.

for shallow wells (up to 1000 m)

рр = (1.74 - 2.57) ррст,………………………………………………………(8)

for deep wells (H > 1000m)

рр =(1.32 - 1.97) ррст,…………………………………………….(9)

where pst is the hydrostatic pressure of the liquid column, the height of which is equal to the depth of the formation.

The tensile strength of rocks is usually low and lies in the range sp = 1.5 ... 3 MPa, so it does not significantly affect pp.

The rupture pressure at the bottom PP and the pressure at the wellhead RU are related by the obvious relationship

pp = ru + rst – rtr,……………………………………………………………………........(10)

where ррр – pressure loss due to friction in the tubing.

From equation (10) it follows:

ru = pp + rtr - rst,………………………………………….....(11)

pst - static pressure, determined taking into account the curvature of the well

рст = rж g Н cos b,……………………………………………………………(12)

where H is the depth of the well; b - angle of curvature (averaged);

rf is the density of the liquid in the well, and if the liquid contains filler (sand, glass beads, polymer powder, etc.), then the density is calculated as a weighted average

r=rzh(1–n/rn)+n,……………………………………………………………………(13)

where n is the number of kilograms of filler in 1m3 of liquid;

pH-density of the filler (for sand pH=2650 kg/m3).

Friction losses are more difficult to determine, since the fluids used sometimes have non-Newtonian properties. The presence of filler (sand) in the liquid increases friction losses.

In American practice, various graphs of pressure loss due to friction are used for every 100 feet of tubing of different diameters when pumping various liquids with a given volumetric flow rate. At high injection rates corresponding to turbulent flow, the structural properties of the fluids used (with various thickeners and chemical reagents) usually disappear, and the friction losses for these fluids can be determined fairly approximately using the usual formulas of pipe hydraulics.

rtr = l(N/d) * (w2/2g) * rga,…………………………………………....(14)

where l is the friction coefficient, determined by the corresponding formulas depending on the Reynolds number;

w - linear flow velocity in the tubing;

d – internal diameter of the tubing; r - fluid density, N - tubing length;

g = 9.81 m/s2; a is a correction factor that takes into account the presence of a filler in the liquid (for pure water a = 1) and depends on its concentration.

5. EQUIPMENT USED FOR fracturing

When hydraulic fracturing, a whole complex of surface equipment is used: pumping units of the 2AN-500 or 4AN-700 type, a 4PA sand mixing unit. To transport fracturing fluid, 4TSR or TsR-20 tank trucks are used.

The 4AN-700 unit designed by Azinmash is the main one in the set of ground equipment. It features increased power and performance and is easy to use. The operating pressure of the unit allows for hydraulic fracturing and hydrosandblasting processes in deep wells. All its components are mounted on a KrAZ-257 three-axle truck with a lifting force of 100-120 kN and consist of the following: power plant; gearbox; triple plunger pump; manifold, control system.

On the frame of the car, directly behind the driver’s cabin, there is a power plant of the unit, consisting of an engine with a multi-disc friction clutch and a centrifugal fan, power systems, lubrication and cooling, an air cleaner installation and other auxiliary components.

The engine of the unit is a twelve-cylinder, four-stroke diesel engine with a power of 588 kW at a crankshaft speed of 2000 rpm. The engine is connected to the transmission input shaft using a multi-plate friction clutch.

Pump 4R-700 is a three-plunger, horizontal, single-acting pump. The plungers are provided in sizes of 100 and 120 mm, which ensures operation of the pump at pressures of up to 70 and 50 MPa, respectively. The productivity of the unit at a pressure of 70 MPa is 6.3 l/s and at 20 MPa - 22 l/s. Unit weight 20200 kg, overall dimensions 9800 x 2900 x 3320 mm. The unit is controlled from a central console located in the vehicle's cabin, where the control pedals for the fuel pump and engine friction clutch, the gearbox control handle and the necessary instrumentation are located.

To transport sand of the required fractions to the well where hydraulic fracturing is planned, and for the subsequent mechanical preparation of the sand-liquid mixture, special sand mixing units of the 4PA type are used.

On the self-propelled chassis of the KrAZ-257 vehicle, a hopper 1 for bulk material with a loading auger 2 and a working auger 3, a hydraulic displacement chamber 5, a mixer 7 with a float level regulator 6, as well as a receiving manifold 11 and a distribution manifold 10 with a pump 9 for pumping sand are mounted . A rotary valve 4 is installed in the upper unloading part of the auger 3, connected to a float regulator 6. Pneumatic vibrators are attached to the walls and bottom of the hopper 1, ensuring reliable flow of bulk material by gravity into the auger 3 receiver.

The loading and working augers, as well as the paddle mixer, are driven by hydraulic motors using an oil pump 8. All units of the installation are controlled from a remote control located in the vehicle cabin.

A sand-liquid mixture with a small concentration of sand is prepared as follows. The liquid through the receiving manifold 11 enters the hydraulic displacement chamber 5, into which bulk material is supplied from hopper 1 by auger 3. The amount of bulk material is regulated by the rotation speed of the working auger and damper 4 using a float level regulator 6, depending on the level of the mixture in mixer 7. The excess amount of bulk material flows back into the hopper through the outlet pipe. In the hydraulic mixing chamber 5, a solution of the required concentration is prepared, which enters the mixer 7, where a uniform sand concentration is maintained using a paddle mixer. From mixer 7, the solution is supplied by sand pump 9 through distribution manifold 10 to the point of consumption.

When preparing a sand-liquid mixture with a high concentration of bulk material, the hydraulic mixing chamber is replaced by a through pipe, and the liquid from the collector 11 and the bulk material from the hopper 1 enter directly into the mixer 7, through a replaceable pipe (indicated by the dotted line). The finished mixture is selected in the same way as in the first case.

Rice. 4. Scheme of the sand mixing unit

Hopper capacity 6.5 m3. The maximum productivity of the working auger (for sand) is 50 t/h, the maximum lifting force is 90 kN, the productivity of the loading auger is 12-15 t/h. The mass of the unit with a load is 23,000 kg, overall dimensions are 8700 x 2625 x 3600 mm. The sand mixing unit is serviced by one driver-motorist. When carrying out hydraulic fracturing, the sand mixing unit is connected to tank trucks and pumping units using flexible hoses. Two tank trucks and four pumping units (two on each side) can be connected to the 4PA unit at the same time.

The 4TSR tank truck is designed to transport fluid used for hydraulic fracturing and supply it to a sand mixing or pumping unit. The 4TSR tank truck (Fig. 5) is mounted on the chassis of a KrAZ-219 vehicle with a lifting force of 120 kN and consists of a tank 1, a vertical plunger pump 2, a pump piping system with fittings 3, a power take-off 4, a transmission unit 5, a rigid towing unit b and spark arrester 7.

The tank is equipped with a special device for heating the liquid with steam. To determine the amount of liquid taken from the tank, a float level indicator is mounted inside it. The liquid is pumped from the tanker using a three-plunger vertical pump with a capacity of 16.7 l/s and a maximum pressure of 2.0 MPa.

Tank volume 9 m3. Depending on the density of the liquid in it, the mass of the tank truck reaches 21,435 kg. Overall dimensions 10100 x 2700 x 2740 mm. The time for heating the fluid from 20° to 50°C is 2 hours. Currently, tank trucks for fracturing fluid with a capacity of 17 m3 are produced. coded TsR-20, the tank was mounted on a tractor with a trailer. In addition to a heating device and a vertical pump, the tanker is equipped with a centrifugal pump. pump with a water capacity of 100 l/s with a maximum developed pressure of 0.2 MPa.

coded TsR-20, the tank was mounted on a tractor with a trailer. In addition to a heating device and a vertical pump, the tanker is equipped with a centrifugal pump. pump with a water capacity of 100 l/s with a maximum developed pressure of 0.2 MPa.

To regulate the operation of the entire complex of equipment and unit during hydraulic fracturing, a self-propelled manifold unit type 1BM-700 is used, which consists of pressure and distribution manifolds, a lifting boom and a set of 60 mm tubing pipes with swivel and quick-assembly joints. All equipment of the manifold unit is mounted on the chassis of an off-road truck (ZIL-157K).

The pressure manifold consists of a valve box with six outlets for connection to pumping units; a central pipe with a sensor for instrumentation (pressure gauge, density meter and flow meter) for working with a process monitoring and control station, two bends for connecting to the fittings at the wellhead; plug valves and safety valve. The distribution manifold serves to distribute working fluids (squeezing solution, water, sand-liquid mixture, etc.) to pumping units.

A set of 60 mm pump and compressor pipes is used to connect the pressure manifold to the wellhead and supply pressure solution, water and other liquids to the distribution manifold. To mechanize the loading and unloading of valves at the mouth of the manifold block, there is a rotating boom with manual control.

6. CALCULATION OF HYDRAULIC FRACTURING

1. Calculation of hydraulic fracturing pressure

Rrazr = Rv.g. – Rpl + sp;

where Rv.g. – vertical rock pressure;

Rpl – reservoir pressure;

sp – rock separation pressure. Vertical rock pressure Rv.g. – determined by the formula:

Rv.g. = rпgН,

– determined by the formula:

rп = 2500 kg/m3 – average density of overlying rocks.

Rv.g. = 2500*9.81*2250 = 55.181 MPa

If the rock separation pressure sp = 1.5 MPa, then the formation rupture pressure will be:

Rres = 55.181 – 17 + 1.5 = 39.681 MPa.

If the rock separation pressure s p = 1.5 MPa, then the formation rupture pressure will be:

Rrazr = 104 * NK,

The bottom hole burst pressure can be determined approximately using the empirical formula:

Rrasr = 104 * 2250 * 1.75 = 39.375 MPa.

where K = 1.5 – 2. We take the average value K = 1.75. Then

P resolution = 10 4 * 2250 * 1.75 = 39.375 MPa.

Рд.у = - rgH + Рtr,

where Dн2, DВ2 are the outer and inner diameters of the casing pipes, m

Dн = 0.173 m DV = 0.144 m; stek = 650 MPa – yield strength of steel grade L; K = 1.5 – safety factor, Рtr = pressure loss due to friction in pipes are determined by the Darcy-Weisbach formula:

where l is the coefficient of hydraulic resistance of pipes, determined from the ratio l = 0.3164/Re0.5 for turbulent or l = 64/Re for laminar modes of fluid movement in a pipe. Here Re (Reynolds number) is a parameter that determines the flow regime; at Re<2300 поток считается ламинарным, а при

Re >2300 turbulent.

Re = ndrsm /mcm

where mcm is the viscosity of the sand-liquid mixture:

mcm=90*e3.18*0.091 = 120 mPa*s;

n - speed of fluid movement through pipes, m/s is determined from the expression

where Q is the rate of injection of hydraulic fracturing fluid, m3/day (0.015 m3/day),

F – tubing internal cross-sectional area:

F = pDB2/4 = 3.14*0.1442/4 = 0.0162, m2.

Fluid speed:

n = 0.015/0.0162 = 0.926 m/s.

rcm = (rp - rl)C + rl – mixture density (oil + sand),

С = С0/(С0+rп) - volumetric sand content, С0 – sand concentration,

rcm = (2500-895)*0.091 + 895 = 1041 kg/m3

Reynolds number:

Re = 0.926*0.144*1041/(120*10-3) = 1156.76 then l = 64/ Re = 0.055

Pressure loss due to friction in pipes

Rtr = 0.055*(1041*0.9262*2250)/(2*9.81*0.144) = 0.039 MPa.

Therefore, the permissible wellhead pressure is:

Rd.u. = (0.1732-0.1442)/(0.1732+0.1442)*(650/1.75)+17-1041*9.81*2250*10-6=

The permissible pressure at the wellhead, depending on the strength of the threads of the upper part of the pipe string against shear forces, is determined by the formula

where Pstr is the shear load for casing pipes made of steel of strength group L, equal to 1.59 MN,

G – tightening force when tying the casing (taken according to the drilling log), equal to 0.5 MN; k – safety factor, which is taken equal to 1.5. Then the permissible wellhead pressure is:

Rd.u. = 34.4 MPa.

From the obtained two values ​​of Рд.у. we accept the smaller one (34.4 MPa).

From the obtained two values ​​of P d.u.

Рз = Рд.у. + rGН – Ptr = 34.4*106 + 1041*9.81*2250 – 0.039*106 = 57.34 MPa

Considering that the required rupture pressure at the bottom Prazr = 39.375 MPa is less than P3 = 57.34 MPa, we determine the working pressure at the wellhead

Ru = Razr - rgH + Rtr = 39.375*106 - 1041*9.81*2250 + 0.039*106 = 16.9 MPa.

+ rGН – P tr = 34.4*10 6 + 1041*9.81*2250 – 0.039*10 6 = 57.34 MPa

Taking into account that the required rupture pressure at the bottom P raz = 39.375 MPa is less than R z = 57.34 MPa, we determine the working pressure at the wellhead

The amount of fracturing fluid cannot be accurately calculated. It depends on the viscosity of the fracturing fluid and filterability, the permeability of the rocks in the bottomhole zone of the well, the rate of fluid injection and the fracturing pressure. According to experimental data, the volume of fracturing fluid varies from 5 to 10 m3. Let us assume for our well Vр = 7.5 m3 of oil.

The amount of sand-carrying liquid depends on the properties of this liquid, the amount of sand pumped into the formation and its concentration. In practice, 20 - 50 m3 of liquid (Vl) and 8 - 10 tons of sand (Gs) are prepared.

The sand concentration C depends on the viscosity of the sand carrier fluid and the rate of its injection. For oil with a viscosity of 90 mPa*s, we take C = 250 kg/m3. Under this condition, the volume of sand carrier liquid:

Vpzh = Gpes/C = 8000/250 = 32 m3.

The volume of sand-carrying liquid should be slightly less than the capacity of the pipe string, since when this liquid is pumped in a volume exceeding the capacity of the column, the pumps at the end of the injection process will operate at high pressure necessary to force sand into the cracks. And injection of liquid with abrasive particles at high pressures leads to very rapid wear of the cylinders and valves of the pumps.

The capacity of a 168-mm casing string with a length of 1800 m is 34 m3, and the accepted amount of sand-carrying fluid is 29 m3

The optimal sand concentration can be determined based on the falling speed of sand grains in the adopted working fluid using the formula

Where C – sand concentration, kg/m3;

n - the falling speed of sand grains with a diameter of 0.8 mm in m/h depending on the viscosity of the liquid is found graphically. For a sand carrier fluid viscosity of 90 MPa*s n = 15 m/h, therefore

C = 4000/15 = 267 kg/m3.

G = 267*29 = 7743 kg.

To avoid leaving sand at the bottom, the volume of the displacement fluid should be 1.2 - 1.3 greater than the volume of the column through which sand is pumped. Required volume of displacement fluid:

Vpr = =3.14*0.144^2*2250*1.3/4 =47.6 m3

4. Timing of hydraulic fracturing

Т = (Vр+Vжп+Vр) Q =(7.5+32+47.6)/ 1500=0.06 days

Where Q is the daily flow rate of working fluid, m³

5. Horizontal crack radius

This technology, used to intensify work and increase the productivity of oil wells for more than half a century, is perhaps the most heated debate among environmentalists, scientists, ordinary citizens, and often even workers in the mining industry themselves. Meanwhile, the mixture that is pumped into a well during hydraulic fracturing consists of 99% water and sand, and only 1% chemical reagents.

What interferes with oil recovery

The main reason for low well productivity, along with poor natural permeability of the formation and poor-quality perforation, is a decrease in the permeability of the near-wellbore zone of the formation. This is the name of the area of ​​the formation around the wellbore that is subject to the most intense influence of various processes that accompany the construction of the well and its subsequent operation and disrupt the initial equilibrium mechanical and physical-chemical state of the formation. Drilling itself changes the distribution of internal stresses in the surrounding rock. A decrease in well productivity during drilling also occurs as a result of the penetration of drilling fluid or its filtrate into the bottomhole zone of the formation

The reason for the low productivity of wells may also be poor-quality perforation due to the use of low-power perforators, especially in deep wells, where the energy of the explosion of charges is absorbed by the energy of high hydrostatic pressures.

A decrease in the permeability of the bottomhole formation zone also occurs during the operation of wells, which is accompanied by a violation of the thermobaric equilibrium in the reservoir system and the release of free gas, paraffin and asphalt-resinous substances from the oil, clogging the pore space of the reservoir. Intense contamination of the bottomhole formation zone is also observed as a result of the penetration of working fluids into it during various repair work in wells. The injectivity of injection wells deteriorates due to clogging of the pore space of the formation with corrosion products, silt, and oil products contained in the injected water. As a result of such processes, the resistance to filtration of liquid and gas increases, well flow rates decrease, and the need arises for artificial influence on the bottom-hole zone of the formation in order to increase the productivity of wells and improve their hydrodynamic connection with the formation.

Technologyfracking

To increase oil recovery, intensify the work of oil and gas wells and increase the injectivity of injection wells, the method of hydraulic fracturing or fracking is used. The technology consists of creating a highly conductive fracture in the target formation under the influence of fluid supplied into it under pressure to ensure the flow of produced fluid to the bottom of the well. After hydraulic fracturing, the well's production rate, as a rule, increases sharply, or the drawdown decreases significantly. Hydraulic fracturing technology makes it possible to “revive” idle wells where oil or gas production using traditional methods is no longer possible or unprofitable.

Hydraulic fracturing (HF) is one of the most effective means of increasing well productivity, since it leads not only to the intensification of the production of reserves located in the drainage zone of the well, but also, under certain conditions, allows you to significantly expand this zone, introducing poorly drained zones to production and interlayers - and, therefore, achieve higher final oil recovery.

Storyhydraulic fracturing method

The first attempts to intensify oil production from oil wells were made back in the 1890s. In the USA, where oil production was developing at a rapid pace at that time, a method of stimulating production from tight rocks using nitroglycerin was successfully tested. The idea was to use an explosion of nitroglycerin to crush dense rocks in the bottomhole zone of the well and ensure an increase in the flow of oil to the bottom. The method was successfully used for some time, despite its obvious dangers.

The first commercially successful hydraulic fracturing was carried out in 1949 in the United States, after which their number began to increase sharply. By the mid-50s, the number of hydraulic fracturing operations carried out reached 3,000 per year. In 1988, the total number of hydraulic fracturing operations performed exceeded 1 million, and this was only in the United States.

In domestic practice, the hydraulic fracturing method began to be used in 1952. The peak use of the method was reached in 1959, after which the number of operations decreased, and then this practice ceased altogether. From the beginning of the 1970s to the end of the 1980s, hydraulic fracturing was not carried out on an industrial scale in domestic oil production. In connection with the commissioning of large oil fields in Western Siberia, the need to intensify production simply disappeared.

… And today is the day

The revival of the practice of using hydraulic fracturing in Russia began only in the late 1980s. Currently, the leading positions in the number of hydraulic fracturing operations are occupied by the USA and Canada. They are followed by Russia, where hydraulic fracturing technology is used mainly in the oil fields of Western Siberia. Russia is practically the only country (not counting Argentina) outside the United States and Canada where hydraulic fracturing is a common practice and is perceived quite adequately. In other countries, the application of hydraulic fracturing technology is difficult due to local prejudices and misunderstandings of the technology. Some of them have significant restrictions on the use of hydraulic fracturing technology, including an outright ban on its use.

A number of experts argue that the use of hydraulic fracturing technology in oil production is an irrational, barbaric approach to the ecosystem. At the same time, the method is widely used by almost all major oil companies.

The application of hydraulic fracturing technology is quite extensive - from low to high permeability reservoirs in gas, gas condensate and oil wells. In addition, using hydraulic fracturing, it is possible to solve specific problems, for example, eliminating sand in wells, obtaining information about the reservoir properties of test objects in exploration wells, etc.

In recent years, the development of hydraulic fracturing technologies in Russia has been aimed at increasing the volume of proppant injection, the production of nitrogen hydraulic fracturing, as well as multi-stage hydraulic fracturing in the reservoir.

Equipment forhydraulic fracturing

The equipment necessary for hydraulic fracturing is produced by a number of enterprises, both foreign and domestic. One of them is the TRUST-ENGINEERING company, which presents a wide selection of equipment for hydraulic fracturing in standard versions and in the form of modifications carried out at the request of the customer .

As a competitive advantage of TRUST-ENGINEERING LLC products, it is necessary to note the high share of localization of production; application of the most modern design and production technologies; use of components and components from world industry leaders. It is important to note the high culture of design, production, warranty, post-warranty and service maintenance inherent in the company’s specialists. Hydraulic fracturing equipment produced by TRUST-ENGINEERING LLC is easier to purchase due to the presence of representative offices in Moscow (Russian Federation), Tashkent (Republic of Uzbekistan), Atyrau (Republic of Kazakhstan), as well as in Pancevo (Serbia).

Of course, the hydraulic fracturing method, like any other technology used in the mining industry, is not without certain disadvantages. One of the disadvantages of fracking is that the positive effect of the operation can be negated by unforeseen situations, the risk of which with such an extensive intervention is quite high (for example, an unexpected violation of the tightness of a nearby water reservoir is possible). At the same time. Hydraulic fracturing is today one of the most effective methods for intensifying wells, opening not only low-permeability formations, but also medium and high permeability reservoirs. The greatest effect from hydraulic fracturing can be achieved by introducing an integrated approach to the design of hydraulic fracturing as an element of the development system, taking into account various factors, such as reservoir conductivity, well placement system, formation energy potential, fracture mechanics, characteristics of the fracturing fluid and proppant, technological and economic limitations .