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MINISTRY OF EDUCATION AND SCIENCE OF THE RUSSIAN FEDERATION

FEDERAL STATE BUDGET EDUCATIONAL INSTITUTION OF HIGHER PROFESSIONAL EDUCATION

"TYUMEN STATE OIL AND GAS UNIVERSITY"

Branch in Nizhnevartovsk

DEPARTMENT OF "OIL AND GAS BUSINESS"

Test

Well Product Management

Completed by student gr.EDNbs-11(1) D.S. Bantikov

Checked by: teacher D.M. Sakhipov

Nizhnevartovsk 2014

Introduction

1. Methods for increasing oil recovery using silicate-alkaline solutions (SAS)

Bibliography

Introduction

An objective need to increase the coverage of the less permeable part of the productive formation by impact during progressive watering is to limit the filtration of the oil-displacing agent through the washed layers and zones of the productive formation and its entry into production wells. This should lead to a redistribution of the energy of the injected water and coverage of low-permeability layers. Solving this problem is not possible using conventional methods of isolating water in production wells due to the limited volume of the treated formation only in the bottom-hole zone. Methods are needed that allow large volumes of waterproofing masses to be pumped into remote areas using cheap and accessible materials and chemicals.

Currently, a large number of methods for increasing the coverage coefficient of the formation by the action are quite well known, such as injection of polymer-thickened water, foam, periodic injection into the formation of reagents that reduce the permeability of individual highly permeable interlayers washed with a displacing agent, silicate-alkaline solutions (SAS), polymer-dispersed systems ( PDS), as well as various gel-forming chemical compositions in reservoir conditions.

1. Methods for increasing oil recovery using silicate-alkaline solutions (SAL).

The method of alkaline flooding of oil reservoirs is based on the interaction of alkalis with reservoir oil and rock. When alkali comes into contact with oil, it interacts with organic acids, resulting in the formation of surfactants that reduce interfacial tension at the interface between the oil and alkali solution phases and increase the wettability of the rock with water. The use of alkali solutions is one of the most effective ways to reduce the contact angle of rock wetting with water, that is, hydrophilization of the porous medium, which leads to an increase in the coefficient of oil displacement by water.

Rice. 1 Use of chemical methods to displace oil

Among the sediment-forming compositions, silicate-alkaline compositions (ALS), alkali-polymer solutions (ALS), ammonia water, methylcellulose, based on interaction with formation water with the formation of an insoluble sediment, are currently considered to be widely used.

In-situ sedimentation requires the interaction of alkali metal silicates with a divalent metal salt and caustic soda or soda ash with polyvalent metals. The technology is based on the use of alkali-silicate flooding in alternate injection of slugs of an alkali metal silicate solution and a divalent metal salt solution, separated by a slug of fresh water. As an alkali metal silicate, sodium and potassium orthosilicate, metasilicate and pentohydrate can be used, which, when interacting with calcium chloride, form a gel-forming precipitate. At the same time, solutions of these silicates at a concentration of about 1% in solution have a pH value close to 13.

Another technology involves the sequential injection of slugs of alkali and ferric iron solutions. As a result of the interaction of alkali with salts of multivalent cations upon contact of the rims, a voluminous, poorly soluble precipitate of hydroxides of multivalent cations is formed. However, controlling sedimentation processes in reservoir conditions by injecting alkalis is a rather complex task.

In the fields of Western Siberia, alkaline flooding was one of the first methods of physical and chemical stimulation of the formation. The impact method has been used since 1976. All the results obtained during an extensive fishing experiment are noteworthy. Here, two modifications of injection of weakly concentrated alkali solutions into the formation were tested, which indicate the insignificant effectiveness of the method. The first field experiment on injection of a concentrated alkali solution was carried out in 1985 at the Trekhozernoye field, where a slug of 10% alkali solution with a size of 0.14% of the pore volume of the area was pumped into two injection wells. For individual producing wells in 4-5 months. There was a decrease in the water cut of extracted products. Thus, the water cut at the beginning of the experiment was 55-90%, later it decreased to 40-50%. And only by the end of 1990 did the water cut increase to 70-80%. Such a sharp decrease in the water cut of the produced product can be explained by a change in the coverage of the formation by the influence of the thickness due to the blockage of water-washed zones of the formation and the inclusion of interlayers previously not covered by waterflooding. In total, 58.8 thousand tons of oil were produced at the pilot site during the implementation period, with a specific technological efficiency of 53.5 tons per ton of injected reagent. Similar results were obtained at the Toluomskoye field. Although the reservoir characteristics are noticeably worse: greater compartmentalization, lower permeability and productivity. The volume of the injected slug was 0.3% of the pore volume of the formation; at the beginning of the experiment, the area was watered by 40-50%; after injection of an alkali solution, the water cut decreased to 20-30%.

Additional oil production amounted to 35.8 thousand tons or 42.4 tons per ton of reagent consumed. The positive results of the field experiment indicate that the technology is effective for medium- and low-permeability formations of small (up to 10 m) thickness.

Field tests of the stimulation method for objects represented by a significant formation thickness of 15 m or more, such as the North Martymyinskaya deposit and the Martymya-Teterevskaya deposit, did not show the low efficiency of its use.

A 1% alkaline solution has been widely used in four fields of the Perm region (Shagirtsko-Gozhanskoye, Padunskoye, Opalikinskoye and Berezovskoye) since 1978. Industrial introduction has been carried out since 1983 in four pilot areas with 13 injection and 72 production wells. Additional oil production in all areas as of January 1, 1991 amounted to 662.4 thousand tons. The increase in oil recovery was 5.6%. In the first section, the increase in the oil recovery factor reached 25.4%. The largest fringe with the size of one pore volume of the formation is created on it. oil recovery solution alkali injection

Experiments on changing wettability show that a 1% alkali solution increases the hydrophilicity of terrigenous rocks and does not change the wettability in limestones, and the consumption of alkali and the amount of sediment increase with increasing water salinity and alkali concentration. When water mineralization is 265 g/l, the maximum amount of sediment is formed - 19 g/l, alkali consumption is 2.5 mg/g of rock. The oil-displacing properties of alkali solutions were assessed using a centrifuge. Sequential injection of solutions increases the displacement efficiency by 2.5-4%.

The technology for regulating the permeability of water-conducting reservoir channels with silicate-alkaline solutions was introduced in several modifications. The main modification includes the injection of separation rims of fresh water and a solution (a mixture of sodium hydroxide, liquid glass, polyacrylamide). Injection of slugs is repeated periodically every 1-3 years, generally within 10-15 years. The slugs of oil-displacing agents are injected in the following sequence: waste mineralized water injected to displace oil; fresh water separation rim; rim of sodium hydroxide solution. However, the technology under consideration is aimed only at regulating the permeability of the formation and cannot effectively block selectively watered zones of the formation, which is only possible in the case of injection of large volumes of the rim.

Bibliography

1. Surguchev M.L. Secondary and tertiary methods for enhanced oil recovery.

2. Amelin I.D., Surguchev M.L., Davydov A.V. Forecast for the development of oil deposits at a late stage.

3. Shelepov V.V. State of the resource base of the Russian oil industry. Increased oil recovery.

4. Surguchev M.L., Zheltov Yu.V., Simkin E.M. Physico-chemical microprocesses in oil and gas bearing formations.

5. Klimov A.A. Methods for enhancing oil recovery.

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Practical lesson No. 4.
Well productivity management.
As was shown in the previous section, control of certain parameters of the wellbore zone (BZZ) can be used to change the productivity of production or injection wells. During the operation of wells, their productivity, as a rule, decreases for a number of reasons. Therefore, methods of artificial influence on the EPC are a powerful means of increasing the efficiency of production of hydrocarbon reserves.
Among the numerous methods for managing well productivity by influencing the EPC (see Table 4.1), not all have the same effectiveness, but each of them (or groups of them) can give the maximum positive effect only if there is a reasonable selection of a specific well. Therefore, when using one or another method of artificial influence on the TES, the issue of well selection is fundamental. At the same time, treatments, even effective ones, carried out in individual wells, may not provide a significant positive effect on the entire reservoir or field, both from the standpoint of intensifying reserve production and from the standpoint of increasing the final oil recovery factor.
Before moving on to considering certain methods of artificially influencing the wells in order to control well productivity, let’s consider some general methodological issues.

5.1. SYSTEM APPROACH TO PES TREATMENTS
The system technology for managing well productivity is set out in RD-39-0147035, so only the basic principles of its industrial use are discussed below.
System technology basically involves intensifying the production of poorly drained hydrocarbon reserves from heterogeneous reservoirs, and also determines the principles for obtaining maximum effect when using methods to increase well productivity. Let us note that the term “poorly drained reserves” refers to hydrocarbon reserves in areas of deposits with deteriorated filtration properties due to geological characteristics, as well as in areas where any complications in the operation of wells are possible (clogging of wells with various solid components, asphalt-resin, paraffin deposits, etc.). Poorly drained reserves are also formed in formations with sharp filtration heterogeneity, when oil is replaced by injected water only in highly permeable varieties, leading to low reservoir coverage by waterflooding.
Solving specific problems of involving poorly drained reserves in the development and increasing well productivity is based on quite numerous technologies for intensifying reserve production.
In areas of the deposit, in the section of which there are highly permeable layers washed with water, which predetermine the low coverage of the object by waterflooding, it is necessary to carry out work to limit and regulate water inflows.
In such work, an indispensable condition for the system technology is the simultaneous impact on the bottomhole zones of both injection and production wells.
Before determining the type of impact, the deposit or part of it must be divided into characteristic areas. At the same time, during the initial period of site development, it is possible to carry out work to increase the productivity of wells, and subsequently, when it becomes watered, measures to regulate (limit) water inflows.
It should be noted that when identifying a section of a deposit with strongly pronounced zonal and layer-by-layer heterogeneity, the bottom-hole zones of those wells that form the main directions of filtration flows are first subjected to artificial influence, which makes it possible to timely change these directions in order to involve undrained zones in the development, increasing thereby covering the object with flooding. When carrying out such work, it is possible to use either one technology or a complex of different technologies.
One of the important conditions for the use of system technology is maintaining approximately equal volumes of hardening and selection, i.e. any measures to intensify oil flows must be accompanied by measures to increase the injectivity of injection wells.
The basic principles of system technology are as follows:
1. The principle of simultaneous treatment of bottomhole zones of injection and production wells within the selected area.
2. The principle of mass processing of the CCD area.
H. The principle of frequency of CCD processing.
4. The principle of step-by-step processing of bottomhole zones of wells that have exposed heterogeneous reservoirs.
5. The principle of programmability of changing the direction of filtration flows in the formation due to the selection of wells for treatment according to a previously specified program,
6. The principle of adequacy of CPR treatments to specific geological and physical conditions, reservoir and filtration properties of the system in the CPR and in the area as a whole.
Thus, the issue of choosing wells for treating bottom-hole zones is one of the most important.

5.2. BYBOR WELLS FOR TREATMENT OF THE BOREWELL ZONE
With a significant number of wells in a deposit, in the process of organizing work on artificial impact on the reservoir zone, the problem arises not only of the order of choice of wells, but also of the feasibility of such treatments in each specific case. This is due to the wide variety of geological and physical conditions of oil occurrence in the zone of treated wells, as well as the degree of their mutual influence. It is advisable to establish a sequence of treatments that ensures their greatest technological and economic efficiency, not so much in each specific well, but in the area as a whole. To a large extent, the choice of wells is determined by the residual oil saturation and the distance of residual oil reserves from the bottom of the producing wells. Methods of field geology and geophysics make it possible to estimate the initial and residual oil saturation of reservoirs and construct saturation maps. A significant and important addition to these data is information on the current performance of wells and data on the oil saturation of zones near specific wells, which can be obtained as a result of hydrodynamic studies of wells in formations,
It can be assumed, for example, that the shape of the bottomhole pressure recovery curve (BRP) or the response curve is also determined by the residual oil saturation in the drained volume of the watered well. The angular coefficients of different sections of the pressure build-up can also be associated with different oil saturations of individual volumes of the total volume drained by a given well.
Knowing the history of well operation and the nature of their watering over time, one can also judge the residual oil saturation. In this case, information about the ratio of the specific oil reserves extracted by a given well to its initial specific reserves turns out to be useful.
More reliable data on the value of residual oil saturation can be obtained from the results of hydrodynamic studies of the well carried out during the dry period of its operation and during the period of water flooding.
There are a number of methods for assessing the residual oil saturation of the reservoir around wells based on the results of monitoring their operation and hydrodynamic studies:
- combined method;
- correlation method;
- according to water cut data from production wells;
- based on data on the relative piezoelectric conductivity of the system (formation);
- based on data on the relative mobility of the oil-water mixture.
Let's consider the issue of determining the current oil saturation of the drainage zone based on data on the water cut of production wells (the simplest method), which can be used in the later stages of development for zones through which the replacement (displacement) front has passed. It is assumed that in the immediate vicinity of the well, the drained volume is uniformly saturated with water and oil.
Let us rewrite expression (4.37), taking Вв = ВН and replacing the phase permeabilities kН and kв and the corresponding values ​​of the relative phase permeability:
.
This expression is nothing more than the Buckley-Leverett function f(S):
(5.1)
where f(S) is a function of saturation of the porous medium with fluid (in the case under consideration, with water Sв).
Thus
(5.2)
where μ0 is the relative viscosity of oil μН/ μв.
If there are graphical dependencies of relative phase permeabilities as a function of water saturation
(5.3)
It is easier to construct a graph using expression (5.2).
Let us use the experimental dependencies obtained by pumping model water-oil mixtures at μ0 = 4.5 through the cemented sandstone of the coal-bearing strata of the Arlan deposit (V.M. Berezin), which are presented in Fig. 5.1. The water saturation of the sample Sв is characterized by a fraction of the pore volume; wherein:
(5.4)
where is oil saturation.
The phase relative permeability for oil and water is characterized by the ratio of the phase permeability for oil and water to the permeability of the system (physical permeability) when a homogeneous fluid is filtered through it:
(5.5)
As can be seen from Fig. 5.1, the saturation with bound water Swe is 0.18. In this case, in the range Sв = 0 – 0.18, water remains motionless, but the presence of this water in the reservoir leads to a decrease in the relative phase permeability for oil to 0.6. Thus, the permeability of the system, determined from the results of studying a well during the dry period of its operation, is not physical permeability, but characterizes the initial permeability for oil (at 8, 8,). The initial relative permeability of the system c’ is characterized by the ratio:
(5.6)
which is one of the main parameters used in calculating current oil saturation.

Rice. 5.1. Dependence of relative phase permeabilities for oil and water on water saturation.
In Fig. Figure 5.2 shows the Buckley-Leverett function. constructed according to expression (5.2) using relative phase permeabilities as a function of water saturation, presented in Fig. 5.1. By drawing a tangent to the graph of the Buckley-Leverett function (point A) from the origin of coordinates, the water saturation Sв and oil saturation SH are determined. Thus, to calculate the current oil saturation using this method, it is necessary to know the volume fraction of water in the product (under reservoir conditions!) and to have the dependence of the relative phase permeabilities on water saturation.
The greatest difficulty in calculations is the choice of relative phase permeability curves. This problem has to be faced when solving many problems related to the filtration of multiphase systems. In each case, the experimental design

Rice. 5.2. Dependence of the Buckley-Leveratt function on water saturation.
The dependence of the relative phase permeability on the saturation of pores with fluids is difficult due to the need to use complex equipment and have highly qualified personnel. Therefore, finding methods for constructing relative phase permeability curves that are simpler and accessible to a wide range of researchers and engineers is an extremely pressing problem. One of these methods is the use of “capillary pressure Pk - water saturation Sw” curves, which can be relatively easily obtained by centrifuging water-saturated cores or by the method of semi-permeable partitions.
It is known that the Рk - Sв curves are representative dependencies that are closely related to the filtration properties of rocks, and which can be used to construct relative phase permeability curves for the case of filtration of water-oil mixtures in terrigenous reservoirs (sandstones).
The dependences Рk - Sв can be described in logarithmic coordinates in the form of a hyperbola:

or (5.7)
where SVO is the residual water saturation;
SВ - water saturation at capillary pressure P
x is the exponent of the hyperbola (structural coefficient);
Po -pressure of the beginning of displacement:
(5.8)
- surface tension at the oil-water interface;
Θ - contact angle;
rmax - maximum pore radius.
The value of P0 can be determined experimentally using the semi-permeable partition method. The exponent x is an integral characteristic of the structure of the pore space and determines the microstructure of the pore space of reservoir rocks. Therefore, the use of the hyperbola exponent to identify the properties of porous media turns out to be acceptable and appropriate when constructing the dependences of the relative phase permeabilities for oil and water using the Pk - Sb curves.
Thus, the selection of wells for a specific treatment of the near-wellbore zone is a rather complex problem if we want to obtain maximum efficiency from the implementation of a particular CCD treatment. It is quite obvious that the technology of the designed treatment must be adequate to the state of the bottomhole zone at the time of its implementation.
Let's consider some of the methods for managing well productivity (intensification and injectivity) given in Table. 4.1.

Since oil is produced in the CDNG, the activities primarily concern work with production wells. Optimizing the operation of production wells while reducing bottomhole pressure, i.e. changing the layout of well equipment in order to ensure a higher flow rate.

If this work does not suit you, at the bottom of the page there is a list of similar works. You can also use the search button

Lecture 1

Topic: interpretation of the results of hydrodynamic studies of wells for making management decisions.

Introduction

Management methodsthese are all types of technological impact on objects that are not related to changes in the development system and are aimed at increasing the efficiency of field development.

Oil and gas field development management is necessary to ensure compliance with planned and actual development indicators. Development management is often called “development regulation”, i.e. it is necessary to bring planned production volumes closer to actual ones. There are 2 main workshops in production: the oil and gas production workshop (OPPG) and the reservoir pressure maintenance workshop (RPM). Since oil is produced in the CDNG, the activities primarily concern work with production wells.

1. Optimizing the operation of production wells while reducing bottomhole pressure, i.e. changing the layout of well equipment in order to ensure a higher flow rate.
2. Intensification well productivity management (acid treatment of wells, hydraulic fracturing, sidetracking).

Classification of management methods

1) Increasing well productivity due to reduction bottomhole pressure.

2) Impact on the bottomhole zone of wells (productivity management) in order to intensify inflow (injectivity) - hydraulic fracturing, sidetracking, acid treatments, etc.

3) Shutdown of high-water-cut wells.

1. Promotion bottomhole pressure of injection wells;
2. drilling additional production wells (within the reserve fund) or returning wells from other horizons.
3. Transfer of the injection front.
4. Use of focal flooding.
5. Application of insulation works.
6. Leveling the inflow or intake profile;
7. Application of new methods for increasing oil recovery.

OPTIMIZATION OF WELL OPERATION increasing productivity by reducing bottomhole pressure.

Selection of wells to optimize their operation low water cut, high productivity coefficient and reserve for reducing bottomhole pressure.

When optimizing the operation of wells, it is necessary to evaluate the increase in production rate with a decrease in bottomhole pressure.

If a well, before optimization, operates with a certain fluid flow rate at the corresponding bottomhole pressure, it is wrong to assume that when the bottomhole pressure decreases, its productivity will certainly remain the same and the increase in flow rate can be determined by the productivity value in the base case.

When reducing bottomhole pressure, one should take into account the physical processes occurring in the formation (primarily in the near-well zones), such as deformation, increase in gas saturation, etc.

Therefore, it is necessary to justify inflow models taking into account deviations from Darcy’s linear law, the parameters of which are determined during hydrodynamic testing of wells (well testing).

1. Mishchenko I.T. Downhole oil production.
2. Bravichev, Bravicheva Paliy. Chapter 9.

All analytical inflow models (in the form of specific formulas) contain parameters characterizing the filtration-capacitance and physical properties of the system. These properties are determined on average over the entire drainage volume: equivalent permeability, piezoelectric and hydraulic conductivity in the drainage volume. Therefore, inflow formulas can be used to assess the production capabilities of wells when justifying the operating method with the equipment layout option.

When managing the development of a heterogeneous reservoir, the assessment of equivalent parameters does not reflect the real picture of filtration flows. Therefore, in the case of heterogeneous drainage volumes, interpretation of well testing results is carried out when they are reproduced using hydrodynamic modeling software products.

Linear inflow models used to assess the production capabilities of wells in a homogeneous formation (for optimization).

1. Assessment of the production capabilities of wells with a decrease in bottomhole pressure (in the case of a linear indicator line).

For radial filtration according to Darcy's law, there is Dupuis' formula.

(1)

where the proportionality coefficient between flow rate and depression is called the well productivity coefficient,

k permeability of the “reservoir-fluid” system, determined during geophysical studies of core material at initial reservoir conditions (initial reservoir pressure and water saturation of the reservoir equal to S St.). R k radius of influence of the well (in the absence of data half the distance between wells).

2. It is necessary to estimate the actual productivity of the well. This is usually due to the fact that when the formation is excited by a well, primary technogenic processes occur (even at small depressions), leading to the appearance of additional filtration resistance.

Primary technogenic processes occurring in near-well zones:

1. penetration of kill fluid and flushing fluid during underground repairs and well development;
2. penetration of mechanical impurities and metal corrosion products during well killing or flushing;
3. deformation of rocks at the bottom of a well during drilling;

In addition, most wells are imperfect in the degree and nature of the opening of the productive formation, so the inflow occurs through perforations, and not along the entire lateral surface of the well.

When primary technogenic processes occur, additional filtration resistance arises, leading to a decrease in flow rate. Because These resistances depend on a very large number of factors; it is impossible to evaluate them analytically. They are taken into account by introducing the parameter S , which is called the skin factor. S is determined based on the results of hydrodynamic studies of wells using the method of sequential change of steady-state selections.

(2)

(3)

If the actual productivity factor is quite high and a slight decrease in bottomhole pressure can lead to a significant increase in well production, then reducing bottomhole pressure as a development management method is justified.

For example, if the actual productivity factor is 15 m 3 /(day MPa), then a decrease in bottomhole pressure even by 5 atm. leads to an increase in flow rate by as much as 7.5 m 3 /day

It is possible to reduce bottomhole pressure by changing the modes and sizes of downhole equipment in the basic configuration. To do this, you need to know the methods for selecting a layout option based on the main methods of operation. This is one of the tasks that we will deal with in the seminars.

If the actual productivity ratio is low, this management method is not effective.

For example, if the actual productivity factor is 2 m 3 /(day MPa), then the bottomhole pressure decreases by 5 atm. leads to an increase in flow rate by only 1 m 3 /day

In this case, it is necessary to use the second management method - well productivity management.

1. Selecting a well productivity management method.

2. Assessment of technological criteria - flow rate increase, etc.

This problem is solved by hydrodynamic modeling of the development process.

For example, if sidetracking is used as a control method, hydrodynamic calculations should be aimed at justifying the parameters of the specified technology (line length, profile, etc.).

For item 1, it is necessary to determine the size of the well bottom zone.

For example, if the bottomhole zone of a well is 10 m or more, then MSD may be ineffective. This happens in carbonate reservoirs that absorb clay solution, development fluids, and fur. impurities, etc.

3. Additional filtration resistance arises due to the formation near the well of the so-called bottomhole zone. The bottomhole zone has design parameters k CCD and R CCD (Fig. 2)

(4)

The formula is derived based on the continuity of the filtered flow: the inflow to the bottomhole zone must be equal to the inflow to the bottom.

Naturally, there is a connection between the skin factor and the calculated parameters of the bottomhole zone

(5)

In practice, the size of the well bottom zone is often neglected and the flow rate is calculated using formula (6)

(6)

In this case, an overestimated value of the permeability of the wellbore zone is obtained. When processing the results of hydrodynamic studies for a large number of fields in the Ural-Volga region and Western Siberia, an adaptation coefficient was obtained that allows a more adequate assessment of this parameter. Adaptation coefficient, i.e. there are optimistic and pessimistic forecasts.

Methodology for estimating the parameters of the bottomhole zone of a well using well testing.

1. The actual productivity coefficient of the well is determined using methods of the mathematical theory of experiment (least squares method).

2. The overestimated value of the permeability of the bottomhole zone (form 6) is estimated.

3. Using the adaptation coefficient, the permeability of the bottomhole zone is specified.

4. The radius of the well bottom zone is calculated (form 4).

5. The skin factor and the reduced radius of the well are calculated.

Example. Suppose that when studying a well using the method of sequential change of steady-state selections, a value of the well productivity coefficient equal to 2 m is obtained 3 /(day MPa). The initial data required for calculations are as follows: permeability of the remote zone (outside the CZ) - 100 10-15 m 2 ; radius of the well supply circuit is 150 m; well radius 0.1 m; uncovered productive thickness 10 m; the volumetric coefficient and dynamic viscosity of the liquid are respectively 1 and 5 10-3 Pa·s.

The permeability of the formation, determined on the basis of the productivity coefficient, is equal to 13.47 10-15 m 2 , taking into account the need to underestimate the specified value for the CCD - k CCD may range from 9.62 10 -15 to 11.225  10 -15 . The radius of the bottomhole zone, determined by formula (4) is in the range from 14.83 to 37.97 m.

Therefore, sidetracking rather than MOR can be proposed as a control method.

The next stage is to conduct multivariate hydrodynamic calculations (seminars).

5. For low depressionsthe parameters of the bottomhole zone and the skin factor are parameters of the LINEAR inflow model. These parameters are determined by methods of the mathematical theory of experiment (in this case, the least squares method).

The least squares method is as follows.

1. A variation series of values ​​of the parameter under study is constructed based on the results of geological and geophysical research and field experience.

2. The criterion is calculated F for each value of the parameter under study:

If the estimated number of parameter values m , then the criterion is calculated m times.

The required parameter corresponds to the smallest calculated value of the criterion F.

• The calculated flow rate can be obtained using the inflow formula for a specific value of the desired parameter. So, . Based on these calculated values, it is determined F 1.
• The calculated flow rate can be obtained using a hydrodynamic model of drainage volume using software products. In this case, well test data are reproduced using the specified software products.

Currently, when interpreting well testing, equivalent permeability (hydraulic conductivity, piezoelectric conductivity) is assessed.

This is justified when estimating well flow rates.

To control development, it is necessary to have information not about equivalent permeability, but about the heterogeneity of drainage volume. For example, know layer-by-layer permeability. That is why software products for hydrodynamic modeling are used.

If it is necessary to determine the parameters of the inflow equation averaged over the drainage volume, in some cases a so-called system of normal equations is constructed, which is obtained by differentiating the least squares criterion with respect to the desired parameter.

Let there be an active experiment Yi (Xi), i =1,2… n . It is required to determine the parameters of the linear trend Y=A+BX using the least squares method.

Method criteria.

Parameters A and B are determined by solving the following system of equations:

or

6. Assessment of actual well productivity.

In general, the linear inflow equation has the form:

If the parameter C is significant, then there is an initial pressure gradient (C negative).

So, there are well test results, it is necessary to determine the parameters of the linear trend Y - Q , X -.

PAGE 2

INTRODUCTION The main highly productive oil fields in Russia are in the final stages of development with high water cut and low levels of oil production. Current oil production is not fully compensated by the increase in reserves during geological exploration; the quality of newly discovered oil reserves is constantly declining. In this regard, the problem of maintaining and increasing the productivity of production wells is becoming increasingly 02/10/2018 2

INTRODUCTION Intensity is an indicator of the efficiency of an object over a certain period of time. In relation to oil production, this is the flow rate of a well. If intensification is understood as an increase in productivity, then in oil production it is a process of production development based on the rational use of technical resources and achievements of scientific and technological progress. That is, intensification of oil extraction from a producing well is an increase in its productivity through geological and technical measures, improvement of technical means of operation, optimization of technological operating modes 02/10/2018 3

INTRODUCTION The productivity of oil production wells is one of the main indicators that determine the efficiency of oil production during field development, especially in difficult geological and physical conditions. Complex geological and physical conditions for oil fields most often include: low permeability of productive formations; increased clay content of the reservoir; fractured-pore structure of the reservoir; high degree of heterogeneity of productive formations; high water cut of layers; high viscosity of formation fluids (oil); high gas saturation of oil. 10.02.2018 4

INTRODUCTION The deterioration of the filtration properties of a productive formation is associated with a decrease in the absolute or relative (phase) permeability of the reservoir. The reasons for the decrease in absolute permeability: a decrease in the capacity of filtration channels due to clogging of the pore space of the formation, deformation processes occurring in the reservoir when the formation pressure decreases. Reduced phase permeability 02/10/2018 5

INTRODUCTION One of the main reasons for the deterioration of the filtration characteristics of the formation is a decrease in reservoir pressure and pressure at the bottom of production wells. In addition, when operating wells, it is necessary to assess the influence of thermodynamic conditions and geological factors on their productivity. Observation, assessment and forecasting of production well productivity are necessary for effective management of this indicator during the development of oil fields. 10.02.2018 6

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 1. 1. Oil reservoir, deposit, field In the process of formation and migration in the bowels of the earth's crust, OIL accumulates in natural reservoirs. A natural reservoir is a container for oil, gas or water in reservoir rocks overlain by poorly permeable rocks. The upper part of the reservoir, where oil and gas accumulates, is called a trap. An oil (gas, water) reservoir is a rock that has interconnected voids in the form of pores, cracks, caverns, etc., filled (saturated) with oil, gas or water and capable of releasing them when a pressure difference is created. 10.02.2018 7

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS A significant accumulation of oil (gas) trapped in a natural reservoir, suitable for industrial development, is called a deposit. A collection of oil or gas deposits connected by one area of ​​the earth's surface forms a field. The bulk of oil fields are confined to sedimentary rocks, which are characterized by a stratified (layered) structure. An oil reservoir may occupy part of the volume of one or more formations in which gas, oil and water are distributed according to their density. 10.02.2018 8

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS An oil reservoir includes a hydrocarbon deposit and an adjacent water-saturated (water-pressure) area. A deposit containing oil with dissolved gas is called oil (Fig. 1. 1). 10.02.2018 9

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS An oil deposit with a gas cap is called a gas-oil deposit (Fig. 1. 2). If the gas cap is large (the volume of the part of the formation with a gas cap exceeds the volume of the formation saturated with oil), the field 02/10/2018 10

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The oil-saturated part of the formation is called in this case the oil rim (Fig. 1. 3). The surface along which the gas cap and oil border in reservoir conditions is called the gas-oil contact (GOC), the surface separating oil and water is called the oil-water contact (WOC). The line of intersection of the surface of the OWC (GOC) with the roof of the productive formation is the external contour, with the bottom of the formation - the internal contour of the oil-bearing capacity (gas-bearing capacity). 10.02.2018 11

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS A reservoir is called full-layer if hydrocarbons occupy the pore space throughout the entire thickness of the productive formation (see Fig. 1. 2). In an incomplete reservoir, hydrocarbons do not fill the formation throughout its entire thickness (see Fig. 1. 3). v. In deposits with marginal (contour) water, oil and water border on the wings of the formation (see Fig. 1. 3), in deposits with bottom water - over the entire area of ​​the deposit (see Fig. 1. 1 and 1. 2). Oil deposits are confined mainly to three types of reservoirs - porous (granular), fractured and mixed structure. 10.02.2018 12

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Pore reservoirs include reservoirs Ø composed of sandy-siltstone terrigenous rocks, rocks Ø the pore space of which consists of intergranular cavities. The same structure of the pore space is characteristic of limestones and dolomites 02/10/2018 13

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS In purely fractured reservoirs (mainly carbonate), the pore space is formed by a system of fractures. The parts of the reservoir between the fractures are dense, low-permeability, non-fractured blocks of rock, the pore space of which does not participate in filtration processes. In practice, mixed-type fractured reservoirs are more common, the pore volume of which includes both systems of fractures and the pore space of blocks, as well as caverns and karst cavities. 10.02.2018 14

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Most often, carbonate formations are fractured-pore reservoirs. The main part of the oil in them is contained in the pores of the blocks; fluid is transferred through cracks. Rocks of sedimentary origin are the main reservoirs of oil and gas. About 60% of the world's oil reserves are confined to terrigenous rocks, 39% to carbonate deposits, and 1% to weathered metamorphic and igneous rocks. Due to the diversity of conditions for the formation of sediments, the geological and physical properties of productive formations 02/10/2018 of various fields can vary widely 15

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 1. 2. Filtration-capacitive properties of rocks (PP) Properties of rocks to contain (due to porosity) and to pass through (due to permeability capacity) through liquid or gas are called filtration-capacitive properties. The filtration and reservoir properties of oil reservoir rocks are characterized by the following main indicators: porosity, permeability, capillary properties, specific surface area, 16 10. 02. 2018 fracturing.

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Capacitive properties of a rock are determined by its porosity. Porosity is characterized by the presence of voids (pores, cracks, caverns) in the rock, which are receptacles for liquids (water, oil) and gases. There are total, open and effective porosity. 10.02.2018 17

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS General (absolute, total) porosity is determined by the presence of all voids in the rock. The total porosity coefficient is equal to the ratio of the volume of all voids to the visible volume of the rock. Open porosity (saturation porosity) is characterized by the volume of communicating (open) voids into which liquid or gas can penetrate. Effective porosity is determined by that part of the volume of open pores (voids) that participates in filtration (the volume of open voids minus the volume of bound water contained in them). 10.02.2018 18

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The filtration properties of rocks are characterized by their permeability - the ability to pass liquids or gases through themselves when creating a pressure difference. The movement of liquids or gases in a porous medium is called filtration. Based on the transverse size, pore channels (filtration channels) are divided into: supercapillary - with a diameter of more than 0.5 mm; capillary - from 0.5 to 0.0002 mm; subcapillary - less than 0.0002 mm. 10.02.2018 19

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS In supercapillary channels, liquid moves freely under the influence of gravity; in capillary channels, the movement of liquid is difficult (it is necessary to overcome the action of capillary forces), gas moves quite easily; in subcapillary channels, liquid does not move during pressure drops that are created during field development. During the operation of oil fields 02/10/2018 20

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS To characterize the permeability of oil-bearing rocks, absolute, phase (effective) and relative permeability are distinguished. 10.02.2018 21

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Absolute permeability is the permeability of a porous medium when only one phase (gas or homogeneous liquid) moves in it in the absence of other phases. Effective (phase) permeability is the permeability of a rock to one of the liquids or to gas when two or more phases are simultaneously present in the pore space. The relative permeability of a porous medium is defined as the ratio of the phase 10. 02. 2018 22

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Permeable rocks include Ø sands, Ø sandstones, Ø limestones. Impermeable or poorly permeable - Ø clays, Ø shales, Ø sandstones with clay cementation, etc. One of the important properties of rocks is their fracturing, which is characterized by Ø thickness, Ø bulk density and Ø crack opening. 10.02.2018 23

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Density is the ratio of the number of cracks Δn cutting the normal of their planes to the length of this normal Δl: Gt = Δn/Δl. (1) Volume density δт characterizes the density of cracks at any point in the formation: δт = ΔS/ΔVп, (2) where ΔS is half the surface area of ​​all cracks in the elementary volume of rock ΔVп, m– 1. Volume of cracks in the elementary volume of rock ΔVт = ΔS ∙ bт, (3) 02/10/2018 24

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Fracture porosity coefficient mt is the ratio of the volume of fractures to the volume of rock. Taking into account formulas (2) and (3) mt = bt ∙ δt. (4) Permeability of fractured rock (without taking into account the permeability of inter-fracture blocks), µm 2, when the cracks are perpendicular to the filtration surface, kt = 85,000 ∙ 2∙ bt ∙ mt, (5) where bt – crack opening, mm; mt – fracture porosity, fractions of unity. 10.02.2018 25

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 1. 3. Reservoir heterogeneity Geological heterogeneity of a reservoir is the variability of lithological and physical properties of rocks over area and section. Hydrocarbon deposits are mainly multi-layered; a single production facility contains several layers and interlayers, correlated by area, therefore geological heterogeneity is studied by section and area. This approach allows Ø to characterize the variability of parameter values ​​by volume that affect the distribution of oil and gas reserves in the subsurface and their 02/10/2018 26

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Depending on the goals and objectives of the study, the stage of exploration of the field, various methods are widely used when determining the geological heterogeneity of formations, which, with a certain degree of convention, can be combined into three groups: a) geological-geophysical, b) laboratory-experimental, c) field-hydrodynamic. 10.02.2018 27

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Geological and geophysical methods of studying Geological and geophysical geological heterogeneity of formations is the whole complex of studies on the processing of actual material obtained during the drilling of wells, including well processing of core analysis data, results interpretation of field geophysical surveys of wells. Using these methods, a detailed study of the deposit section is carried out, subdivision of the deposit section, correlation of well sections taking into account lithologic petrographic characteristics, and also taking into account paleontological 10.02.2018 28

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The end result of geological and geophysical methods are geological profiles and lithological maps that reflect the structural features of productive formations in section and area, identified dependencies between individual parameters of the formations. 10.02.2018 29

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS A detailed understanding of the physical properties of rocks is obtained by studying core samples using laboratory methods. In laboratory studies, porosity, permeability, particle size distribution, carbonate content, and water saturation are determined. However, before extending the values ​​of the formation parameters to the entire volume of the deposit or to some part of it, it is necessary to carefully link the studied core samples for identification in the productive section 02/10/2018 30

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Field hydrodynamic methods are methods that allow one to obtain data characterizing the hydrodynamic properties of formations. Hydrodynamic studies are aimed at studying the reservoir properties of the formation, the hydrodynamic characteristics of the formation, and the physical properties of the fluid saturating the reservoir. Hydrodynamic studies determine the coefficients of hydraulic conductivity, piezoelectric conductivity, permeability, 02/10/2018 31

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS These methods also allow one to assess the degree of homogeneity of the formation, identify lithological screens, establish the relationship of layers along the section and wells over the area, and assess the oil saturation of rocks. The heterogeneity of layers can be assessed using indicators characterizing the features of the geological structure of deposits. 10.02.2018 32

, I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Heterogeneity of formations can be assessed using indicators characterizing the features of the geological structure of deposits. These indicators include, first of all, the coefficients of dissection and sandiness. The compartmentalization coefficient Kp is determined for the reservoir as a whole and is calculated by dividing the sum of sand layers in all wells by the total number of wells that penetrated the reservoir: the number of wells that penetrated the reservoir (6) where n 1, n 2, . . . , nm – number of reservoir layers in each well; N is the total number of wells that penetrated the reservoir. 10.02.2018 33

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The sandiness coefficient Kp is the ratio of the effective thickness hef to the total thickness of the formation htotal, traced in the section of a given well: well (7) For the formation as a whole, the sandiness coefficient is equal to the ratio total effective formation thickness in all wells to the total total formation thickness in these wells. For oil deposits of the Perm Kama region, the coefficients of compartmentalization and sandiness vary from 1.38 to 14.8 and from 0.18 to 0.87, respectively. (In practice, find out these 10. 02. 2018 34

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 1. 4. Composition and properties of formation fluids Formation fluids that saturate productive formations include oil, gas and water. Oil is a complex mixture of organic compounds, mainly hydrocarbons and their derivatives. The physicochemical properties of oils from different fields and even different layers of the same field are very diverse. Based on their consistency, oils are classified as: Ø easily mobile, Ø highly viscous (almost non-fluid) or solidifying under normal conditions. The color of oils varies from greenish-brown to black. 10.02.2018 35

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Elemental, fractional, and group compositions of oil are distinguished. Elemental composition. The main elements in the composition of oil are carbon and hydrogen. On average, oil contains 86% carbon and 13% hydrogen. There are small amounts of other elements (oxygen, nitrogen, sulfur, etc.) in oil. However, they can significantly affect the physicochemical 10. 02. 2018 36

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Group composition. The group composition of oil is understood as the quantitative ratio of individual groups of hydrocarbons in it. 1. Paraffinic hydrocarbons (alkanes) are saturated (saturated) hydrocarbons with the general formula Cn. H 2 n+2. Content in oil is 30–70%. There are normal alkanes (n-alkanes) and isoalkanes (isoalkanes). Oil contains gaseous alkanes C 2–C 4 (in the form of dissolved gas), liquid alkanes C 5–C 16 (the bulk of the liquid fractions of oil), solid alkanes C 17–C 53, which are included in 02/10/2018 37

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 2. Naphthenic hydrocarbons (cycloalkanes) are saturated alicyclic hydrocarbons with the general formula Cn. H 2 n, Cn. H 2 n– 2 (bicyclic) or Cn. H 2 n– 4 (tricyclic). Oil contains mainly five- and six-membered naphthenes. Content in oil is 25–75%. The content of naphthenes increases as the molecular weight of the oil increases. 3. Aromatic hydrocarbons are compounds whose molecules contain cyclic polyconjugated systems. These include benzene and its homologues, toluene, phenanthrene, etc. The content in oil is 10–15%. 10.02.2018 38

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Heteroatomic compounds – hydrocarbons whose molecules include oxygen and nitrogen , sulfur, metals. These include: resins, asphaltenes, mercaptans, sulfides, disulfides, thiophenes, porphyrins, phenols, naphthenic acids. The overwhelming majority of heteroatomic compounds are contained in the highest molecular weight fractions 02/10/2018 39

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The fractional composition of oil reflects the content of compounds that boil away in different temperature ranges. Oils boil away in a very wide temperature range – 28–550 °C and above. When heated from 40–180 °C, aviation gasoline boils away; 40–205 °С – motor gasoline; 200–300 °C – kerosene; 270–350 °C – naphtha. At higher temperatures, oil fractions boil away. Based on the content of light fractions that boil up to 350 °C, oils are divided into oils of type T 1 (more than 45%), 02/10/2018 40

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The density of reservoir oil depends on its composition, pressure, temperature, and the amount of gas dissolved in it (Fig. 1. 4). 10.02.2018 41

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The lower the density of the oil, the higher the yield of light fractions. Not all gases dissolving in oil have the same effect on its density. With increasing pressure, the density of oil decreases significantly when it is saturated with hydrocarbon gases. Carbon dioxide and hydrocarbon gases have the greatest solubility in oil, nitrogen has the least solubility. When pressure decreases, nitrogen is first released from oil, then hydrocarbon gases (first dry, then fatty) and carbon dioxide. 10.02.2018 42

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The pressure at which gas begins to be released from oil is called saturation pressure (Psat). The saturation pressure depends on the ratio of the volumes of oil and dissolved gas in the reservoir, on their composition, and reservoir temperature. Under natural conditions, the saturation pressure can be equal to the reservoir pressure or be less than it: in the first case, the oil is completely saturated with gas, in the second it is undersaturated with gas. The difference between saturation pressure and reservoir pressure 02/10/2018 can range from tenths to tens of 43

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Oil samples taken from different areas of the deposit may be characterized by different saturation pressures. This is due to changes in the properties of oil and gas within the area, with the influence of rock properties on the nature of gas release from oil, rock properties with the influence of the amount and properties of bound water and other factors. water Nitrogen dissolved in reservoir oil increases the saturation pressure. 10.02.2018 44

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 02/10/2018 45

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Viscosity is the ability of a liquid or gas to resist the movement of some layers of a substance relative to others. Dynamic viscosity is determined through Newton's law: (8) where A is the contact area of ​​moving layers of liquid (gas), m 2; F is the force required to maintain the difference in speed dv between layers H; dy – distance between moving layers of liquid (gas), m; - coefficient of dynamic viscosity (coefficient 02/10/2018 46

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The viscosity of reservoir oil always differs significantly from the viscosity of separated oil, due to the large amount of dissolved gas, increased pressure and dependence on temperature (Fig. 1. 5, 1. 6) . The viscosity of oil in reservoir conditions of various fields varies from hundreds of m. Pa∙s to tenths of m. Pa∙s. Under reservoir conditions, the viscosity of oil can be tens of times less than the viscosity of separated oil. 10.02.2018 47

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS In addition to dynamic viscosity, kinematic viscosity is used for calculations - the property of a fluid to resist the movement of one part of the fluid relative to another with (9) taking into account gravity: Where is the coefficient of kinematic viscosity, m 2/s; - oil density, kg/m 3. 10. 02. 2018 48

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Oil, like all liquids, has elasticity, i.e. the ability to change its volume under the influence of external pressure. The decrease in volume is characterized by the coefficient of compressibility (or volumetric elasticity): (10) where V is the volume occupied by oil at pressure P, m 3; V – change in oil volume when pressure changes by value P, m 3. The compressibility coefficient depends on: pressure, temperature, oil composition, amount of dissolved gas. Oils that do not contain dissolved gas have a relatively low compressibility coefficient of 0.4 - 0.7 GPa-1, and light oils with a significant content of dissolved gas have an increased compressibility coefficient (up to 14 GPa-1). 10.02.2018 49

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The amount of dissolved gas in oil is associated with the amount of dissolved gas in oil, the volumetric coefficient b (see Fig. 1. 5), which characterizes the ratio of volumes for a unit mass of oil in reservoir conditions and after gas separation on the surface: surface (11) where Vlayer is the volume of oil in reservoir conditions, m 3; Vdeg is the volume of oil at atmospheric pressure and a temperature of 20°C after degassing, m 3. Using the volumetric coefficient, you can determine the oil shrinkage U, i.e., the reduction in the volume of reservoir oil when extracting it to the surface, usually designated by the letter U (12) 10.02.2018 50

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Petroleum gases consist of a mixture of gaseous hydrocarbons, mainly of the paraffin series (methane, ethane, propane, butane), nitrogen, helium, argon, carbon dioxide, hydrogen sulfide. The content of nitrogen, hydrogen sulfide, and carbon dioxide can reach several tens of percent. Hydrocarbon gases, depending on composition, pressure, temperature, are in the deposit in various states of aggregation: Ø gaseous, Ø liquid, Ø in the form of gas-liquid mixtures. 10.02.2018 51

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS If there is no gas cap in an oil deposit, this means that all the gas is dissolved in the oil. As the pressure decreases during field development, this gas (associated petroleum gas) will be released from the oil. Density of the gas mixture: (13) where is the mole volume fraction; density – i-th component, kg/m3; Relative density of gas in air (14) For normal air conditions 1, 293 kg/m 3; for standard air conditions 1, 205 kg/m 3. 10. 02. 2018 52

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS If the gas density is specified at atmospheric pressure P 0 (0, 1013 MPa), then its recalculation to another pressure (at a constant temperature) for an ideal gas will be (15) Mixtures of ideal gases are characterized by the additivity of partial pressures and partial volumes. For ideal gases, the pressure of the mixture is equal to the sum of the partial pressures of the components (Dalton’s law (16): where P is the pressure of the mixture of gases, Pa; pi – partial pressure of the i-th component in the mixture, Pa; 10.02.2018 53

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS (17) The additivity of the partial volumes of the components of the gas mixture is expressed by Amag’s law: (18) Amag’s or (19) Where V is the volume of the gas mixture, m 3; Vi – volume of the i-th component in the mixture, s. The analytical relationship between pressure, temperature and volume of a gas is called the equation of state. The state of an ideal gas under standard conditions is characterized by the Mendeleev equation. Clapeyron PV = GRT where P – absolute pressure, Pa; V – volume, m 3; G – amount of substance, mol; R – 02/10/2018 universal gas constant, Pa∙m 3/mol∙deg; (20) 54

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS For ideal gas (21) Real gases do not obey the laws of ideal gas, and the compressibility coefficient z characterizes the degree of deviation of real gases from the Mendeleev-Clapeyron law. The deviation is associated with the interaction of gas molecules having a certain intrinsic volume. In practical calculations, z 1 can be taken at atmospheric pressure. With increasing pressure and temperature, the value of the supercompressibility coefficient increasingly differs from 1. The value of z depends on the composition of the gas, pressure, temperature (their critical and reduced values) and can be determined 55

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Critical pressure is the pressure of a substance (or mixture of substances) in its critical state. At pressures below critical, the system can decompose into two equilibrium phases - liquid and vapor. At critical pressure, the physical difference between liquid and vapor is lost, and the substance goes into a single-phase state. Therefore, critical pressure can be defined as the limiting (highest) pressure of saturated vapor under conditions of coexistence of the liquid phase and vapor. Critical temperature is the temperature of a substance in its critical state. For individual substances, the critical temperature is defined as the temperature at which the differences in physical properties between liquid and vapor, 02/10/2018 56

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS At critical temperatures, the densities of saturated vapor and liquid become the same, the boundary between them disappears and the heat of vaporization turns to 0. Knowing the compressibility coefficient, you can find the volume of gas in reservoir conditions: (22) where designations with the index “pl” refer to reservoir conditions, and with the index “0” - to standard (surface) conditions. 10.02.2018 57

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The volumetric coefficient of gas is used when converting the volume of gas under standard conditions to reservoir conditions and vice versa (for example, when calculating reserves): (23) The dynamic viscosity of gas depends on the average length distance and on the average speed of movement of molecules: (24) The dynamic viscosity of natural gas under standard conditions is small and does not exceed 0.01 - 0.02 m. Pa∙s. It increases with increasing temperature (as the temperature increases, the average speed and path length of the molecules increases), however, at a pressure of more than 3 MPa, the viscosity begins to decrease with increasing temperature. 58

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Gas viscosity is practically independent of pressure (a decrease in the speed and travel distance of molecules with increasing pressure is compensated by an increase in density). Solubility of gases in oil and water. From the amount of solubility of gases in oil and water. All of its most important properties depend on the gas dissolved in reservoir oil: viscosity, compressibility, thermal expansion, density, etc. The distribution of oil gas components between the liquid and gaseous phases is determined by the laws of dissolution processes. 10.02.2018 59

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The dissolution process for an ideal gas at low pressures and temperatures is described by Henry’s law (25) where VG is the volume of liquid – solvent, m 3; - gas solubility coefficient, Pa-1; VZh - amount of gas dissolved at a given temperature, m 3; P – gas pressure above the liquid surface, Pa. The gas solubility coefficient shows how much gas is dissolved in a unit volume of liquid at a given pressure: (26) 02/10/2018 60

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The solubility coefficient depends on the nature of the gas and liquid, pressure, temperature. The nature of water and hydrocarbons is different, so the hydrocarbon component of oil gas is less soluble in water than in oil. Non-hydrocarbon compounds of petroleum gas (CO, CO 2, H 2 S, N 2) dissolve better in water. For example, the formation water of the Cenomanian horizon is highly carbonated (up to 5 m 3 CO 2 per 1 ton of water). With increasing pressure, the solubility of a gas increases, and with increasing temperature it decreases. Gas solubility also depends on the degree of mineralization of water. 10.02.2018 61

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS When gas moves through the formation, the so-called throttling effect is observed - a decrease in the pressure of the gas flow as it moves through constrictions in the channels. At the same time, a change in temperature is also observed. The intensity of temperature change T with a change in pressure P is characterized by the Joule-Thomson equation: (27) where t is the Joule-Thomson coefficient (depends on the nature of the gas, pressure, temperature), K/Pa. 10.02.2018 62

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The composition of formation waters is varied and depends on the nature of the exploited oil reservoir, the physical and chemical properties of oil and gas. Formation waters always contain a certain amount of salts dissolved, mainly chloride salts (up to 80-90%) of the total salt content. Types of formation water: bottom (water filling the pores of the reservoir under the deposit); marginal (water filling the pores around the deposit); intermediate (between layers); residual (water in the oil-saturated or gas-saturated part of the reservoir, remaining from the time the deposit was formed). 10.02.2018 63

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Produced water is often an agent that displaces oil from the formation, and its properties affect the amount of displaced oil. The main physical properties of formation fluids are density and viscosity. The viscosity of the filtered fluid has a direct impact on the productivity of the well. 10.02.2018 64

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The appearance of water in the production of oil producing wells can lead to the formation of oil-water emulsions. Water globules in oil are quickly stabilized by the surface-active compounds and mechanical impurities contained in it (particles of clay, sand, steel corrosion products, iron sulfide), and then further dispersed. The resulting water-oil emulsions are characterized by high viscosity. The most stable emulsions are formed at a product water content of 35–75%. Oil watering under certain conditions can cause more intense formation of asphaltene-resin-paraffin deposits (ARPD). 10.02.2018 65

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 1. 5. Thermodynamic conditions All hydrocarbon deposits have a greater or lesser reserve of various types of energy that can be used to move oil and gas to the bottom of the wells. The potential of deposits significantly depends on the value of the initial reservoir pressure and the dynamics of its change during the development of the deposit. Initial (static) reservoir pressure Рpl. start is the pressure in the reservoir under natural conditions, i.e. before the start of extraction of liquids or gas from it. The value of the initial reservoir pressure in the deposit and outside it is determined by the characteristics of the natural water-pressure system to which the deposit is confined, and by the location of the deposit in this system. 10.02.2018 66

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Natural water pressure systems are divided into infiltration and elision systems, which differ in Ø formation conditions, Ø features of filtration processes and Ø pressure values. Hydrocarbon deposits associated with water-pressure systems of these types may have different values ​​of initial reservoir pressure at the same depth of productive formations. Depending on the degree of correspondence of the initial reservoir pressure at the depth of the reservoir layers, two groups of hydrocarbon deposits are distinguished: deposits with an initial reservoir pressure corresponding to hydrostatic pressure; corresponding to the hydrostatic pressure of the deposit with initial reservoir pressure, 02/10/2018 67

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS In geological and field practice, it is customary to call deposits of the first type deposits with normal reservoir pressure, and deposits of the second type – deposits with abnormal reservoir pressure. Such a division is conditional, since any value of the initial reservoir pressure is associated with the geological features of the area, and is normal for the geological conditions under consideration. In an aquifer, the initial reservoir pressure is considered equal to hydrostatic pressure when the corresponding piezometric height at each point approximately corresponds to the depth of the formation. Reservoir pressure close to hydrostatic is typical for infiltration water-pressure systems and associated deposits. Within oil and gas deposits, the values ​​of the initial reservoir pressure exceed the value of this indicator in the aquiferous part of the formation at the same absolute elevations of the formations. 10.02.2018 68

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The magnitude of the excess depends on The magnitude of the excess depends on the degree of difference in the density of formation water, oil and gas, and on the vertical distance from the considered points of the reservoir to the OWC. The difference between reservoir and hydrostatic pressure at one absolute reservoir elevation is usually called excess reservoir pressure Rizb. In infiltration systems, the vertical gradient of reservoir pressure for oil and gas deposits, even taking into account excess pressure, usually does not go beyond 0.008 0.013 MPa/m. The upper limit is typical for gas deposits at high altitudes. Increased reservoir pressure in the crests of reservoirs of infiltration water-pressure systems should not be confused with superhydrostatic pressure. 10.02.2018 69

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The correspondence of the formation pressure to the hydrostatic one, i.e., the depth of the formation, is judged by the pressure value in the aquiferous part of the formation directly at the boundaries of the deposit. With a vertical gradient of more than 0.013 MPa/m, the reservoir pressure is considered superhydrostatic (SGPD); with a gradient of less than 0.008 MPa/m, it is considered less than hydrostatic. In the first case, there is ultra-high (SVHP), in the second - ultra-low (SLLP) reservoir pressure. The presence of SGPD in reservoir layers can be explained by the fact that at a certain stage of geological history the reservoir receives an increased amount of liquid due to the excess of its inflow rate over the outflow rate. 10.02.2018 70

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS In such systems, pressure is created by squeezing water out of reservoir layers during their compaction under the influence of hydrostatic pressure, geodynamic processes, as a result of rock cementation, thermal expansion of water, etc. In an elision system, the recharge area is the most submerged part of the reservoir formation, from which water moves in the direction of formation uplift to the discharge areas. Part of the geostatic pressure is transferred to this water, so the formation pressure in the water-saturated part of the formation adjacent to the hydrocarbon deposit increases compared to normal hydrostatic pressure. With an increase in the closedness of the water-pressure system and the volume of water squeezed into it, the SGPD values ​​increase. This is especially typical for layers located at great depths between thick layers of clayey rocks, in inter-salt and sub-salt 02/10/2018 71

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Within elision water pressure systems, the pressure in the hypsometrically high parts of oil and gas deposits, as well as within infiltration systems, is slightly increased due to excess reservoir pressure. Reservoir pressure is less than hydrostatic ( with a vertical gradient of less than 0.008 MPa/m), is rare. The presence of low pressures in reservoir layers can be explained by the fact that at a certain stage of geological history, conditions were created that led to a shortage of formation water in the reservoir, for example, with an increase in porosity associated with leaching or recrystallization of rocks. The volume of water saturating the void space may also decrease due to a decrease in the temperature of the formations 02/10/2018 72

I. Factors that determine the geological and physical characteristics of productive layers and the operating conditions of extracting wells, the initial reservoir pressure in the deposits, nature and size of the water system largely determine the phase state of hydrocarbons in the bowels, the natural energy characteristic of the deposit, the choice and implementation of the development system, the patterns of changes parameters of the deposit during its operation, levels and dynamics of annual oil and gas production. The value of the formation pressure of the deposit must be taken into account when estimating the porosity and permeability of the formations in their natural occurrence from the core. The indicated parameters determined from the core in surface conditions can be significantly 02/10/2018 overestimated, which will lead to incorrect determination 73

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Knowledge of the value of the initial reservoir pressure of the deposit and all overlying reservoir layers is necessary when justifying the drilling technology and well design, i.e. to ensure drilling of the well without absorption of the drilling fluid, emissions, collapses, stuck pipes, increasing the degree of perfection of formation penetration without reducing the productivity of the reservoir compared to its natural characteristics. The correspondence of reservoir pressure to hydrostatic pressure can serve as an indicator of the reservoir’s association with an infiltration water-pressure system. Under these conditions, it can be expected that during reservoir development the reservoir pressure will decrease relatively slowly. When drawing up the first project document for development 02/10/2018 74

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Data on formation temperature are necessary when studying the properties of formation fluids (oil, gas and water), determining the formation regime and the dynamics of groundwater movement, when solving various technical issues related with well plugging, perforation, etc. Temperature measurements in wells lined or uncased with pipes are carried out with a maximum thermometer or an electric thermometer. 10.02.2018 75

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Before measurement, the well must be at rest for 20 - 25 days in order for the natural temperature regime disturbed by drilling or operation to be restored. During the drilling process, temperature is usually measured in wells that are temporarily stopped for technical reasons. In production wells, temperature measurement turns out to be reliable only for the depth range of the productive (production) formation. To obtain reliable temperature data in other intervals, the well must be stopped on February 10, 2018 for a long period. 76

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS For this purpose, inactive or temporarily mothballed production wells are used. When taking measurements in wells, one should take into account a possible decrease in natural temperature due to gas manifestations (throttle effect). Temperature measurement data is used to determine the geothermal step and geothermal gradient. Geothermal stage - the distance in meters during deepening by which the temperature of the rocks naturally increases by 1°C, is determined by the formula: (28) 02/10/2018 77

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS where G – geothermal stage, m/°C; H – depth of the temperature measurement location, m; h – depth of the layer with constant temperature, m; T – temperature at depth Н, °С; t – constant temperature at depth h, °C. To more accurately characterize the geothermal stage, it is necessary to have temperature measurements along the entire wellbore. Such data make it possible to calculate the value of the geothermal step in different intervals of the section, as well as determine the geothermal gradient, i.e., the increase in temperature in °C with deepening by (29) every 100 m. 02.10.2018 78

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS In areas of difficult water exchange, the value of the geothermal stage in an aquifer complex depends on its hypsometric position. If the aquifer has a low elevation, then the value of the geothermal stage will take a reduced value . In areas of weak water movement, with virtually no water exchange, the geothermal stage is 02/10/2018 79

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Using the geoisotherm map, one judges the attenuation of underground flow due to the deterioration of the permeability of sandstones, monitors the dynamics and direction of movement of groundwater. The magnitude of the geothermal gradient increases in zones and decreases in synclinal zones, t That is, anticlines are zones of increased temperature, and synclines are zones of low temperature. For the upper layers of the earth's crust (10 - 20 km), the value of the geothermal step is on average 33 m/°C and 02/10/2018 80

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 1. 6. HYDRODYNAMIC OPERATING REGIME OF THE DEPOSITS The natural regime of the deposit is the set of natural forces (types of energy) that ensure the movement of oil or gas in the reservoir to the surface production well pits. In oil deposits, the main forces that move the formations are: the pressure of the contour water, which arises under the influence of its mass; mass pressure of contour water created by elastic expansion of rock and water; gas pressure in the gas cap; elasticity of gas released from oil dissolved in 81 02/10/2018; gas

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS When one of the above energy sources is predominant, the regimes of oil deposits are distinguished accordingly: 1. water-pressure; 2. elastic water pressure; 3. gas pressure (gas cap mode); 4. dissolved gas; 5. gravitational. 10.02.2018 82

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The natural regime of a deposit is determined (mainly) by geological factors: the characteristics of the water-pressure system to which the deposit belongs, and the location of the deposit in this system relative to the recharge area; geological and physical characteristics of the deposit (thermobaric conditions, phase state of hydrocarbons and their properties); conditions of occurrence and properties of reservoir rocks; degree of hydrodynamic connection of the deposit with 83 10.02.2018

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The formation regime can be significantly influenced by the operating conditions of the deposits. When using natural energy when developing deposits, the following depend on the regime: the intensity of the reduction in reservoir pressure depends; energy reserve of the deposit at each stage of development; behavior of the moving boundaries of the deposit (GNK, GVK, VNK); change in deposit volume as extraction progresses 02/10/2018 84

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The reserve of natural energy and the forms of its manifestation determine the efficiency of deposit development: deposits, the rate of annual oil (gas) production; dynamics of other development indicators; possible degree of final recovery of reserves from the subsoil. 10.02.2018 85

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The operating mode of the deposit affects the duration of operation of the wells in various ways; choice of field development scheme for the field, etc. The regime of the deposit during its operation can be judged from the curves of changes in reservoir pressure and gas factor of the entire deposit. 10.02.2018 86

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 1. In water pressure mode, the main type of energy is the pressure of marginal water, which penetrates into the deposit and completely compensates for the amount of liquid taken from the well. The volume of oil deposits is gradually decreasing due to the rise of the OWC. To reduce the extraction of associated water from the formation, in wells drilled near or within the OWC, the lower part of the oil-saturated formation is usually not perforated. 10.02.2018 87

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Water pressure regime manifests itself in deposits associated with infiltration water-pressure systems, with a good hydrodynamic connection of the deposit with the boundary zone of the reservoir and with the feeding area, with large dimensions of the contour areas. 10.02.2018 88

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS For the water pressure regime to be effective, it is necessary to have a significant difference between the initial reservoir pressure and the saturation pressure of oil with gas, and to maintain this difference as long as possible, keeping the gas in a dissolved state . In water-pressure mode, a high oil recovery factor is achieved - 0.6 0.7. This is due to the ability of water (especially mineralized reservoir water) to wash out oil well and displace it from 10.02.2018 voids of reservoir rocks + combination 89

I. Factors that determine the geological and physical characteristics of the productive layers and the operating conditions of producing wells 2. The elastic regime is the mode in which oil is displaced from the layer under the influence of the pressure of the regional water, but the main source of energy is the elasticity of the breeders and their fluid saturating them. 10.02.2018 90

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 1. Liquid withdrawal is not fully compensated by water penetrating into the reservoir 2. The decrease in pressure in the reservoir gradually spreads beyond the boundaries of the reservoir and covers the area of ​​the aquiferous part of the reservoir. 3. Here the expansion of rock and formation water occurs. 4. The elasticity coefficients of water and rock are insignificant, however, if the area of ​​reduced pressure is significant (many times larger than the size of the deposit), the elastic forces of the formation create a significant supply of energy. 10.02.2018 91

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The volume of oil obtained from the deposit due to elastic forces when the reservoir pressure in it decreases by P can be expressed by the formula (30) where, are the volumes of oil obtained due to elastic forces of the deposit itself and the aquiferous area of ​​the formation, respectively, m 3; Vн, Vв – volumes of the oil-bearing part of the formation and the aquiferous part involved in the process of reducing reservoir pressure m 3; , is the volumetric elasticity of the formation in the oil-bearing and aquiferous parts (where m is the average porosity coefficient, Pa-1; w, p, are the coefficients of volumetric elasticity of liquid and rock), Pa-1. The proportion of oil obtained due to the elasticity of the oil-bearing region of the formation is small, since the volume of the deposit is (most often) less than the volume of the aquifer region. 10.02.2018 92

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Elastic water-pressure regime usually manifests itself 1. in deposits of infiltration water-pressure systems, 2. with a weak hydrodynamic connection with the supply area (due to great distance), 3. reduced permeability reservoir capacity and increased oil viscosity; 4. in large-sized deposits with significant fluid withdrawals that are not fully compensated by formation water penetrating into the deposit; 5. in deposits confined to elision water-pressure systems. 10.02.2018 93

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Conditions of existence: occurrence of the reservoir layer over a large area outside the deposit; excess of the initial reservoir pressure above the saturation pressure. Conditions are worse than under water pressure mode. KIN – 0.55. 10.02.2018 94

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 3. Gas pressure regime - oil is forced out of the formation under the influence of gas pressure contained in the gas cap. In this case, during the development of the deposit, the reservoir pressure decreases, the gas cap expands, and the gas oil moves downward. 10.02.2018 95

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Since in oil and gas deposits the saturation pressure is most often close to the initial reservoir, soon after the start of development the reservoir pressure becomes lower than the saturation pressure, saturation as a result of which the release of dissolved oil begins there is gas in it and with high vertical permeability of the formation, gas partially replenishes the gas cap of the m. Gas pressure regime in its pure form is possible in deposits that do not have a hydrodynamic connection since 02/10/2018 96

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Reasons for the separation of the reservoir and the aquifer area: Ø a sharp decrease in permeability in the peripheral zone of the reservoir near the OWC; Ø the presence of tectonic disturbances limiting the deposit, etc. Geological conditions conducive to the manifestation of gas pressure regime: the presence of a large gas cap with a sufficient supply of energy to displace oil; significant height of the oil part of the deposit; deposits have high vertical permeability of the formation; vertical low viscosity of reservoir oil (2 – 3 m. Pa s). 10.02.2018 97

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS When developing a deposit, due to the subsidence of the gas oil condensate, the volume of the oil part of the deposit is reduced. To prevent premature gas breakthroughs into oil wells, the lower part of the oil-saturated thickness is perforated at a certain distance from the gas oil condensate. When developing under gas pressure conditions, the reservoir pressure constantly decreases. The rate of its decline depends on The rate of its decline depends on the ratio of the volumes of the gas and oil parts of the deposit, 02/10/2018 98

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF CIN PRODUCTION WELLS under gas pressure conditions of 0.4. This is explained by the instability of the displacement front (advanced movement of gas along the most permeable parts of the formation), the formation of gas cones, and reduced displacement efficiency oil gas, compared to water. 10.02.2018 99

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The average gas factor for a deposit in the initial period of development can remain approximately constant. As the GOC is lowered, gas from the gas cap enters the wells, gas is released from the oil, the value of the gas factor begins to increase sharply, and the level of oil production decreases. Oil production is carried out practically without associated water. Found in its pure form in Krasnodar 02/10/2018 100

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 4. Dissolved gas regime - a regime in which reservoir pressure decreases during development below the saturation pressure, as a result of which gas is released from the saturation solution and bubbles of occluded gas expand , displace oil to wells. The regime in its pure form manifests itself in the absence of the influence of the aquifer region, with close or equal values ​​of the initial reservoir pressure and saturation pressure, with an increased gas content of reservoir oil, 02/10/2018 101

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS During the development process, the oil saturation of the formation decreases, the volume of the deposit remains unchanged. In this regard, the entire oil-saturated thickness of the formation is perforated in production wells. 10.02.2018 102

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS Dynamics of reservoir development in the dissolved gas regime: reservoir pressure is steadily and intensively decreasing, the difference between the saturation pressure and the current formation pressure increases over time, the gas factor is at first constant, then increases and several times higher than the reservoir gas content, degassing of reservoir oil leads to a significant increase in its viscosity, over time, due to degassing of reservoir oil, the gas factor is significantly reduced, for the entire development period the average value of the field gas factor is 4 - 5 times higher than 103 10. 02 .2018

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The formation of narrow depression craters near each well is typical. The placement of production wells is more dense than in regimes where oil is displaced by water. The final oil recovery factor is 0.2 – 0.3, and with low gas content – ​​0.15. 10.02.2018 104

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 5. Gravity regime - oil moves in the formation to the wells under the influence of gravity of the oil itself. It operates when the deposit has no other energy sources or their reserves have been exhausted. It appears after the end of the dissolved gas regime, i.e. after degassing of oil and a decrease in reservoir pressure. Although, sometimes it can be natural. The manifestation of the regime is facilitated by the significant height of the oil-saturated part of the reservoir formation, 02/10/2018 105

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The production rate increases with a decrease in the hypsometric marks of the formation opening intervals. The upper part of the deposit is gradually filled with gas released from the oil, the volume (of the oil part) of the deposit decreases, oil is withdrawn at a very low rate - up to 1% per year of recoverable reserves. The reservoir pressure in this mode is usually tenths of MPa, the gas content is a few cubic meters per 1 m3. When using development systems that maintain reservoir pressure, the gravity regime is practically non-existent 02/10/2018 106

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS SUMMARY 1. Currently, natural regimes are used only if they provide an oil recovery of 40% or more. Usually this is either a water-pressure regime or an active elastic-water-pressure regime. 2. The elastic-water-pressure regime in its pure form usually operates when extracting the first 5–10% of recoverable oil reserves, 3. When the reservoir pressure decreases below the saturation pressure, the dissolved gas regime becomes of primary importance. 4. Ineffective natural regimes, usually at the very beginning of development, are transformed into more 10.02.2018 107

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 5. The type of regime must be established in the early stages of drawing up the first development documents to properly substantiate the development system, to resolve the issue of the need to influence the formation, to select the method of stimulation. 6. The type of regime is determined based on the study of the geological and hydrogeological features of the water pressure system as a whole and the geological and physical characteristics of the deposit itself. 10.02.2018 108

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS The study of the water-pressure system involves: clarification of the regional conditions of the horizon, the nature of the natural water-pressure system (infiltration, elision) and its size, the position of recharge and drainage areas, the location of deposits in the water supply noah system relative to the feeding area, factors determining the hydrodynamic connection of various points of the system (location conditions, permeability, nature 10.02.2018 109

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS For the reservoir under study, it is necessary to obtain data: on its size, on the degree of connectivity of the reservoir with the boundary area, on the structure and properties of the reservoir within the reservoir, on the phase state and properties of reservoir oil and gas, thermobaric conditions of the productive reservoir. 10.02.2018 110

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS 7. Analogs in determining the development mode of a deposit are previously put into operation deposits of the same horizon with similar geological and physical characteristics. 8. In the absence or insufficiency of indirect data, part of the deposit is put into short-term trial operation (exploration wells), during which the following are measured and controlled: changes in reservoir pressure in the deposit itself and in the boundary area, behavior of the gas factor, water cut in wells, productivity, interaction of the deposit with contour area and the activity of the latter (observation of pressure in piezometric 111 10.02.2018

I. FACTORS DETERMINING THE GEOLOGICAL AND PHYSICAL CHARACTERISTICS OF PRODUCTIVE FORMATIONS AND OPERATING CONDITIONS OF PRODUCTION WELLS When piezometric wells are located at different distances from the reservoir, not only the very fact of this interaction can be revealed, but also the nature of the general depression funnel in the formation. Leading production wells for trial operation are drilled to obtain the necessary information in a relatively short time, since these wells can produce high oil production in a short period of time. 10.02.2018 112

Ministry of Education and Science of the Russian Federation
Branch of the Federal State Budgetary Educational Institution
institutions of higher professional education
"Udmurt State University" in Votkinsk

Test
In the discipline “Well Productivity Management and
intensification of oil production"

Completed by: student of group Z-Vt-131000-42(k)
Lonshakov Pavel Sergeevich

Checked by: Ph.D., Associate Professor Borkhovich S.Yu.

Votkinsk 2016

Selection of candidate wells for treatment of near-wellbore zones.

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.
The bottomhole formation zone is 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 environment 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 the solution or its filtrate into the bottom-hole zone of the formation. When the filtrate interacts with formation mineralized water, the formation of insoluble salts and their precipitation, swelling of clay cement and clogging of persistent emulsions, and a decrease in the phase permeability of wells can occur. There may be poor quality perforation due to the use of low-power perforators, especially in deep wells, where the emulsion of explosion charges is absorbed by the energy of high hydrostatic pressures.
A decrease in the permeability of the bottomhole zone of the formation 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 vapor space of the reservoir.
Intense contamination of the bottomhole zone of the formation is also observed as a result of the penetration of working fluids during various repair work in wells. The injectivity of injection wells deteriorates due to clogging of the pore space with petroleum products contained in the injected water. As a result of the penetration 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.
In wells with a contaminated bottom-hole zone, a drop in fluid production is observed while maintaining the same operating conditions, lower flow rates compared to nearby wells of the given field. Identification of such wells is carried out on the basis of field data or as a result of calculations. The calculation method is as follows: the radius of the well drainage area is estimated and the fluid flow rate is calculated using the Dupuis formula; if the calculated flow rate is significantly higher than the actual one, then it can be assumed that there is contamination of the bottomhole zone. In addition, deterioration of reservoir properties in the near-wellbore zone can be identified based on the results of hydrodynamic studies.
The effectiveness of using a particular method of influencing a development object is determined by the geological characteristics of the reservoir, the properties of formation fluids and parameters characterizing the state of development. The selection of wells for OPD based on the average characteristics of the field is not always successful, especially for productive carbonate deposits characterized by layered and zonal heterogeneity of reservoirs, both in structure and properties.
The main geological criteria that determine the success of the application of OPP include the following:
a. type of reservoir (fractured, fractured-pore or pore), which determines the component composition for waterproofing compositions (for example, for...