The main technological indicators characterizing the process of developing an oil field (deposit) include: annual and cumulative production of oil, liquid, gas; annual and cumulative agent (water) injection; water cut of produced products; selection of oil from recoverable reserves; stock of production and injection wells; oil withdrawal rates; compensation of fluid withdrawal by water injection; current and final (design) oil recovery factor; well flow rates for oil and liquid; well injectivity; dynamics of reservoir pressure, drilling volumes, commissioning of production and injection wells, decommissioning of wells, etc.
The efficiency of the development process is also assessed by the ratio of the share of recovered oil from the initial recoverable reserves and the current water cut, by the current and accumulated balance of water injection and fluid withdrawal from the reservoir, by the reduction of reservoir pressure (relative to the initial value), etc.
Let us present a methodology for calculating the main technological indicators of the process of developing an oil field (deposit).
1. Annual oil production ( qt, t/year) - oil production from all production wells in one year. Oil production for the future period is determined using various methods and computer programs. When developing deposits at the final stages (with decreasing oil production), annual oil production ( q t ,) , number of miners 2 - ( n tд ) and injection wells 3 - ( n tн ) can be determined using the formulas [9]:
2. 
(3.11)
2. 
(3.12)
Where t – serial number of the accounting year ( t =1, 2, 3, 4, 5); q 0 – amplitude oil production for 10 years; e =2.718 – base of natural logarithms; Q ost – residual recoverable oil reserves; n 0d And n 0н - number of wells at the beginning of the accounting year, production and injection, respectively; T- average well life, years; in the absence of actual data, the standard depreciation period for a well (20 years) can be taken as T.
4. Annual oil withdrawal rate t bottom – ratio of annual production ( q t ) to initial recoverable reserves ( Q bottom ), %:
t bottom = q t / Q bottom (3.13)
5. Annual oil withdrawal rate t oiz , % - of residual (current) recoverable reserves - ratio of annual production ( q t ) to residual recoverable reserves ( Q oiz ) - residual recoverable oil reserves at the beginning of the calculation (the difference between the initial recoverable reserves and accumulated oil production at the beginning of the calculation year:
t oiz = q t / Q oiz (3.14)
6. Oil production from the beginning of development (cumulative oil extraction) Q nak - sum of annual oil withdrawals at the end of the year, thousand tons:
Q nak = q t1 + q t2 + q t3 + …… + q tn-1 + q tn, (3.15)
7. Oil selection from initial recoverable reserves With Q – ratio of accumulated oil production to initial recoverable reserves), %:
With Q = Q top / Q bottom (3.16)
8. Oil recovery factor ( KIN ) or oil recovery factor - the ratio of the accumulated oil recovery to the initial geological or balance oil reserves, fractions of units:
KIN = Q nak / Q ball (3.17)
9. Liquid extraction from the beginning of development Q – sum of annual fluid withdrawals ( q ) for the current year, thousand tons:
Q l = q l1 + q l2 + q l3 +……..+q ln-1 +q ln (3.18)
10. Average annual water cut - the share of water in well production W , – ratio of annual water production ( q in ) to annual liquid production ( q ), %:
W = q in / q f (3.19)
11. Water injection since the beginning of development - the sum of annual water injection values ( q order ) at the end of the reporting year, thousand m 3:
Q order = q order1 + q order2 + q order3 +……….+ q order n-1 + q order n (3.20)
12. Compensation for fluid withdrawal by water injection per year (current) – the ratio of annual water injection to annual fluid production, %:
K g = q order / q f (3.21)
13. Compensation for fluid withdrawal by water injection from the beginning of development (cumulative compensation) – the ratio of accumulated water injection to accumulated liquid withdrawal, %:
K nak = Q zak / Q w (3.22)
14. Production of associated petroleum gas for the year is determined by multiplying the annual oil production by the gas factor ( G f ), million m 3:
q gas = q t . G f (3.23)
15. Production of associated petroleum gas from the beginning of development - the sum of annual gas withdrawals, million m 3:
Gas Q = q gas1 + q gas2 + q gas3 +……….+ q gas n-1 + q gas n (3.24)
16. The average annual oil production rate of one production well is the ratio of annual oil production to the average annual number of production wells ( n ext ) and the number of days in a year ( T g ), taking into account the operating rate of production wells, ( K e.d. ), t/day:
q well = q t / n ext T g K e.d, (3.25)
Where K e.d. is equal to the ratio of the sum of days (days) worked by all production wells during a calendar year to the number of these wells and the number calendar days(days) per year, and which is taken equal to 0.98.
17. The average annual liquid production rate of one production well is the ratio of the annual liquid production to the average annual number of production wells and the number of days in a year, taking into account the production well operation rate, t/day:
q well = q w / n ext T g K e.d, (3.26)
18. Average annual injectivity of one injection well - the ratio of the annual water injection to the average annual number of injection wells ( n naked ) and the number of days per year, taking into account the operating rate of injection wells ( K.E.N. ), m 3 /day:
q well = q zak / n nag T g K e.n, (3.27)
Where K.E.N. is equal to the ratio of the sum of days worked by all injection wells during a calendar year to the number of these wells and the number of calendar days in a year.
19. Reservoir pressure for the 20th year of development tends to decrease if the accumulated compensation K nak less than 120%, i.e. R pl t ≤ R pl n ≥; if the accumulated compensation is in the range from 120 to 150%, then the reservoir pressure is close to or equal to the initial R pl t = R pl n ; if the accumulated compensation is more than 150%, then the reservoir pressure tends to increase and may be higher than the initial one R pl t ≥ R pl n .
Development technology is a set of methods used to extract oil from the subsoil. There are many indicators of technological development, but there are common ones for all, let’s look at them:
1. Oil extraction from a field during its development, which is divided into four stages.
2. The rate of development of an oil field can be represented as the ratio of current oil production q n (t) to the geological reserves of the field G
Z(t q n (t)) = q n (t) / G
3. Liquid production from a field is the total production of oil and water.
4. Oil recovery is the ratio of the amount of oil extracted from the reservoir to its initial reserves in the reservoir. They distinguish between current - the ratio of the amount of oil extracted from the reservoir at the moment of reservoir development to its initial reserves. Final oil recovery is the ratio of the amount of oil produced to its initial reserves at the end of reservoir development.
5. Gas extraction from an oil field during its development. This factor is characterized by the gas factor Gf.
6.Consumption of substances injected into the formation and their extraction together with oil and gas (ordinary water, water with additives of chemical reagents, hot water or steam, hydrocarbon gases, air, carbon dioxide, etc.).
7.Distribution in the reservoir.
8. Pressure at the mouth of the production well
9. Distribution of wells according to the method of lifting fluid from the bottom to the surface.
10. Reservoir temperature.
5 . What is called a development object. How the object is developed. What is a feature of an object? Is it possible to develop different objects with the same wells by using technical means.
Development object- this is an artificially isolated geological formation (layer, massif, structure, set of layers) within the developed field, containing industrial reserves of hydrocarbons, the extraction of which from the subsoil is carried out using certain group wells or other mining structures. Developers, using terminology common among oil industry workers, usually believe that each object is developed with its own network of wells. It must be emphasized that nature itself does not create development objects - they are allocated by people developing the field. The development object may include one, several or all layers of the field.
Main features of the development object- the presence of commercial oil reserves in the formations and a certain group of wells inherent to a given object, with the help of which it is developed. At the same time, one cannot say the opposite, since the same wells can be used to develop different objects by using technical means for simultaneous and separate operation. The main factors are:
Geological and physical properties of the formation;
Recoverable oil reserves, million tons.
Thickness, m
Permeability, 10~3μm2
Oil viscosity - Z Kti,.1IO-3 P 3 Pa-s
Development objects are sometimes divided into the following types: independent, i.e., being developed at a given time, and return, i.e., one that will be developed by wells exploiting another object during this period.
6. Name the main factors influencing the allocation of development objects. How do the geological and physical properties of reservoir rocks influence the identification of development objects?
Factors influencing the allocation of development objects
1. Geological and physical properties of oil and gas reservoir rocks.
In many cases, formations that differ sharply in permeability, total and effective thickness, as well as heterogeneity are not advisable to develop as one object, since they can differ significantly in productivity, reservoir pressure during their development and, consequently, in the methods of well operation and the rate of production of oil reserves and changes in product water cut. For formations with different areal heterogeneity, different well patterns can be effective, so combining such formations into one development object turns out to be impractical. In formations that are highly heterogeneous vertically and have individual low-permeability interlayers that are not connected to high-permeable ones, it can be difficult to ensure acceptable vertical coverage of the horizon due to the fact that only high-permeability interlayers are included in active development, and low-permeability layers are not exposed to the agent injected into the formation (water , gas). In order to increase the development coverage of such formations, they are trying to divide them into several objects.
2. Physico-chemical properties of oil and gas.
The properties of oils are important when identifying development objects. It may be impractical to combine reservoirs with significantly different oil viscosity into one object, since they can be developed using different technologies for extracting oil from the subsoil with different layouts and well spacing. Sharply different contents of paraffin, hydrogen sulfide, valuable hydrocarbon components, and industrial contents of other minerals can also make it impossible to jointly develop the formations as one object due to the need to use significantly different technologies for extracting oil and other minerals from the formations.
3. Phase state of hydrocarbons and formation regime.
4. Conditions for managing the process of developing oil fields.
5. Equipment and technology of well operation.
There may be numerous technical and technological reasons leading to the expediency or inexpediency of using certain options for highlighting objects. For example, if from wells exploiting a certain formation or group of formations identified as development objects, it is planned to take such significant fluid flow rates that they will be limiting for modern means well operation. Therefore, further consolidation of objects will be impossible for technical reasons.
In conclusion, it should be emphasized once again that the influence of each of the listed factors on the selection of development objects must first be subjected to technological and technical-economic analysis, and only after this can a decision be made on the allocation of development objects.
7. The influence of physical and chemical properties of oil and gas on the identification of development objects. The feasibility of combining formations with significantly different oil viscosity into one object.
The properties of oils are important when identifying development objects.
It may be impractical to combine formations with significantly different oil viscosity into one object, since they can be developed using different technologies for extracting oil from the subsoil with different layouts and well patterns.
Sharply different contents of paraffin, hydrogen sulfide, valuable hydrocarbon components, and industrial contents of other minerals can also make it impossible to jointly develop the formations as one object due to the need to use significantly different technologies for extracting oil and other minerals from the formations.
It is impossible to combine a pure oil reservoir and an oil reservoir with a gas cap into one object. Combining these formations into one object is impractical, since the development of each of them requires different well layouts and oil and gas extraction technologies.
Independent development objects can be layers that have significant thickness with thick impermeable sections. With a small thickness of the layers and the presence of confluence zones, which complicate the separate injection of water into each layer and the regulation of development processes, the layers are combined into a single operational object. When identifying development objects, the following factors should be taken into account:
1. Geological and physical properties of oil and gas reservoir rocks. One development object can include layers that have similar lithological characteristics and reservoir properties of productive formation rocks, values of initial reduced reservoir pressures, and coincide in terms of oil-bearing area. It is impractical to combine strata that differ sharply in permeability, total and effective thickness, as well as initial reservoir pressure into one object. It is also inappropriate to combine strata that differ greatly in areal and layer-by-layer heterogeneity into one development object.
Reservoirs that differ significantly in productivity and reservoir pressure will differ in development methods, the rate of production of oil reserves and changes in the water cut of wells, so their inclusion in one development object will inevitably lead to a decrease in oil recovery for the entire object.
In the process of developing multi-layer production facilities in oil fields, it was noticed that the average productivity coefficient of wells Kpsov, exploiting several formations together, is less than the sum of Kpsum average productivity coefficients of wells exploiting the same formations separately. The physical essence of this phenomenon has not been sufficiently studied. A number of researchers believe that the decrease in productivity occurs due to fluid flows between layers, others explain losses due to hydraulic resistance in the wellbore, some researchers explain this by the mutual influence of the exploited formations.
If a large number of formations are combined into one production facility, the maximum value of the reduction in the productivity coefficient of wells during joint operation of formations compared to separate operation reaches 35-45%.
2. Physico-chemical properties of oil, water and gas. Reservoirs containing oil with different properties, for example, viscosity, are not advisable to combine into one development object, since in order to extract products it is necessary to use different technologies for influencing them, requiring a different arrangement system and a different well pattern density.
The physical and chemical properties of formation waters and their ability to mix are of significant importance when identifying objects. For example, injection of water into a formation containing formation water of a certain composition can cause chemical reactions, as a result of which the conditions for filtration of liquids deteriorate.
3. Phase state of hydrocarbons and formation regimes. For example, it is impossible to combine a pure oil reservoir and an oil reservoir with a gas cap into one object. Combining these formations into one object is impractical, since the development of each of them requires different well layouts and oil and gas extraction technologies.
4. The ability to control the development process (it is impractical to combine many layers into one object)
5.Development technology and technology - technology operation of wells (if it is profitable to develop the formations independently, then it is not advisable to combine them)
The feasibility of combining layers into one exploitation object, previously established based on the listed geological characteristics, is further clarified by technological analysis and technical and economic calculations.
One of the latest achievements in production technology and technology is the technology of simultaneous-separate exploitation (SSE) of formations. The use of such technology makes it possible to combine the advantages of disaggregating development objects with the advantages of joint exploitation of formations. With this technology, a well can produce oil from two objects simultaneously, providing each of the objects with its own optimal impact specifically for this object. Thus, there is no loss of recoverable reserves, and the profitability of the process increases by reducing the number of wells required.
At the same time, the most economical is the single-lift modification of the ORE, when the mixing of fluids produced from two objects occurs in one tubing in the well. However, this modification complicates the process of monitoring the development of individual objects and, moreover, is not applicable when there are significant differences in the physicochemical properties of formation fluids. The two-lift design allows the use of one well for completely separate production of hydrocarbons from two objects using different tubing. Simultaneous-separate injection technologies are also being developed.
8. Influence on the identification of development objects of the phase state of hydrocarbons and formation regime. What phase states do hydrocarbons have in formations? Name the operating modes of the formations.
Various formations that lie relatively close to each other vertically and have similar geological and physical properties, in some cases, it is inappropriate to combine into one object as a result of the different phase state of formation hydrocarbons and formation regimes. Thus, if one formation has a significant gas cap, and the other is developed under natural elastic-water-pressure conditions, then combining them into one object may not be practical, since their development will require various schemes location and number of wells, as well as various oil and gas extraction technologies.
Classification of deposits by phase state of hydrocarbons
Based on the initial phase state and composition of the main hydrocarbon compounds in the depths, deposits are divided into single-phase and two-phase.
Single-phase deposits include:
a) oil deposits confined to reservoir layers containing oil saturated to varying degrees with gas;
b) gas or gas condensate deposits confined to reservoir layers containing gas or gas with hydrocarbon condensate.
Two-phase deposits include deposits confined to reservoir strata containing oil with dissolved gas and free gas above the oil (oil reservoir with a gas cap or gas reservoir with an oil rim). In some cases, the free gas of such deposits may contain hydrocarbon condensate. Based on the ratio of the volume of the oil-saturated part of the deposit to the volume of the entire deposit ( V n = V n / V n + Vr), two-phase deposits are divided into:
a) oil with a gas or gas condensate cap ( V n 0.75);
b) gas or gas condensate-oil (0.50< V н О,75);
c) oil and gas or oil and gas condensate (0.25< V н 0,50);
d) gas or gas condensate with an oil rim ( V n 0.25).
Depending on which reserves prevail, the main production object in two-phase deposits is considered to be the gas-saturated or oil-saturated part.
The formation regime is understood as the nature of the manifestation of the driving forces that ensure the movement of oil in the formations to the bottoms of production wells. Knowing the operating modes is necessary for designing a rational field development system and efficient use of reservoir energy in order to maximize the extraction of oil and gas from the subsoil.
The following modes are distinguished:
1- water pump,
2- elastic and elastic-water-pressure,
3-gas pressure or gas cap mode,
4-gas or dissolved gas mode,
5-gravity,
6- mixed.
1) Water-pressure regime - a regime in which oil moves in the reservoir to wells under the pressure of marginal (or bottom) waters. In this case, the deposit is filled with water from surface sources in quantities equal to or slightly less than the amount of liquid and gas withdrawn from the reservoir during its development. An indicator of the efficiency of reservoir development is the oil recovery factor - the ratio of the amount of oil extracted from the reservoir to the total (balance) reserves in the reservoir. Practice has established that active water pressure mode is the most effective. With this mode, it is possible to extract 50-70%, and sometimes more, of the total amount of oil contained in the subsoil before the development of the deposit begins. The oil recovery coefficient under water pressure conditions can be in the range of 0.5-0.7 or more.
2) Elastic (elastic-water-pressure) mode - the operating mode of the reservoir, in which reservoir energy, when pressure in the reservoir decreases, manifests itself in the form of elastic expansion of reservoir fluid and rock. The elastic forces of fluid and rock can manifest themselves in any operating mode of the deposit. Therefore, it is more correct to consider the elastic regime not as an independent one, but as a phase of the water-pressure regime when the elasticity of the liquid (oil, water) and rock is the main source of energy of the deposit. Elastic expansion of the reservoir fluid and rock as the pressure decreases should occur in any operating mode of the deposit. However, for the active water-pressure mode and gas modes, this process plays a secondary role. In contrast to the water-pressure mode, in the elastic-water-pressure mode, the formation pressure at any given moment of operation depends on both the current and the total fluid withdrawal from the formation. Compared to the water-pressure mode, the elastic-water-pressure mode of formation operation is less effective. The oil recovery coefficient (oil recovery) ranges from 0.5-0.6 and
Gas pressure mode (or gas cap mode) is a formation operating mode when the main energy propelling oil is the gas pressure of the gas cap. In this case, oil is forced to the wells under the pressure of expanding gas, which is in a free state in the elevated part of the formation. However, in contrast to the water-pressure regime (when oil is displaced by water from the lower parts of the deposit), in the gas-pressure regime, on the contrary, gas displaces oil from the higher to the lower parts of the deposit. The efficiency of reservoir development in this case depends on the ratio of the size of the gas cap and the nature of the structure of the deposit. Favorable conditions for the most effective manifestation of this regime are high permeability of reservoirs (especially vertical, bedding), large angles of inclination of layers and low viscosity of oil. As oil is extracted from the reservoir and reservoir pressure in the oil-saturated zone decreases, the gas cap expands, and gas displaces oil into the lower part of the formation to the bottom of the wells. In this case, gas breaks through to wells located close to the gas-oil contact. The release of gas and the gas cap, as well as the operation of wells with high flow rates, is unacceptable, since gas breakthroughs lead to uncontrolled consumption of gas energy while simultaneously reducing the flow of oil. Therefore, it is necessary to constantly monitor the operation of wells located near the gas cap, and in the event of a sharp increase in gas coming out of the well along with oil, limit their flow rate or even stop operating the wells. The oil recovery factor for oil deposits with gas pressure ranges from 0.5-0.6. To increase it, gas is injected from the surface into the elevated part of the deposit (into the gas cap), which makes it possible to maintain and sometimes restore gas energy in the deposit.
Dissolved gas mode is a reservoir operating mode in which oil is forced through the reservoir to the bottom of the wells under the influence of the energy of expanding gas bubbles when it is released from the oil. In this mode, the main driving force is gas dissolved in oil or dispersed with it in the formation in the form of tiny bubbles. As the fluid is withdrawn, the reservoir pressure decreases, gas bubbles increase in volume and move towards zones of lowest pressure, i.e. to the bottoms of wells, taking oil with it. The change in equilibrium in the reservoir in this mode depends on the total extraction of oil and gas from the reservoir. An indicator of the efficiency of reservoir development under gas conditions is the gas factor, or the volume of gas per each ton of oil extracted from the reservoir. The oil recovery factor in this mode is 0.2-0.4.
Gravity mode is the operating mode of a deposit in which the movement of oil through the reservoir to the bottom of the wells occurs due to the gravity of the oil itself. The gravity regime manifests itself when the pressure in the formation has dropped to a minimum, there is no pressure from the contour waters, and the gas energy is completely depleted. If the deposit has a steep dip angle, then those wells that penetrated the formation in the wing, low zones will be productive. The oil recovery factor in gravity mode usually ranges from 0.1-0.2.
Mixed mode is a mode of operation of a deposit when, during its operation, the simultaneous action of two or more different energy sources is noticeable.
9. Explain the conditions for managing the process of developing oil fields, depending on the number of layers and pore layers in one object. How technically and technologically the movement of sections of oil and the agent displacing it is controlled.
Reservoir Management.
Development and operation covers the period of time from the end of exploration to the liquidation of the field. This period of time represents the “life cycle” of the deposit. The company developing the field must actively manage this process in order to optimize it. Thus, managing the field development process is a cornerstone concept that includes the development and adoption of decisions related to the entire range of work carried out at the field. The main objective of management is to maximize the economic efficiency of development and operation of the field throughout its entire life cycle. To achieve the best results, the development process must be managed by taking into account all major factors. This approach will ensure that optimal decisions are made and adjustments to the development and production process at all stages of field operation. For example, the local task of increasing production from several individual wells should not be posed in isolation from considering the consequences of such an increase on the integral indicators of oil recovery throughout the entire field. Another example is where changes in taxes or oil prices may make some wells unprofitable to operate. However, despite this, it is advisable to make the final decision to shut down such wells only after determining the impact of their shutdown on the efficiency of oil extraction for the field as a whole. Determining the optimal development and operation strategy requires comprehensive and ongoing field studies. Such studies include the creation (refinement) of a geological model of the field, the study of wells and reservoir properties, and, finally, the construction on their basis of development and production schemes that ensure the greatest investment efficiency. Comprehensive optimization of field development requires the creation of a permanent development model, on the basis of which geological and engineering support should be provided for all production activities ongoing at the field.
The more layers and interlayers are included in one object, the technically and technologically more difficult it is to control the movement of sections of oil and the agent displacing it (water-oil and gas-oil sections) in individual layers and interlayers, the more difficult it is to separately influence the interlayers and extract oil and gas from them , it is more difficult to change the rate of production of layers and interlayers. Deterioration of field development management conditions leads to a decrease in oil recovery.
Oil fields are layer-by-layer and zonally heterogeneous multi-layer development objects, characterized by a complex geological structure. In this regard, it is extremely important to organize effective control over the production of oil reserves, including control over the movement of injected water across the reservoir distribution area, the position of the water-water contact, the degree of oil washout from the formations, the technical condition of the wells and the temperature regime of the deposit. The solution to the listed problems is carried out by carrying out a complex of field hydrodynamic studies (PHS), laboratory measurements (LI) and field geophysical studies (GIS).
Geological and field methods
Geological and field surveys are carried out to monitor flow rates, well injectivity, water cut, changes in the composition of oil, associated water, and injected liquid. These works are carried out in field conditions by oil field workers, laboratories of research and production workshops of NGDU.
The following work is being carried out on production wells:
Measurement of liquid and gas flow rates;
Sampling and determination of water content of products;
Selection of deep and surface samples of oil and water for chemical analysis;
Measurement of buffer and casing pressures.
Selection of deep and surface oil samples, as well as gas sampling for laboratory chemical analysis, is carried out annually in special wells, the number of which is 10% of the operating stock. Analysis of these data allows us to monitor the nature of changes in reservoir oil parameters during the development process. Sampling of water supplied along with produced oil is carried out throughout the watered fund once a quarter. The obtained data is used to establish the causes of water flooding of wells in the process of conducting geological and field analysis.
NGDU periodically conducts analyzes of produced water, chemical analyzes of oil and gas, and analyzes of deep oil samples. Deep samplers are used for sampling. For injection wells, the wells' injectivity is determined. In the pressure maintenance workshops, temperature measurements and determination of the EHF of injected water are carried out.
Hydrodynamic methods
Important information about the state of deposits can be obtained by conducting hydrodynamic studies. Hydrodynamic studies include a set of works to monitor the energy state of perforated formations, changes in hydrodynamic parameters when changing the operating mode of wells (hydraulic conductivity, permeability, productivity factor). Determination of the productivity coefficient must be carried out in production and injection wells using indicator curves or pressure recovery curves once every two years, studies with deep flow meters and flow meters - once a year. Based on measurements of reservoir and bottomhole pressures, isobar maps are compiled quarterly. Bottomhole pressure measurements for the old well stock are carried out once every six months, for the new one - once a quarter. To determine hydraulic conductivity and piezoelectric conductivity, cross-well studies are carried out using pressure waves.
The following types of work are carried out:
For production wells -
Research under steady-state filtration conditions and determination of hydraulic conductivity, piezoelectric conductivity, and productivity coefficient;
Measurements Rpl (Nst), Rzab (Ndin);
Debitometry, moisture measurement;
Determination of Tmel;
Removing indicator diagrams;
For injection wells -
Research in steady and unsteady filtration modes;
Determination of pressure drop curve;
Measurements Rpl, Rbuf, Tpl;
Flow metering.
In piezometric wells -
Measurements Rpl (Nst);
Liquid sampling;
Thermometry.
In control wells (unperforated) -
Thermometry;
Determination of oil-water saturation by geophysical methods.
oil reserve natural gas
The main technological indicators characterizing the process of developing an oil field (deposit) include: annual and cumulative production of oil, liquid, gas; annual and cumulative agent (water) injection; water cut of produced products; selection of oil from recoverable reserves; stock of production and injection wells; oil withdrawal rates; compensation of fluid withdrawal by water injection; oil recovery factor; well flow rates for oil and liquid; well injectivity; reservoir pressure, etc.
According to the method of Lysenko V.D. The following indicators are determined and summarized in table No. 1:
1. Annual oil production (qt) and 2. Number of production and injection wells (nt):
where t is the serial number of the accounting year (t=1, 2, 3, 4, 5); q0 - oil production for the year preceding the calculated one, in our example for the 10th year; e=2.718 - base of natural logarithms; Qres – residual recoverable oil reserves at the beginning of the calculation (the difference between the initial recoverable reserves and the accumulated oil production at the beginning of the calculation year, in our example for the 10th year).
n0 - number of wells at the beginning of the accounting year; T is the average life of a well, years; in the absence of actual data, the standard depreciation period for a well (15 years) can be taken as T.
3. Annual rate of oil withdrawal t - the ratio of annual oil production (qt) to the initial recoverable oil reserves (Qlow):
t bottom = qt / Q bottom
4. The annual rate of oil withdrawal from residual (current) recoverable reserves is the ratio of annual oil production (qt) to residual recoverable reserves (Qoiz):
t oiz = qt / Qoiz
5. Oil production from the beginning of development (cumulative oil recovery (Qacc):
Sum of annual oil withdrawals for the current year.
6. Oil withdrawal from initial recoverable reserves - the ratio of accumulated oil withdrawal (Qacc) to (Qlow):
СQ = Qnak / Qniz
7. Oil recovery factor (ORF) or oil recovery - the ratio of accumulated oil recovery (Qnak) to initial geological or balance reserves (Qbal):
KIN = Qnak / Qbal
- 8. Liquid production per year (ql). The annual liquid production for the prospective period can be assumed constant at the level actually achieved in the 10th year.
- 9. Liquid production from the beginning of development (Ql) - the sum of annual liquid withdrawals for the current year.
- 10. Average annual water cut of well production (W) - the ratio of annual water production (qw) to annual liquid production (ql):
- 11. Water injection per year (qzak) for the prospective period is accepted in volumes that provide accumulated compensation for fluid withdrawal for the 15th year of development in the amount of 110-120%.
- 12. Water injection since the beginning of development Qzak - the sum of annual water injections for the current year.
- 13. Compensation of fluid withdrawal by water injection per year (current) - the ratio of annual water injection (qzak) to annual fluid production (ql):
Kg = qzak / qzh
14. Compensation for liquid withdrawal by water injection from the beginning of development (accumulated compensation) - the ratio of accumulated water injection (Qzak) to accumulated liquid withdrawal (Ql):
Knak = Qzak / Qzh
15. Production of associated petroleum gas for the year is determined by multiplying the annual oil production (qt) by the gas factor:
qgas = qt.Gf
- 16. Production of associated petroleum gas from the beginning of development - the sum of annual gas withdrawals.
- 17. The average annual oil production rate of one production well is the ratio of annual oil production (qg) to the average annual number of production wells (next) and the number of days per year (Tg), taking into account the production wells operating coefficient (Ke.d):
qwell d. = qg / nadd Tg Ke.d,
where K.d is equal to the ratio of days (days) worked by all production wells during a calendar year to the number of these wells and the number of calendar days (days) in a year.
- 18. The average annual liquid flow rate of one production well is the ratio of the annual liquid production (ql) to the average annual number of production wells (next) and the number of days per year (Tg), taking into account the production well operation rate (Ke.d):
- 19. Average annual injectivity of one injection well - the ratio of the annual water injection (qzak) to the average annual number of injection wells (nnag) and the number of days per year (Tg), taking into account the operating coefficient of injection wells (Ke.n):
qwell = qzak / nnag Tg Ke.n,
where K.n is equal to the ratio of the days worked by all injection wells during a calendar year to the number of these wells and the number of calendar days in a year.
20. Reservoir pressure for the 20th year of development tends to decrease if the accumulated compensation is less than 120%; if the accumulated compensation is in the range from 120 to 150%, then the reservoir pressure is close to or equal to the initial one; if the accumulated compensation is more than 150%, then the reservoir pressure tends to increase and may be higher than the initial one.
The field development schedule is presented in the histogram.
Calculation of natural gas reserves using a formula and calculation of recoverable reserves using a graphical method
By extrapolating the graph Q zap = f (Pav(t)) to the abscissa axis determines the recoverable gas reserves or using the ratio:
where Q reserve - initial recoverable gas reserves, million m3;
Qext (t) - gas production from the beginning of development over a certain period of time (for example, 5 years) is given in Appendix 4, million m3;
Pinit - initial pressure in the reservoir, MPa;
Pav(t) - weighted average pressure in the deposit for the period of time of gas volume extraction (for example, 5 years), Pav(t) =0.9 Initial, MPa;
initial and av(t) - corrections for the deviation of the properties of a real gas according to the Boyle-Mariotte law from the properties of ideal gases (respectively for pressures Pinit and Paver(t)). The amendment is equal to
The gas supercompressibility coefficient is determined from the experimental Brown-Katz curves. To simplify the calculations, we conventionally assume zinit =0.65, zav(t) =0.66, the value of which corresponds to the pressure Pav(t); For calculation we take Kgo = 0.8.
Calculation of development indicators using the method of current oil and liquid production planning. This methodology is known as the “Methodology of the USSR State Planning Committee”. It is used to this day in all oil and gas production departments, in oil producing companies, in organizations of the fuel and energy complex and planning organizations.
Initial data for calculation:
1. Initial balance oil reserves (NBR), t;
2. Initial recoverable oil reserves (IRR), t;
3. At the beginning of the planned year:
Cumulative oil production (?Qн), t;
Cumulative liquid production (?Q liquid), t;
Cumulative water injection (?Q zak), m 3 ;
Current stock of production wells (N days);
Current stock of injection wells (N days);
4. Dynamics of well drilling by year for the planned period (Nb):
Mining (N d b);
Discharge (N n b).
Table 5.1 Initial data for the West Leninogorsk area of the Romashkinskoye field
|
NBZ, thousand tons |
NIZ, thousand tons |
Qn, thousand tons |
Qf, thousand tons |
Q zak, thousand m 3 |
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Calculation of development indicators
1. Number of days of operation of production wells per year, carried over from the previous year:
Dper=365K (5.1)
D lane = 3650.9 = 328.5
2. Number of days of operation of new production wells:
3. Average oil flow rate of new production wells:
q n new =8 t/day
4. Oil production decline rate of producing wells:
5. Annual oil production from new wells:
6. Annual oil production from transferred wells:
7. Total annual oil production
8. Annual oil production from new wells of the previous year, if they had operated without decline in this year:
9. Annual oil production from the transferred wells of the previous year (if they had worked without falling):
10. Possible estimated oil production from all wells of the previous year (if they were operated without falling):
11. Planned oil production from wells of the previous year:
12. Decrease in oil production from wells of the previous year:
13. Percentage change in oil production from wells in the previous year:
14. Average oil production per well:
15. Average production rate of oil wells transferred from the previous year:
16. Cumulative oil production:
17. The current oil recovery factor (ORF) is inversely proportional to the initial balance reserves (IBR):
18. Selection from approved initial recoverable NCD reserves, %:
19. Rate of selection from initial recoverable reserves (IRR), %:
20. Rate of selection from current recoverable reserves, %:
21. Average water cut of produced products:
22. Annual liquid production:
23. Liquid production from the beginning of development:
24. Annual water injection:
25. Annual compensation for fluid extraction by injection:
26. Accumulated compensation for fluid extraction by injection:
27. Water-oil factor:
The dynamics of the main development indicators are shown in table. 5.2
Table 5.2 Dynamics of key development indicators
|
Production, million tons |
Cumulative production, million tons |
Water injection, million m 3 |
Average oil flow rate, t/day |
Rate of selection from NCDs |
Selection rate from TIZ |
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|
liquids |
liquids |
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The dynamics of annual oil and liquid production and annual water injection are shown in Fig. 5.1.
Rice. 5.1.
The dynamics of accumulated oil and liquid production and accumulated water injection are shown in Fig. 5.2.
Rice. 5.2.
The dynamics of the oil recovery factor, the rate of selection from NCDs and the rate of selection from industrial diseases are shown in Fig. 5.3.
Rice. 5.3. Dynamics of oil recovery factor, rate of selection from NCDs and rate of selection from industrial diseases
