Determination of oil well flow rate: formula and calculation methods. What is well flow rate and how to determine it Formula for calculating the flow rate of a gas well

Well flow rate is main well parameter, showing how much water can be obtained from it in a certain period of time. This value is measured in m 3 / day, m 3 / hour, m 3 / min. Consequently, the higher the flow rate of the well, the higher its productivity.

It is necessary to determine the flow rate of a well first of all in order to know how much fluid you can count on. For example, is there enough water for uninterrupted use in the bathroom, in the garden for irrigation, etc. In addition, this parameter is an excellent aid in choosing a pump for water supply. So, the larger it is, the more efficient the pump can be used. If you buy a pump without paying attention to the flow rate of the well, then it may happen that it will suck water out of the well faster than it will be filled.

Static and dynamic water levels

In order to calculate the flow rate of a well, it is necessary to know the static and dynamic water levels. The first value indicates the water level in a calm state, i.e. at a time when the water was not pumped out yet. The second value determines the steady-state water level. while the pump is running, i.e. when the rate of its pumping out is equal to the rate of filling the well (water stops decreasing). In other words, this flow rate directly depends on the pump performance, which is indicated in its passport.

Both of these indicators are measured from the surface of the water to the surface of the earth. The unit of measurement in this case is most often chosen by the meter. So, for example, the water level was fixed at 2 m, and after turning on the pump, it settled at 3 m, therefore, the static water level is 2 m, and the dynamic water level is 3 m.

I would also like to note here that if the difference between these two values is not significant (for example, 0.5-1 m), then we can say that the well debit is large and most likely higher than the pump performance.

Well rate calculation

How is the production rate of a well determined? This requires a high-performance pump and a measuring container for the pumped-out water, preferably as large as possible. The calculation itself is best considered with a specific example.

Initial data 1:

Well depth - 10 m.

The beginning of the level of the filtration zone (zone of water intake from the aquifer) - 8 m.

Static water level - 6 m.

The height of the water column in the pipe - 10-6 = 4m.

Dynamic water level - 8.5 m... This value reflects the remaining amount of water in the well after pumping out 3 m 3 of water from it, with the time spent for this 1 hour. In other words, 8.5 m is the dynamic water level at a debit of 3 m 3 / hour, which has decreased by 2.5 m.

Calculation 1:

Well flow rate is calculated using the formula:

D sk = (U / (H din -N st)) H in = (3 / (8.5-6)) * 4 = 4.8 m 3 / h,

Conclusion: well debit is 4.8 m 3 / h.

The presented calculation is very often used by drillers. But it carries a very large error. Since this calculation assumes that the dynamic water level will increase in direct proportion to the rate of pumping water. For example, with an increase in water pumping up to 4 m 3 / h, according to him, the water level in the pipe drops by 5 m, and this is incorrect. Therefore, there is a more accurate method with the inclusion in the calculation of the parameters of the second water intake to determine the specific flow rate.

What should be done while doing this? It is necessary after the first water intake and data collection (previous version), to allow the water to settle and return to its static level. After that, pump out water at a different speed, for example, 4 m 3 / hour.

Initial data 2:

The well parameters are the same.

Dynamic water level - 9.5 m... At a water intake rate of 4 m 3 / h.

Calculation 2:

The specific flow rate of the well is calculated using the formula:

D y = (U 2 -U 1) / (h 2 -h 1) = (4-3) / (3.5-2.5) = 1 m 3 / h,

As a result, it turns out that an increase in the dynamic water level by 1 m contributes to an increase in flow rate by 1 m 3 / h. But this is only on condition that the pump is not lower than the beginning of the filtration zone.

The real production rate is calculated here using the formula:

D sk = (H f-N st) D y = (8-6) 1 = 2 m 3 / h,

H f = 8 m- the beginning of the filtration zone level.

Conclusion: well debit is 2 m 3 / h.

After comparison, it can be seen that the values of the well production rate, depending on the calculation method, differ from each other by more than 2 times. But the second calculation is also not accurate. The well flow rate, calculated through the specific flow rate, is only close to the real value.

Methods for increasing the production rate of a well

In conclusion, I would like to mention how you can increase the flow rate of the well. There are essentially two ways. The first method is to clean the production pipe and filter in the well. The second is to check if the pump is working properly. Suddenly, it was precisely because of this that the amount of produced water decreased.

Gas wells are operated in a flowing manner, i.e. through the use of reservoir energy. The calculation of the lift is reduced to determining the diameter of the flowing pipes. It can be determined from the conditions of bottomhole removal of solid and liquid particles or to provide maximum wellhead pressure (minimum pressure loss in the wellbore at a given flow rate).

Carrying out of solid and liquid particles depends on the gas velocity. As the gas rises in the pipes, the velocity increases due to the increase in gas volume with decreasing pressure. The calculation is performed for the conditions of the fountain pipe shoe. The depth of lowering the pipes into the well is taken taking into account the productive characteristics of the formation and the technological mode of the well operation.

It is advisable to run the pipes down to the lower perforation holes. If the pipes are run down to the upper holes of the perforations, then the gas flow rate in the production string opposite the perforated reservoir from bottom to top increases from zero to a certain value. This means that in the lower part and up to the shoe, the removal of solid and liquid particles is not ensured. Therefore, the lower part of the reservoir is cut off by a sandy-clay plug or liquid, while the well debit decreases.

We use the law of the gas state of Mendeleev - Clapeyron

For a given well flow rate, the gas velocity at the pipe shoe is:

where Q 0 - well flow rate under standard conditions (pressure P 0 = 0.1 MPa, temperature T 0 = 273 K), m 3 / day;

P З, T З - pressure and temperature of gas at the bottomhole, Pa, K;

zo, zz - gas supercompressibility coefficient, respectively, under the conditions T 0, P 0 and T, P;

F - flow area of fountain pipes, m 2

d - diameter (internal) fountain pipes, m.

Based on the formulas for calculating the critical speed of removal of solid and liquid particles and according to experimental data, the minimum speed v cr of removal of solid and liquid particles from the bottomhole is 5-10 m / s. Then the maximum pipe diameter at which particles of rock and liquid are carried to the surface:

During the operation of gas condensate wells, liquid hydrocarbons (gas condensate) are released from gas, which create a two-phase flow in the flow pipes. To prevent the accumulation of liquid at the bottom hole and a decrease in production rate, a gas condensate well must be operated with a flow rate of at least the minimum permissible, which ensures the removal of gas condensate to the surface. The value of this flow rate is determined by the empirical formula:

where M is the molecular weight of the gas. Then the diameter of the pipes:

When determining the diameter of flowing pipes, from the condition of ensuring minimum pressure losses in the wellbore, it is necessary to provide for their reduction in the wellbore to a minimum so that gas flows to the wellhead with a possible high pressure. Then the cost of gas transportation will decrease. The bottomhole and wellhead pressures of a gas well are linked by the formula of G.A. Adamov.

where P 2 - pressure at the wellhead, MPa;

e - base of natural logarithms;

s - exponent equal to s = 0.03415 s g L / (T av z av);

c g is the relative density of the gas in the air;

L is the length of the fountain pipes, m;

d - pipe diameter, m;

T cf - the average temperature of the gas in the well, K;

Qo - well flow rate under standard conditions, thousand m3 / day;

l - coefficient of hydraulic resistance;

z cf - coefficient of gas supercompressibility at an average temperature T cf and an average pressure P cf = (Pz + P 2) / 2.

Since P З is unknown, then z cf determines by the method of successive approximations. Then, if the flow rate of the well Qo and the corresponding bottomhole pressure P З are known from the results of gas-dynamic studies, at a given pressure at the wellhead P 2, the diameter of the flowing pipes is determined from the formula in the form:

The actual diameter of the flowing pipes is selected taking into account the standard diameters. Note that in the calculations, based on two conditions, the determining factor is the removal of rock particles and liquid to the surface. If well flow rates are limited by other factors, then the calculation is based on the condition of reducing pressure losses to the lowest possible value from the technological and technical points of view. Sometimes, for a given pipe diameter, using the formulas written out, the flow rate of the well or the pressure loss in the wellbore is determined.

The calculation of the lift is reduced to determining the diameter of the tubing (Table 18 A of Appendix A). Initial data: well flow rate under standard conditions Q o = 38.4 thousand m 3 / day = 0.444 m 3 / s (pressure P o = 0.1 MPa, temperature T o = 293 K); bottomhole pressure P s = 10.1 MPa; well depth H = 1320 m; coefficient of compressibility of gas under standard conditions z o = 1; the critical velocity of the removal of solid and liquid particles to the surface x cr = 5 m / s.

1) Well temperature T is determined by the formula:

T = H? Г, (19)

where H is the depth of the well, m

Г - geothermal gradient.

2) The coefficient of gas compressibility z z is determined by the Brown curve (Figure 6 B of Appendix B). To do this, we find the reduced pressure P pr and temperature T pr:

where Р PL - reservoir pressure, MPa

P cr - critical pressure, MPa

For methane P cr = 4.48 MPa

where T cr - critical temperature, K

For methane, T cr = - 82.5? C = 190.5 K

The gas compressibility factor at the bottomhole z z = 0.86 is determined according to Figure 6 B (Appendix B).

1) The diameter of the pump ...

- daily volume of gas q, nm 3 / day,
- initial and final pressure in the gas pipeline Р 1 and Р 2, MPa;
- initial and final temperature t 1 and t 2, about C;
- concentration of fresh methanol C 1,% wt.

The calculation of the individual rate of consumption of methanol for the technological process during the preparation and transportation of natural and oil gas for each section is carried out according to the formula:

H Ti = q w + q g + q k, (23)

where H Ti is the individual rate of methanol consumption for the i-th section;

q w - the amount of methanol required to saturate the liquid phase;

q g - the amount of methanol required to saturate the gaseous phase;

q to - the amount of methanol required to saturate the condensate.

The amount of methanol q w (kg / 1000 m 3) required to saturate the liquid phase is determined by the formula:

where ДW is the amount of moisture taken from the gas, kg / 1000 m 3;

С 1 - weight concentration of introduced methanol,%;

С 2 - weight concentration of methanol in water (concentration of spent methanol at the end of the section where hydrates are formed),%;

From formula 24 it follows that in order to determine the amount of methanol for saturation of the liquid phase, it is necessary to know the gas humidity and the methanol concentration at two points: at the beginning and at the end of the section where hydrates can form.

Humidity of hydrocarbon gases with a relative density (by air) of 0.60, not containing nitrogen and saturated with fresh water.

Having determined the moisture content of the gas at the beginning of the section W 1 and at the end of the section W 2, the amount of moisture DW emitted from every 1000 m 3 of passing gas is found:

ДW = W 2 - W 1 (25)

Let's determine the humidity by the formula:

where P is the gas pressure, MPa;

A - coefficient characterizing the moisture content of the ideal gas;

B is a coefficient that depends on the composition of the gas.

To determine the concentration of waste methanol C 2, the equilibrium temperature T (° C) of hydrate formation is first determined. For this, the equilibrium curves of the formation of gas hydrates of various densities are used (Figure 7 B of Appendix B) based on the average pressure at the methanol supply section:

where Р 1 and Р 2 - pressure at the beginning and end of the section, MPa.

Having determined T, the value of the decrease in the DT of the equilibrium temperature necessary to prevent hydrate formation is found:

DT = T - T 2, (28)

where T 2 is the temperature at the end of the section where hydrates are formed, ° С.

After determining the diesel fuel, according to the graph in Figure 8 B (Appendix B), we find the concentration of processed methanol C 2 (%).

The amount of methanol (q g, kg / 1000 m 3) required to saturate the gaseous medium is determined by the formula:

q g = k m C 2, (29)

where m is the ratio of the methanol content required to saturate the gas to the methanol concentration in the liquid (the solubility of methanol in the gas).

The coefficient k m is determined for the conditions of the end of the section, where the formation of hydrates is possible, according to Figure 9 B (Appendix B) for the pressure Р 2 and temperature Т 2.

The amount of methanol supply (Tables 20 A - 22 A of Appendix A), taking into account the flow rate, is determined by the formula.

Ministry of Education and Science of the Russian Federation

Russian State University of Oil and Gas named after I.M. Gubkina

Faculty of Oil and Gas Field Development

Department of Development and Operation of Gas and Gas Condensate Fields

TEST

on the course "Development and operation of gas and gas condensate fields"

on the topic: "Calculation of the technological mode of operation - the limiting waterless flow rate on the example of the well of the Komsomolskoye gas field."

Completed by A.A. Kibishev

Checked by: Timashev A.N.

Moscow, 2014

1. Brief geological and commercial characteristics of the field
5. Analysis of calculation results

1. Brief geological and commercial characteristics of the field

The Komsomolskoye gas condensate oil field is located in the Purovsky District of the Yamalo-Nenets Autonomous Okrug, 45 km south of the regional center of the Tarko-Sale settlement and 40 km east of the Purpe settlement.

The nearest fields with the Ust-Kharampurskoye oil reserves approved by the USSR State Reserves Committee (10-15 km to the east). Novo-Purpeyskoe (100 km to the west).

The field was discovered in 1967 initially as a gas field (C "Enomanian backwater). As an oil field discovered in 1975. In 1980, a technological development scheme was drawn up, the implementation of which began in 1986.

The operating Urengoy - Novopolotsk gas pipeline is located 30 km west of the field. The Surgut - Urengoy railway line runs 35-40 km to the west.

The territory is a slightly hilly (absolute marks plus 33, plus 80 m), swampy plain with numerous lakes. The hydrographic network is represented by the Pyakupur and Aivasedapur rivers (tributaries of the Pur river). The rivers are navigable only during the spring flood (June), which lasts one month.

The Komsomolskoye field is located within the P-order structure - the Pyakupurovsky dome-shaped uplift, which is part of the Northern mega-shaft.

The Pyakupurovskoe dome-shaped uplift is an uplifted zone of irregular shape, oriented in the south-west-north-east directions, complicated by several local uplifts of the III order.

Analysis of the physical and chemical properties of oil, gas and water allows you to select the most optimal downhole equipment, operating mode, storage and transportation technology, the type of operation for treating the bottomhole formation zone, the volume of injected fluid, and much more.

The physicochemical properties of oil and dissolved gas of the Komsomolskoye field were studied based on the data of studies of surface and depth samples.

Some of the parameters were determined directly at the wells (measurements of pressures, temperatures, etc.). Samples were analyzed in laboratory conditions in the TCL. LLC "Geochem", LLC "Reagent" Tyumen.

Surface samples were taken from the flow line when the wells were operating in a certain mode. All studies of surface samples of oil and gas were carried out according to the methods provided by the State Standards.

During the research, the component composition of the oil gas was studied, the results are shown in Table 1.

Table 1 - Component composition of oil gas.

For the calculation of reserves, the parameters are recommended that are determined under standard conditions and a method close to the conditions for degassing oil in the field, that is, with stepwise separation. In this regard, the results of investigations of samples by the oil method of differential degassing were not used in the calculation of average values.

Oil properties also change along the section. Analysis of the results of laboratory studies of oil samples does not allow us to distinguish strict regularities, however, it is possible to trace the main trends in the change in the properties of oils. With depth, the density and viscosity of oil tend to decrease, the same tendency remains for the content of tar.

The solubility of gases in water is much lower than in oil. With an increase in water salinity, the solubility of gases in water decreases.

Table 2 - Chemical composition of formation waters.

2. Design of wells for fields that have exposed formation water

In gas wells, condensation of vaporous water from the gas and the flow of water to the bottom of the well from the formation can occur. In gas condensate wells, this fluid is supplemented with hydrocarbon condensate coming from the formation and formed in the wellbore. In the initial period of reservoir development, at high rates of gas flow at the bottom of the wells and a small amount of liquid, it is almost completely carried to the surface. As the gas flow rate at the bottomhole decreases and the flow rate of the liquid entering the bottomhole increases due to the flooding of the permeable interlayers and the increase in the volumetric condensate saturation of the porous medium, the complete removal of fluid from the well is not ensured, and the liquid column accumulates at the bottomhole. It increases the back pressure on the formation, leads to a significant decrease in production rate, cessation of gas flow from low-permeability layers and even a complete shutdown of the well.

It is possible to prevent the flow of liquid into the well by maintaining the conditions for gas extraction at the bottom of the well, in which there is no condensation of water and liquid hydrocarbons in the bottomhole formation zone, preventing the breakthrough of the bottom water cone or the tongue of edge water into the well. In addition, it is possible to prevent water from entering the well by isolating extraneous and formation water.

Borehole fluid is removed continuously or periodically. Continuous removal of fluid from the well is carried out by operating it at speeds that ensure the removal of fluid from the bottomhole into surface separators, by withdrawing fluid through siphon or flowing pipes lowered into the well using a gas lift, plunger lift or pumping out the fluid with downhole pumps.

Periodic liquid removal can be carried out by shutting in the well to absorb fluid by the formation, blowing the well into the atmosphere through siphon or flow pipes without pumping or by pumping surfactants (foaming agents) to the bottom of the well.

The choice of a method for removing fluid from the bottom of the wells depends on the geological and production characteristics of the gas-saturated reservoir, the well design, the quality of annulus cementing, the period of reservoir development, as well as the amount and reasons for the fluid entering the well. The minimum fluid release in the bottomhole formation zone and at the bottom of the well can be ensured by adjusting the bottomhole pressure and temperature. The amount of water and condensate released from the gas at the bottom hole of the well at the bottom hole pressure and temperature is determined by the curves of gas moisture capacity and condensation isotherms.

To prevent the breakthrough of the bottom water cone into a gas well, it is operated at limiting waterless flow rates, determined theoretically or by special studies.

Extraneous and formation waters are isolated by injection of cement slurry under pressure. During these operations, gas-bearing formations are isolated from those watered by packers. At underground gas storage facilities, a method has been developed for isolating water-cut layers by injecting surfactants into them, which prevent water from entering the well. Pilot tests have shown that to obtain a stable foam, the "concentration of the foaming agent" (in terms of the active substance) should be taken equal to 1.5-2% of the volume of the injected fluid, and the foam stabilizer - 0.5-1%. For mixing surfactants and air on the surface, a special device is used - an aerator (of the "perforated pipe in a pipe" type). Air is pumped through the perforated branch pipe by a compressor in accordance with a given a, an aqueous surfactant solution is pumped into the outer pipe with a pump with a flow rate of 2-3 l / s.

The effectiveness of the liquid removal method is substantiated by special studies of wells and technical and economic calculations. To absorb liquid by the formation, the well is stopped for 2-4 hours. The well production rates after start-up increase, however, they do not always compensate for the losses in gas production due to the downtime of the wells. Since the liquid column does not always go into the reservoir, and at low pressures, gas inflow may not resume, this method is rarely used. Connecting the well to a low-pressure gas gathering network allows operating water-cut wells, separating water from gas, and using low pressure gas for a long time. The wells are blown into the atmosphere within 15-30 minutes. At the same time, the gas velocity at the bottomhole should reach 3-6 m / s. The method is simple and is used if the production rate is restored for a long time (several days). However, this method has many drawbacks: the liquid from the bottomhole is not completely removed, the increasing drawdown on the formation leads to an intensive influx of new portions of water, the destruction of the formation, the formation of a sand plug, environmental pollution, and gas losses.

Periodic blowing of wells through tubing with a diameter of 63-76 mm or through specially lowered siphon pipes with a diameter of 25-37 mm is carried out in three ways: manually or by automatic machines installed on the surface or at the bottom of the well. This method differs from blowing into the atmosphere in that it is applied only after a certain liquid column has accumulated at the bottomhole.

Gas from the well, together with the liquid, enters the low-pressure gas-collecting manifold, is separated from the water in separators and is compressed or burned in a flare. The machine installed at the wellhead periodically opens the valve on the working line. The automaton receives a command to do this when it rises to a predetermined pressure difference between the annulus and working line pressures. The magnitude of this drop depends on the height of the liquid column in the tubing.

The machines installed at the bottom also operate at a certain height of the liquid column. Install one valve at the inlet to the tubing or several starting gas-lift valves in the lower section of the tubing.

To accumulate liquid at the bottomhole, downhole separation of the gas-liquid flow can be used. This method of separation with subsequent pumping of liquid into the underlying horizon was tested after preliminary laboratory studies at well No. 408 and 328 of the Korobkovskoye field. With this method, the hydraulic pressure loss in the wellbore and the cost of collecting and disposing of formation water are significantly reduced.

Periodic liquid removal can also be carried out when surfactant is supplied to the bottom of the well. When water comes into contact with a blowing agent and gas is bubbled through the liquid column, foam is formed. Since the density of the foam is significantly less than the density of water, even relatively low gas velocities (0.2-0.5 m / s) ensure the removal of the foamy mass to the surface.

When the mineralization of waters is less than 3-4 g / l, a 3-5% aqueous solution of sulfonol is used, with high mineralization (up to 15-20 g / l), sodium salts of sulfonic acids are used. Liquid surfactants are periodically injected into the well, and from solid surfactants (powders "Don", "Ladoga", Trialon, etc.) granules with a diameter of 1.5-2 cm or rods 60-80 cm long are made, which are then fed to the bottom of the wells.

For wells with an inflow of water up to 200 l / day, it is recommended to inject up to 4 g of active surfactant substance per 1 l of water; in wells with an inflow of up to 10 t / day, this amount decreases.

The introduction of up to 300-400 liters of sulfonol solutions or Novost powder in individual wells of the Maikop field led to an increase in production rates by 1.5-2.5 times compared to the initial ones, the duration of the effect reached 10-15 days. The presence of condensate in the liquid reduces the surfactant activity by 10-30%, and if there is more condensate than water, no foam is formed. Under these conditions, special surfactants are used.

Continuous removal of liquid from the bottomhole occurs at certain gas velocities, ensuring the formation of a droplet two-phase flow. It is known that these conditions are provided at gas velocities of more than 5 m / s in pipe strings with a diameter of 63-76 mm at well depths up to 2500 m.

Continuous liquid removal is used in cases where formation water is continuously flowing to the bottom of the well. The diameter of the tubing string is selected so as to obtain flow rates that ensure the removal of liquid from the bottom of the well. When switching to a smaller pipe diameter, hydraulic resistance increases. Therefore, the transition to a smaller diameter is effective if the pressure loss due to friction is less than the back pressure on the formation of the liquid column, which is not removed from the bottomhole.

Gas-lift systems with a downhole valve are successfully used to remove liquid from the bottomhole. Gas is taken through the annular space, and the liquid is removed through the tubing, on which the starting gas-lift and downhole valves are installed. The valve is acted upon by the compression force of the spring and the pressure difference created by the liquid columns in the tubing and in the annulus (downward), as well as the force due to the pressure in the annulus (upward). At the design level of the liquid in the annulus, the ratio of the acting forces becomes such that the valve opens and the liquid enters the tubing and then into the atmosphere or into the separator. After the liquid level in the annulus has dropped to a predetermined value, the inlet valve closes. Fluid builds up inside the tubing until the gas lift start valves are activated. When the latter are opened, gas from the annulus enters the tubing and carries the liquid to the surface. After the liquid level in the tubing has dropped, the start valves are closed, and liquid again accumulates inside the pipes due to its bypassing from the annulus.

In gas and gas condensate wells, a plunger lift of the "flying valve" type is used. A pipe limiter is installed in the lower part of the tubing string, and an upper shock absorber is installed on the Christmas tree. acts as a "piston".

Operational practice has established the optimal lifting speed (1-3 m / s) and fall (2-5 m / s) of the plunger. At gas velocities at the shoe over 2 m / s, a continuous plunger lift is used.

At low reservoir pressures in wells up to 2500 m deep, downhole pumping units are used. In this case, liquid removal does not depend on the gas velocity * and can be carried out until the very end of the reservoir development with a decrease in wellhead pressure to 0.2-0.4 MPa. Thus, downhole pumping units are used in conditions when other methods of liquid removal cannot be applied at all or their efficiency drops sharply.

Downhole pumps are installed on the tubing, and gas is withdrawn through the annulus. To exclude the flow of gas to the pump intake, it is placed below the perforation zone under the buffer level of the liquid or above the downhole valve, which passes only liquid into the tubing.

field well production rate anisotropy

3. Technological modes of well operation, reasons for limiting production rates

The technological mode of operation of design wells is one of the most important decisions made by the designer. The technological mode of operation, along with the type of wells (vertical or horizontal), predetermines their number, therefore, the ground piping, and ultimately, the capital investment for the development of the field with a given extraction from the reservoir. It is difficult to find a design problem that would have, like a technological mode, a multivariate and purely subjective solution.

The technological regime is the specific conditions for gas movement in the reservoir, the bottomhole zone and the well, characterized by the flow rate and bottomhole pressure (pressure gradient) and determined by some natural constraints.

To date, 6 criteria have been identified, the observance of which makes it possible to control the stable operation of the well. These criteria are a mathematical expression for taking into account the influence of various groups of factors on the operation mode. The greatest influence on the well operation mode is exerted by:

Deformation of the porous medium during the creation of significant drawdowns on the formation, leading to a decrease in the permeability of the bottomhole zone, especially in fractured porous formations;

Destruction of the bottomhole zone when opening unstable, weakly stable and weakly cemented reservoirs;

Formation of sand-liquid plugs during the operation of wells and their effect on the selected operating mode;

Formation of hydrates in the bottomhole zone and in the wellbore;

Watering of wells with bottom water;

Corrosion of downhole equipment during operation;

Connecting wells to reservoir communities;

Opening of a layer of multilayer fields, taking into account the presence of a hydrodynamic connection between interlayers, etc.

All these and other factors are expressed by the following criteria, which look like:

dP / dR = Const - constant gradient with which the wells must be operated;

DP = Ppl (t) - Pz (t) = Const - constant pressure drawdown;

Pz (t) = Const - constant bottomhole pressure;

Q (t) = Const - constant flow rate;

Py (t) = Const - constant wellhead pressure;

x (t) = Const - constant flow rate.

For any field, when justifying the technological mode of operation, one (very rarely two) of these criteria should be selected.

When choosing the technological modes of operation of the wells of the projected field, regardless of what criteria will be accepted as the main ones that determine the mode of operation, the following principles must be observed:

Completeness of accounting for the geological characteristics of the deposit, the properties of fluids that saturate the porous medium;

Compliance with the requirements of the law on the protection of the environment and natural resources of hydrocarbons, gas, condensate and oil;

Full guarantee of the reliability of the "reservoir - the beginning of the gas pipeline" system during the development of the deposit;

Maximum consideration of the possibility of removing all factors limiting the productivity of wells;

Timely change of previously established modes that are not suitable at this stage of field development;

Ensuring the planned volume of gas, condensate and oil production with minimal capital investments and operating costs and stable operation of the entire "reservoir-gas pipeline" system.

To select the criteria for the technological mode of wells operation, it is first necessary to establish a determining factor or a group of factors to justify the mode of operation of the planned wells. In this case, the designer should pay special attention to the presence of bottom water, multilayer and the presence of a hydrodynamic connection between layers, to the parameter of anisotropy, to the presence of lithological screens over the area of the deposit, to the proximity of circuit waters, to reserves and permeability of low-power highly permeable interlayers (super reservoirs), to stability interlayers, by the magnitude of the limiting gradients, from which the destruction of the formation begins, to the pressure and temperature in the “reservoir-UKPG” system, to the change in the properties of gas and liquid from pressure, to the piping and to the conditions of gas drying, etc.

4. Calculation of the waterless well production rate, the dependence of the production rate on the degree of reservoir penetration, anisotropy parameter

In most gas-bearing formations, the vertical and horizontal permeabilities differ, and, as a rule, the vertical permeability k is much less than the horizontal k g. Low vertical permeability reduces the risk of watering gas wells that have penetrated anisotropic formations with bottom water during their operation. However, with low vertical permeability, it is also difficult to inflow gas from the bottom into the area of influence of well imperfection in terms of the degree of penetration. The exact mathematical relationship between the anisotropy parameter and the value of the allowable drawdown when the well penetrates an anisotropic formation with bottom water has not been established. The use of methods for determining Q pr, developed for isotropic formations, leads to significant errors.

Solution algorithm:

1. Determine the critical parameters of the gas:

2. Determine the supercompressibility factor in reservoir conditions:

3. Determine the gas density under standard conditions and then under reservoir conditions:

4. Find the height of the produced water column required to create a pressure of 0.1 MPa:

5. Determine the coefficients a * and b *:

6. Determine the average radius:

7. Find the coefficient D:

8. Determine the coefficients K o, Q * and the maximum waterless flow rate Q pr.without. depending on the degree of reservoir penetration h and for two different values of the anisotropy parameter:

Initial data:

Table 1 - Initial data for calculating the anhydrous regime.

Table 4 - Calculation of anhydrous regime.

5. Analysis of calculation results

As a result of calculating the anhydrous regime for different degrees of reservoir penetration and with the values of the anisotropy parameter equal to 0.03 and 0.003, I obtained the following dependencies:

Figure 1 - Dependence of the limiting anhydrous flow rate on the degree of opening for two values of the anisotropy parameter: 0.03 and 0.003.

It can be concluded that the optimal opening value is 0.72 in both cases. In this case, a higher production rate will be at a higher value of anisotropy, that is, at a higher ratio of vertical to horizontal permeability.

Bibliography

1. "Instructions for the comprehensive study of gas and gas condensate wells." M: Nedra, 1980. Edited by GA Zotov. ZS Aliev.

2. Ermilov OM, Remizov VV, Shirkovsky AI, Chugunov L.S. "Physics of Reservoir, Production and Underground Gas Storage". M. Science, 1996

3. Aliev Z.S., Bondarenko V.V. Guidelines for the design of development of gas and gas-oil fields. Pechora .: Pechora time, 2002 - 896 p.

Methods for calculating this indicator

As we said earlier, there are several methods for calculating this indicator.

Most often, two methods are used - the standard one, and using the Dupuis formula mentioned above.

It should be said right away that the second method, although more complicated, gives a more accurate result, since the French engineer devoted his whole life to studying this area, as a result of which much more parameters are used in his formula than in the standard method. However, we will cover both methods.

Standard calculation

This technique is based on the following formula:

D = H x V / (Hd - Hst), where

D is the value of the well production rate;

H is the height of the water column;

V is the pump performance;

Нд - dynamic level;

Нst is a static level.

In this case, the static level indicator is the distance from the initial groundwater level to the initial soil layers, and an absolute value is used as the dynamic level, which is determined by measuring the water level after pumping it out using measuring instruments.

There is a concept of the optimal indicator of the flow rate of the oil-bearing area of the field. It is determined both to determine the general drawdown level of a particular well, and for the entire productive formation as a whole.

The formula for calculating the average drawdown level assumes the value of the bottomhole pressure Pb = 0. The flow rate of a particular well, which was calculated for the optimal drawdown indicator, is the optimal value of this indicator.

Mechanical and physical pressure on the formation can lead to the collapse of some parts of the inner walls of the wellbore. As a result, the potential flow rate often has to be reduced mechanically in order not to disrupt production continuity and to maintain the strength and integrity of the wellbore walls.

As you can see, the standard formula is the simplest, as a result of which it gives the result with a rather significant error. To get a more accurate and objective result, it is advisable to use a more complex, but much more accurate Dupuis formula, which takes into account a larger number of important parameters of a particular site.

Dupuis calculation

It is worth saying that Dupuis was not only a qualified engineer, but also an excellent theoretician.

He deduced not even one, but two formulas, the first of which is used to determine the potential transmissibility and productivity for pumping equipment and an oil-bearing reservoir, in the second, it allows calculating for an imperfect pump and field, based on their actual productivity.

So, let's analyze the first Dupuis formula:

N0 = kh / ub * 2∏ / ln (Rk / rc), where

N0 is an indicator of potential productivity;

Kh / u - coefficient of hydraulic permeability of the oil-bearing formation;

b - coefficient taking into account expansion in volume;

∏ is the number Pi = 3.14;

Rk is the value of the radius of the loop power supply;

Rc is the value of the bit radius measured over the entire distance to the exposed pay zone.

Dupuis's second formula:

N = kh / ub * 2∏ / (ln (Rk / rc) + S, where

N is an indicator of actual productivity;

S is the so-called skin factor, which determines the filtration resistance to flow.

The rest of the parameters are decrypted in the same way as in the first formula.

The second Dupuis formula for determining the actual productivity of a particular oil-bearing area is currently used by almost all producing companies.

It should be said that to increase the productivity of the field, in some cases, the technology of hydraulic fracturing of a productive formation is used, the essence of which is the mechanical formation of cracks in it.
Periodically, it is possible to carry out the so-called mechanical adjustment of the oil flow rate in the well. It is carried out by increasing the bottomhole pressure, which leads to a decrease in the level of production and shows the actual capabilities of each oil-bearing area of the field.
In addition, in order to increase the flow rate, thermal acid treatment is also used.

With the help of various solutions containing acidic liquids, the rock is cleaned from the deposits of resins, salts and other chemicals formed during drilling and operation, which interfere with the high-quality and efficient development of the productive formation.
First, an acidic fluid is poured into the wellbore until it fills the area in front of the developed formation. Then the valve is closed, and under pressure this solution passes further into the depths. The residues of this solution are washed out with either oil or water after the resumption of hydrocarbon production.
It is worth saying that the natural decline in the productivity of oil fields is at the level of 10 to 20 percent per year, if we count from the initial values of this indicator obtained at the time of the start of production. The technologies described above make it possible to increase the intensity of oil production at the field.
The debit must be calculated over specific periods of time. This helps in the formation of a development strategy for any modern oil company that supplies raw materials to enterprises that produce various petroleum products.

One of the main tasks after the drilling of a well is completed is to calculate its production rate. Some people have no idea what well production is. In our article we will see what it is and how it is calculated. This is necessary in order to understand whether she can meet the need for water. The calculation of the well flow rate is determined before the drilling organization issues you a certificate of the object, since the data calculated by them and the real one may not always coincide.

How to determine

Everyone knows that the main purpose of the well is to provide the owners with high quality water in sufficient volume. This must be done even before the completion of the drilling work. Then this data must be compared with those obtained during geological exploration. Geological exploration provides information about whether there is an aquifer in a given location and how thick it is.

But far from everything depends on the amount of water lying on the site, because a lot determines the correctness of the arrangement of the well itself, how it was designed, at what depth, how high-quality equipment.

Master Data for Debit Determination

To determine the productivity of the well and its compliance with water needs, the correct determination of the well production rate will help. In other words, will you have enough water from this well for household needs?

Dynamic and static level

Before you know what the well's water production rate is, you need to get some more data. In this case, we are talking about dynamic and static indicators. What they are and how they are calculated, we will now tell you.

It is important that the flow rate is not constant. It depends entirely on seasonal changes, as well as some other circumstances. Therefore, it is impossible to establish precisely its indicators. This means that you need to use approximate figures. This work is required to establish whether a certain water supply is sufficient for normal living conditions.

The static level shows how much water is in the well without being drawn. Such an indicator is calculated by measuring from the surface of the earth to the water table. It must be determined when the water stops rising from the next fence.

Field flow rates

In order for the information to be objective, you need to wait until the water is collected to the previous level. Only then can you continue your research. For the information to be objective, you need to do everything sequentially.

In order to determine the flow rate, we need to set dynamic and static indicators. Given that, for accuracy, you will need to calculate the dynamic indicator several times. During the calculation, it is necessary to pump out with different intensities. In this case, the error will be minimal.

How the debit is calculated

In order not to puzzle over how to increase the flow rate of a well after it has been put into operation, it is required to carry out calculations as accurately as possible. Otherwise, you may not have enough water in the future. And if over time the well begins to silt and the water yield decreases even more, then the problem will only get worse.

If your well is approximately 80 meters deep, while the zone where water intake starts is 75 meters from the surface, the static indicator (Hst) will be at a depth of 40 meters. Such data will help us calculate the height of the water column (Hw): 80 - 40 = 40 m.

There is a very simple method, but its data is not always true, a way to determine the flow rate (D). To install it, it is necessary to pump out water for an hour, and then measure the dynamic level (Hd). It is quite possible to do this on your own using the following formula: D = V * Hw / Hd - Hst. The rate of pumping out m 3 / hour is indicated by V.

In this case, for example, you pumped out 3 m 3 of water in an hour, the level decreased by 12 m, then the dynamic level was 40 + 12 = 52 m.Now we can transfer our data under the formula and we will get the flow rate, which is 10 m 3 / hour ...

Almost always, this method is used to calculate and enter into a passport. But it does not differ in high accuracy, since they do not take into account the relationship between the intensity and the dynamic indicator. This means that they do not take into account an important indicator - the power of the pumping equipment. If you use a more or less powerful pump, then this indicator will differ significantly.

A plumb line can be used to determine the water level

As we have already said, in order to obtain more reliable calculations, it is necessary to measure the dynamic level several times using pumps of different capacities. Only in this way will the result be the closest to the truth.

To carry out calculations using this method, you need to wait after the first measurement until the water level is at the same level. Then pump out the water for an hour with a pump of a different power, and then measure the dynamic indicator.

For example, it was 64 m, and the volume of pumped water was 5 m 3. The data that we obtained during the two fences will allow us to obtain information using the following formula: Du = V2 - V1 / h2 - h1. V - with what intensity the pumping was done, h - how much the level fell in comparison with static indicators. We have them at 24 and 12 m. Thus, we received a flow rate of 0.17 m 3 / hour.

The specific flow rate of the well will show how the real flow rate will change if the dynamic level increases.

To calculate the real debit, we use the following formula: D = (Hf - Hst) * Du. Hf shows the top point where water intake (filter) starts. We took 75 m for this indicator. Substituting the values into the formula, we get an indicator that is 5.95 m 3 / hour. Thus, this indicator is almost two times less than that recorded in the well certificate. It is more reliable, so you need to focus on it when you determine whether you have enough water or need an increase.

With this information, you can set the average well production rate. He will show what the daily productivity of the well.

In some cases, the well arrangement is done before the house is built, so it is not always possible to calculate whether there will be enough water or not.

In order not to solve the question of how to increase the debit, you need to demand that the correct calculations be done immediately. The exact information must also be entered in the passport. This is necessary so that if problems arise in the future, it was possible to restore the previous level of water intake.

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