How to calculate the flow rate of a gas well. How to correctly calculate the flow rate of a well? Static and dynamic water levels

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Gas wells are exploited using the fountain method, i.e. through the use of formation energy. The calculation of the elevator comes down to determining the diameter of the fountain pipes. It can be determined from the conditions of the bottom hole removal of solid and liquid particles or to ensure maximum wellhead pressure (minimum pressure loss in the wellbore at a given flow rate).

The removal of solid and liquid particles depends on the gas velocity. As the gas rises in the pipes, the speed increases due to the increase in gas volume as the pressure decreases. The calculation is performed for the conditions of the fountain pipe shoe. The depth of running pipes into the well is taken into account the productive characteristics of the formation and the technological mode of operation of the well.

It is advisable to lower the pipes to the lower perforation holes. If the pipes are lowered to the upper perforation holes, then the gas flow velocity in the production string opposite the perforated productive formation 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. That's why Bottom part the formation is cut off by a sandy clay plug or liquid, and the well flow rate decreases.

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

At a given well flow rate, the gas velocity at the pipe shoe is equal to:

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

P Z, T Z - pressure and temperature of gas at the bottom, Pa, K;

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

F - flow area of fountain pipes, m 2

d - diameter (internal) of 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 vcr of removal of solid and liquid particles from the face is 5 - 10 m/s. Then the maximum diameter of the pipes at which rock and liquid particles 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 fountain pipes. To prevent the accumulation of liquid at the bottom and a decrease in flow rate, a gas condensate well must be operated with a flow rate no less than the minimum permissible, ensuring the removal of gas condensate to the surface. The value of this flow rate is determined by the empirical formula:

where M - molecular mass gas Then the pipe diameter:

When determining the diameter of the fountain pipes, in order to ensure minimal pressure losses in the wellbore, it is necessary to provide for their reduction in the wellbore to the minimum so that the gas flows to the wellhead with the highest possible pressure. This will reduce gas transportation costs. The bottomhole and wellhead pressures of a gas well are linked to each other by G.A. Adamov’s formula.

where P 2 is the pressure at the wellhead, MPa;

e is the base of natural logarithms;

s is the exponent equal to s = 0.03415 s g L / (T avg z ap);

c g is the relative density of gas in air;

L - length of fountain pipes, m;

d - pipe diameter, m;

T av - average gas temperature in the well, K;

Qo - well flow rate under standard conditions, thousand m 3 /day;

l - coefficient of hydraulic resistance;

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

Since PZ is unknown, z cf is determined by the method of successive approximations. Then, if the well flow rate Qo and the corresponding bottomhole pressure P3 are known from the results of gas-dynamic studies, at a given pressure at the wellhead P2, the diameter of the fountain pipes is determined from the formula in the form:

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

The calculation of the elevator comes down to determining the diameter of the pump and compressor pipes (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 Р з = 10.1 MPa; well depth H = 1320 m; gas compressibility coefficient under standard conditions z o = 1; critical speed of removal of solid and liquid particles to the surface x cr = 5 m/s.

1) Well temperature T is determined by the formula:

T = N? G, (19)

where H is the well depth, m

G - geothermal gradient.

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

where Ppl - reservoir pressure, MPa

P cr - critical pressure, MPa

For methane P cr = 4.48 MPa

where T cr - critical temperature, TO

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

The gas compressibility coefficient at the bottom z z = 0.86 is determined from Figure 6 B (Appendix B).

1) Diameter of pump-compressor...

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

Calculation of individual methanol consumption rates for technological process when preparing and transporting natural and oil gas for each section, it is carried out according to the formula:

H Ti = q f + q g + q c, (23)

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

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

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

q k is the amount of methanol required to saturate the condensate.

The amount of methanol q l (kg/1000 m3) required to saturate the liquid phase is determined by the formula:

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

C 1 - weight concentration of introduced methanol, %;

C 2 - weight concentration of methanol in water (concentration of waste 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 to saturate the liquid phase, it is necessary to know the gas humidity and the concentration of methanol at two points: at the beginning and at the end of the section where hydrate formation is possible.

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

Having determined the gas humidity at the beginning of section W 1 and at the end of section W 2, find the amount of moisture DW released from every 1000 m 3 of passing gas:

DW = W 2 - W 1 (25)

Let's determine humidity using the formula:

where P is gas pressure, MPa;

A is a coefficient characterizing the humidity of an ideal gas;

B is a coefficient depending on the composition of the gas.

To determine the concentration of spent methanol C2, first determine the equilibrium temperature T (° C) of hydrate formation. To do this, use equilibrium curves for the formation of gas hydrates various densities(Figure 7 B of Appendix B) based on the average pressure at the methanol supply section:

where P 1 and P 2 are the pressure at the beginning and end of the section, MPa.

Having determined T, find the amount of decrease in DT of the equilibrium temperature necessary to prevent hydrate formation:

DT = T - T 2, (28)

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

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

Amount of methanol (q g, kg/1000 m 3) required for saturation gaseous medium, is determined by the formula:

q g = k m C 2, (29)

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

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

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

The main element of the water supply system is the water supply source. For autonomous systems in private households, country houses or farms wells or boreholes are used as sources. The principle of water supply is simple: the aquifer fills them with water, which is supplied to users using a pump. When the pump operates for a long time, no matter what its power, it cannot supply more water than the water carrier releases into the pipe.

Any source has a limiting volume of water that it can give to the consumer per unit of time.

Flow definitions

After drilling, the organization that carried out the work provides a test report, or a passport for the well, in which everything is entered required parameters. However, when drilling for households, contractors often enter approximate values into the passport.

You can double-check the accuracy of the information or calculate the flow rate of your well yourself.

Dynamics, statics and height of the water column

Before you start taking measurements, you need to understand what the static and dynamic water level in a well is, as well as the height of the water column in the well column. Measuring these parameters is necessary not only to calculate well productivity, but also to the right choice pumping unit for the water supply system.

The static level is the height of the water column in the absence of water intake. Depends on in-situ pressure and is set during downtime (usually at least an hour);
Dynamic Level – steady level water during water intake, that is, when the influx of liquid is equal to the outflow;
Column height is the difference between the well depth and the static level.

Dynamics and statics are measured in meters from the ground, and the height of the column from the bottom of the well

You can take a measurement using:

Electric level gauge;
An electrode that makes contact when interacting with water;
An ordinary weight tied to a rope.

Measurement using a signaling electrode

Determining pump performance

When calculating the flow rate, it is necessary to know the pump performance during pumping. To do this, you can use the following methods:

View flow meter or meter data;
Read the passport for the pump and find out the performance by operating point;
Calculate the approximate flow rate based on water pressure.

In the latter case, it is necessary to fix a pipe of smaller diameter in a horizontal position at the outlet of the water-lifting pipe. And make the following measurements:

Pipe length (min. 1.5 m) and its diameter;
Height from the ground to the center of the pipe;
The length of the jet from the end of the pipe to the point of impact on the ground.

After receiving the data, you need to compare them using a diagram.

Compare the data by analogy with the example

Measuring the dynamic level and flow rate of a well must be done with a pump with a capacity no less your estimated peak water flow.

Simplified calculation

Well flow rate is the ratio of the product of water pumping intensity and the height of the water column to the difference between dynamic and static water levels. To determine the flow rate of a well, the following formula is used:

Dt = (V/(Hdin-Nst))*Hv, Where

Dt – required flow rate;
V – volume of pumped liquid;
Hdin – dynamic level;
Hst – static level;
Hv – height of the water column.

For example, we have a well 60 meters deep; the statics of which is 40 meters; the dynamic level when operating a pump with a capacity of 3 cubic meters per hour was established at around 47 meters.

In total, the flow rate will be: Dt = (3/(47-40))*20= 8.57 cubic meters/hour.

A simplified measurement method involves measuring the dynamic level when the pump is operating at one capacity; for the private sector this may be sufficient, but not to determine the exact picture.

Specific flow rate

With an increase in pump performance, the dynamic level, and, accordingly, the actual flow rate decreases. Therefore, water intake is more accurately characterized by the productivity coefficient and specific flow rate.

To calculate the latter, not one, but two measurements of the dynamic level should be made at different water intake rates.

The specific flow rate of a well is the volume of water released when its level decreases for each meter.

The formula defines it as the ratio of the difference between the larger and smaller values of water intake intensity to the difference between the values of the drop in the water column.

Dsp=(V2-V1)/(h2-h1), Where

Dsp – specific flow rate
V2 – volume of pumped water during the second water intake
V1 – primary pumped volume
h2 – decrease in water level at the second water intake
h1 – level reduction at the first water intake

Returning to our conditional well: with water intake at an intensity of 3 cubic meters per hour, the difference between dynamics and statics was 7 m; when re-measuring with a pump capacity of 6 cubic meters per hour, the difference was 15 m.

In total, the specific flow rate will be: Dsp = (6-3)/(15-7)= 0.375 cubic meters/hour

Real flow rate

The calculation is based on the specific indicator and the distance from the ground surface to the top point of the filter zone, taking into account the condition that pump unit will not be shipped below. This calculation is as close to reality as possible.

DT= (Hf-Hst) * Doud, Where

Dt – well flow rate;
Hf – distance to the beginning of the filtration zone (in our case we will take it as 57 m);
Hst – static level;
Dsp – specific flow rate.

In total, the real flow rate will be: Dt = (57-40)*0.375= 6.375 cubic meters/hour.

As you can see, in the case of our imaginary well, the difference between the simplified and subsequent measurements was almost 2.2 cubic meters per hour in the direction of decreasing productivity.

Decrease in flow rate

During operation, the well's productivity may decrease; the main reason for the decrease in flow rate is clogging, and to increase it to the previous level, it is necessary to clean the filters.

Over time the impellers centrifugal pump may wear out, especially if your well is on sand, in which case its productivity will become lower.

However, cleaning may not help if you initially had a low-income water well. The reasons for this are different: the diameter of the production pipe is insufficient, it fell past the aquifer, or it contains little moisture.

Calculation of fitting diameter

The diameter of the wellhead fitting for gas wells is determined by the formula:

Where is the diameter of the fitting, mm;

Flow coefficient;

Qg - gas flow rate, m3/day;

Рbur - buffer pressure, according to field data atm.

Let's calculate the diameter of the wellhead choke hole using formula (2.16) for well No. 1104:

Calculation of the minimum well flow rate ensuring the removal of the liquid phase

When operating gas wells, the most common complication is the influx of liquid phase (water or condensate). In this case, it is necessary to determine the minimum bottomhole flow rate of a gas well, at which liquid accumulation at the bottom with the formation of a liquid plug does not yet occur.

The minimum flow rate of a gas well (in m3/day), at which a liquid plug does not form at the bottom, is calculated by the formula:

Where is the minimum gas velocity at which a liquid plug does not form, m/s;

Temperature under standard conditions, K,

Reservoir temperature, K,

Bottomhole pressure, MPa,

Atmospheric pressure, MPa,

Internal diameter of the tubing, according to the project = 0.062 m,

Gas supercompressibility coefficient.

Minimum gas velocity at which a water plug does not form:

Minimum gas velocity at which a condensate plug does not form:

Using formulas (2.17-2.19), we calculate the minimum flow rates of gas condensate well No. 1104 of the Samburg oil and gas condensate field, at which condensate will not settle at the bottom:

Minimum flow rate at which water is removed:

Or thousand m3/day.

Minimum gas velocity at which all condensate is carried to the surface:

Minimum flow rate for condensate removal:

Or thousand m3/day.

Comparing the results obtained, it can be noted that, under other constant conditions, complete removal of condensate is possible at higher flow rates of a gas well than complete removal of water.

Calculation of technological efficiency of sidewalls

The amount of additional gas produced per billing period by drilling a horizontal lateral wellbore in well No. 1104 in the productive formation is determined by the formula:

Where is the amount of oil actually produced by the well during the billing period;

The value of theoretical (estimated) oil production from a well during the calculation period in the absence of a horizontal wellbore in the productive formation, .

Where is the flow rate of a well with a horizontal well and a vertical one;

Vertical well flow rate, .

Correction factor, taking into account compliance with additional gas production and development of recoverable reserves, units. For the first 2 years in = 1;

Amount of additionally produced gas condensate determined by the formula:

Where is the amount of additionally produced gas condensate during the billing period due to the drilling of a horizontal lateral trunk, t;

Condensate-gas factor, according to field data kg/m3.

Calculation for 2 years using formulas (2.23-2.34):

In this section, a calculation was made of technological efficiency due to drilling a horizontal wellbore in vertical well. Comparison of “actual” indicators of site development with horizontal wells with indicators basic version, shows again undeniable advantage the use of BGS in the development of low-productive formations of relatively small effective thickness. During the period of operation in natural mode for two years when using horizontal wells, additional production will be natural gas and tons of gas condensate, which is 9 times higher than the base version.

Conclusions on the second section

1. Analysis modern methods intensification of natural gas and gas condensate production showed the promise of using methods such as hydraulic fracturing and sidetracking in vertical and directional wells at the Samburgskoye oil and gas condensate field. Among these methods of production intensification, sidetracking is one of the most effective in the conditions of the Samburgskoye field.

2. The use of sidetracking technology in vertical and directional wells of the Samburg oil and gas condensate field to convert wells to horizontal ones will not only reduce drilling volumes, increase the flow rate and profitability of wells, but also more rationally use reservoir energy, due to lower depressions on the reservoir.

3. Based on an analysis of the stock of producing wells and the density of residual mobile reservoir gas reserves, candidate well No. 1104 was selected for sidetracking. For a larger scale implementation of this technology, it is recommended to conduct additional research in order to identify other wells that are promising for sidetracking.

3. Technological calculation of the parameters of a candidate well using the method of Aliev Z.S. showed that the design well flow rate after sidetracking can increase more than 10 times from 89.3 thousand m3/day to 903.2 thousand m3/day.

4. Calculations of the profile of well No. 1104 were performed. At the same time, “cutting a window” in the EC at a depth of 2650 m was chosen as the drilling method technology, with a maximum curvature angle of 2.0° per 10 m in the interval 2940 - 3103 m vertically and a horizontal section length of 400 m.

5. Calculation of the main parameters of the technological operating mode of the well made it possible to determine the diameter of the wellhead choke, the minimum gas velocities (m/s, m/s) at the bottom, ensuring the complete removal of water and gas condensate to the surface, as well as the minimum flow rates at which no gas is formed. bottomhole liquid plugs (thousand m3/day, thousand m3/day). Under other constant conditions, complete removal of condensate is possible at higher flow rates of a gas well than complete removal of water.

6. Calculation of the technological efficiency of sidetracking shows the undeniable advantage of using this technology in the development of low-productive formations of relatively small effective thickness. During the period of operation in natural mode for two years, additional production will amount to natural gas and tons of gas condensate, which is 9 times higher than these figures above the base option.

7. Thus, the calculations performed for the use of sidetracking at the Samburgskoye oil and gas condensate field have shown their effectiveness, and this technology can be recommended as a method for intensifying the production of natural gas and gas condensate in this field.

Ministry of Education and Science of the Russian Federation

Russian State University 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 operating mode - the maximum anhydrous flow rate using the example of a well in the Komsomolskoye gas field.”

Completed by Kibishev A.A.

Checked by: Timashev A.N.

Moscow, 2014

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

1. Brief geological and field characteristics of the field

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

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

The field was discovered in 1967, initially as a gas field (S "Enomanskaya zatezh). It was discovered as an oil field in 1975. In 1980, a technology system development, the implementation of which began in 1986.

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

The territory is a slightly hilly (absolute elevations 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 megaswell.

The Pyakupurovsky dome-shaped uplift represents an elevated zone irregular shape, oriented in southwest-northeast directions, complicated by several local uplifts of the third 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, type of operation for treating the bottomhole zone of the formation, volume of injected fluid, and much more.

The physicochemical properties of oil and dissolved gas of the Komsomolskoye field were studied based on research data from surface and deep samples.

Some parameters were determined directly at the wells (measurements of pressures, temperatures, etc.) Sample analysis was carried out in laboratory conditions at the TCL. Geokhim LLC, Reagent LLC, Tyumen.

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

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

Table 1 - Component composition of petroleum gas.

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

The properties of oils also vary along the section. Analysis of results laboratory research Oil samples do not allow us to identify strict patterns, but we can trace the main trends in changes in the properties of oils. With depth, the density and viscosity of oil tend to decrease, and the same trend persists for the resin content.

The solubility of gases in water is much lower than in oil. As water mineralization increases, the solubility of gases in water decreases.

Table 2 - Chemical composition formation water.

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

In gas wells, condensation of vaporous water from the gas can occur and water can flow to the bottom of the well from the formation. In gas condensate wells, hydrocarbon condensate coming from the formation and formed in the wellbore is added to this liquid. IN initial period development of deposits at high speeds gas flow at the bottom of wells and a small amount of liquid, it is almost completely carried to the surface. As the gas flow rate at the bottom decreases and the flow rate of liquid entering the bottom of the well increases due to watering of the permeable layers and an increase in the volumetric condensate saturation of the porous medium, the complete removal of fluid from the well is not ensured, and a column of liquid accumulates at the bottom. It increases the back pressure on the formation, leads to a significant decrease in flow 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 gas sampling conditions at the bottom of the well, under which condensation of water and liquid hydrocarbons does not occur in the bottomhole zone of the formation, and by preventing the breakthrough of a cone of bottom water or a tongue of marginal water into the well. In addition, it is possible to prevent water from entering the well by isolating foreign and formation waters.

Liquid from the bottom of wells is removed continuously or periodically. Continuous removal of liquid from a well is carried out by operating it at speeds that ensure removal of liquid from the bottom to surface separators, by withdrawing liquid through siphon or fountain pipes lowered into the well using a gas lift, plunger lift, or pumping out liquid by downhole pumps.

Periodic removal of liquid can be carried out by stopping the well to absorb liquid into the formation, by blowing the well into the atmosphere through siphon or fountain pipes without injection or with the injection of surfactants (foaming agents) to the bottom of the well.

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

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

Extraneous and formation waters are isolated by injection cement mortar under pressure. During these operations, gas-saturated formations are isolated from water-saturated ones with packers. At underground gas storage facilities, a method has been developed for isolating water-filled interlayers by injecting surfactants into them, preventing the flow of water into the well. Pilot tests have shown that to obtain stable foam, the “foaming agent concentration” (in terms of the active substance) should be taken equal to 1.5-2% of the volume of injected liquid, and the foam stabilizer - 0.5-1%. To mix surfactants and air on the surface, use a special device - an aerator (type " perforated pipe in the pipe"). Air is pumped through the perforated pipe with a compressor in accordance with the specified a, b outer pipe pump in an aqueous surfactant solution with a pump at a flow rate of 2-3 l/s.

The effectiveness of the liquid removal method is justified by special well studies and technical and economic calculations. To absorb liquid into the formation, the well is stopped for 2-4 hours. Well production rates increase after startup, but do not always compensate for losses in gas production due to well downtime. Since the liquid column does not always go into the formation, and at low pressures the gas flow may not resume, this method is rarely used. Connecting the well to the gas collection network low pressure allows you to operate flooded wells, separate water from gas, and use low-pressure gas for a long time. The wells are purged into the atmosphere within 15-30 minutes. The gas speed at the bottom should reach 3-6 m/s. The method is simple and is used if the flow rate is restored for a long period (several days). However, this method has many disadvantages: fluid is not completely removed from the bottom, increasing depression on the formation leads to intensive influx of new portions of water, destruction of the formation, formation of a sand plug, and pollution environment, gas losses.

Periodic purging 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 automatically installed on the surface or at the bottom of the well. This method differs from atmospheric blowing in that it is applied only after a certain column of liquid has accumulated at the bottom.

Gas from the well, together with the liquid, enters the low-pressure gas collection 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 machine receives a command for this when the pressure difference in the annulus and in the working line increases to a given pressure. The magnitude of this difference depends on the height of the liquid column in the tubing.

Automatic machines installed at the bottom also operate at a certain height of the liquid column. Install one valve at the entrance to the tubing or several gas lift start-up valves at the lower section of the tubing.

To accumulate liquid at the bottom, downhole separation of the gas-liquid flow can be used. This method of separation followed by forcing liquid into the underlying horizon was tested after preliminary laboratory tests in a well. 408 and 328 of the Korobkovskoye field. This method significantly reduces hydraulic pressure losses in the wellbore and the costs of collecting and disposing of formation water.

Periodic removal of liquid can also be carried out when a surfactant is supplied to the bottom of the well. When water comes into contact with a foaming agent and the gas bubbles 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 a foam-like mass to the surface.

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

For wells with a water influx of up to 200 l/day, it is recommended to introduce up to 4 g active substance Surfactant per 1 liter of water; in wells with an inflow of up to 10 tons/day, this amount decreases.

Injecting up to 300-400 liters of sulfonol solutions or Novost powder into individual wells of the Maikop field led to an increase in flow 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 activity of the surfactant by 10-30%, and if there is more condensate than water, foam does not form. Under these conditions, special surfactants are used.

Continuous removal of liquid from the bottom 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 of up to 2500 m.

Continuous fluid removal is used in cases where formation water is continuously supplied to the bottom of the well. The diameter of the tubing string is selected so as to obtain flow rates that ensure fluid removal from the bottom. When switching to a smaller pipe diameter, hydraulic resistance increases. Therefore, switching 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 bottom.

Gas lift systems with a downhole valve are successfully used to remove fluid from the bottomhole. Gas is taken through the annulus, and liquid is removed through the tubing, on which gas lift and downhole starting 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 (down), as well as the force caused by the pressure in the annulus (up). At the calculated fluid level in the annulus, the ratio active 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 decreases to a predetermined level, the inlet valve closes. Liquid accumulates inside the tubing until the gas lift start valves operate. When the latter are opened, gas from the annulus enters the tubing and carries liquid to the surface. After the liquid level in the tubing decreases, the start valves close, and liquid accumulates inside the pipes again due to its bypass from the annulus.

In gas and gas condensate wells, a plunger lift of the “flying valve” type is used. A pipe restrictor is installed in the lower part of the tubing string, and an upper shock absorber is installed on the Xmas tree. The plunger is placed in the Xmas pipes, which serve as its guide channel - a “cylinder”, and the plunger itself acts as a “piston”.

Operating practice has established the optimal speeds of rise (1-3 m/s) and fall (2-5 m/s) of the plunger. When gas velocities at the shoe are more than 2 m/s, a continuous plunger elevator is used.

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

Downhole pumps are installed on the tubing, and gas is taken through the annulus. To prevent gas from entering the pump intake, it is placed below the perforation zone under the buffer liquid level or above the downhole valve, which allows only liquid into the tubing.

field well flow rate anisotropy

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

The technological operating mode of project wells is among the most important decisions accepted by the designer. The technological mode of operation, along with the type of well (vertical or horizontal), determines their number, therefore, the surface piping, and, ultimately, the capital investment for field development for a given extraction from the deposit. It is difficult to find a design problem that would have, as a technological mode, a multivariate and purely subjective solution.

The technological regime is the specific conditions of gas movement in the formation, bottomhole zone and well, characterized by the value of flow rate and bottomhole pressure (pressure gradient) and determined by certain natural limitations.

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

Deformation of the porous medium when creating significant depressions on the formation, leading to a decrease in the permeability of the bottom-hole 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 well operation and their impact on the selected operating mode;

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

Watering wells with bottom water;

Corrosion of downhole equipment during operation;

Connecting wells to the community collector;

Opening up a layer of multi-layer fields, taking into account the presence of hydrodynamic connection between layers, etc.

All these and other factors are expressed the following criteria, having the form:

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

ДP=Ppl(t) - Pз(t) = Const - constant depression on the reservoir;

Pз(t) = Const -- constant bottomhole pressure;

Q(t) = Const -- constant flow rate;

Py(t) = Const -- constant wellhead pressure;

x(t) = Const -- constant speed flow.

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

When choosing technological operating modes for wells in a projected field, regardless of what criteria are accepted as the main ones that determine the operating mode, the following principles must be observed:

Completeness of taking into account the geological characteristics of the deposit, the properties of fluids saturating the porous medium;

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

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

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

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 criteria for the technological operating mode of wells, you must first establish a determining factor or group of factors to justify the operating mode of design wells. Special attention in this case, the designer must pay attention to the presence of bottom water, multi-layering and the presence of hydrodynamic connection between layers, to the anisotropy parameter, to the presence of lithological screens over the deposit area, to the proximity of contour waters, to the reserves and permeability of thin, highly permeable interlayers (super reservoirs), to the stability of the interlayers, on the magnitude of the maximum gradients from which formation destruction begins, on the pressure and temperature in the “reservoir-GPP” system, on changes in the properties of gas and liquid depending on pressure, on piping and gas drying conditions, etc.

4. Calculation of anhydrous well flow rate, dependence of flow rate on the degree of formation opening, anisotropy parameter

In most gas-bearing formations, the vertical and horizontal permeabilities differ, and, as a rule, the vertical permeability k in is significantly less than the horizontal permeability k g. Low vertical permeability reduces the risk of water flooding of gas wells that have exposed anisotropic formations with bottom water during their operation. However, with low vertical permeability, the flow of gas from below into the area influenced by the imperfection of the well in terms of the degree of penetration is also difficult. The exact mathematical relationship between the anisotropy parameter and the amount of permissible drawdown when a well penetrates an anisotropic formation with bottom water has not been established. The use of methods for determining Qpr, developed for isotropic formations, leads to significant errors.

Solution algorithm:

1. Determine the critical parameters of the gas:

2. Determine the supercompressibility coefficient under reservoir conditions:

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

4. Find the height of the formation 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 coefficient D:

8. Determine the coefficients K o , Q * and the maximum water-free flow rate Q pr. without. depending on the degree of formation h and for two different meanings anisotropy parameter:

Initial data:

Table 1 - Initial data for calculating the anhydrous regime.

Table 4 - Calculation of anhydrous mode.

5. Analysis of calculation results

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

Figure 1 - Dependence of the maximum 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 optimal value autopsy is 0.72 in both cases. In this case, the higher flow rate will be at higher value anisotropy, that is, with a greater ratio of vertical to horizontal permeability.

Bibliography

1. “Instructions for comprehensive research gas and gas condensate wells." M: Nedra, 1980. Edited by Zotov G.A.. Aliev Z.S.

2. Ermilov O.M., Remizov V.V., Shirkovsky A.I., Chugunov L.S. “Reservoir physics, gas production and underground storage.” M. Nauka, 1996

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