How to predict the flow rate of a gas well. Calculation of well flow rate. Reasons for a small well flow rate

This concept means the amount of water, oil, or gas that a source can give out for a conventional unit of time - in a word, its productivity. This indicator is measured in liters per minute, or in cubic meters per hour.

The calculation of the flow rate is necessary both for the arrangement of domestic aquifers, and in the gas and oil industries - each classification has a certain formula for calculations.

1 Why do you need to calculate the well flow rate?

If you know the flow rate of your well, you can easily select the optimal pumping equipment, since the pump power must exactly match the productivity of the source. In addition, in case of any problems, a correctly completed well passport will greatly help the repair team to choose the appropriate way to restore it.

Based on the flow rates, wells are classified into three groups:

Low-rate (less than 20 m³/day);
Average flow rates (from 20 to 85 m³/day);
High-yield (over 85 m³/day).

In the gas and oil industry, the operation of marginal wells is unprofitable. Therefore, preliminary forecasting of their flow rate is a key factor that determines whether a new gas well will be drilled in the developed area.

To determine such a parameter in the gas industry, there is a certain formula (which will be given below).

1.1 How to calculate the flow rate of an artesian well?

To perform calculations, you need to know two source parameters - static and dynamic water levels.

To do this, you will need a rope, with a bulky weight at the end (so that when you touch the water surface, a splash is clearly audible).

You can measure the indicators after one day after the end. Waiting a day after completion of drilling and flushing is necessary for the amount of fluid in the well to stabilize. It is not recommended to take measurements earlier - the result may be inaccurate, since on the first day there is a constant increase in the maximum water level.

Take measurements after the required time has elapsed. You need to do this in depth - determine how long the part of the pipe in which there is no water is. If the well is made in accordance with all technological requirements, then the static water level in it will always be higher than the top point of the filter section.

The dynamic level is a variable indicator that will change depending on the operating conditions of the well. When water is taken from the source, its amount in the casing is constantly decreasing. In the case when the intensity of water intake does not exceed the productivity of the source, then after some time the water stabilizes at a certain level.

Based on this, the dynamic level of the liquid in the well is an indicator of the height of the water column, which will be maintained with a constant intake of liquid at a given intensity. When using different power, the dynamic water level in the well will be different.

Both of these indicators are measured in "meters from the surface", that is, the lower the actual height of the water column in the siege column, the lower the dynamic level will be. In practice, calculating the dynamic water level helps to find out to what maximum depth a submersible pump can be lowered..

The calculation of the dynamic water level is carried out in two stages - you need to perform an average and intensive water intake. Make a measurement after the pump has been running continuously for one hour.

Having determined both factors, you can already obtain indicative information on the flow rate of the source - the smaller the difference between the static and dynamic levels, the greater the well flow rate. For a good artesian well, these indicators will be identical, and the average productivity source has a difference of 1-2 meters.

The calculation of the well flow rate can be done in several ways. It is easiest to calculate the flow rate using the following formula: V * Hv / Hdyn - Hstat.

Wherein:

V is the intensity of water withdrawal when measuring the dynamic level of the well;
H dyn - dynamic level;
H stat - static level;
H in - the height of the water column in the casing (the difference between the total height of the casing and the static level of the liquid)

How to determine the flow rate of a well in practice: take as an example a well whose height is 50 meters, while the perforated filtration zone is located at a depth of 45 meters. The measurement showed a static water level with a depth of 30 meters. Based on this, we determine the height of the water column: 50-30 \u003d 20 m.

To determine the dynamic indicator, suppose that two cubic meters of water were pumped out of the source in one hour of operation by the pump. After that, the measurement showed that the height of the water column in the well became less by 4 meters (there was an increase in the dynamic level by 4 m)

That is, N dyn \u003d 30 + 4 \u003d 34 m.

In order to minimize possible calculation errors, after the first measurement, it is necessary to calculate the specific flow rate, with which it will be possible to calculate the real indicator. To do this, after the first liquid intake, it is necessary to give the source time to fill up so that the level of the water column rises to a static level.

After that, we take water with a greater intensity than the first time, and again measure the dynamic indicator.

To demonstrate the calculation of the specific flow rate, we use the following conditional indicators: V2 (pumping intensity) - 3 m³, if we assume that with a pumping intensity of 3 cubic meters per hour, Ndyn is 38 meters, then 38-30 = 8 (h2 = 8).

The specific flow rate is calculated by the formula: Du = V 2 - V 1 / H 2 - H 1, where:

V1 - intensity of the first water intake (smaller);
V2 - intensity of the second water intake (large);
H1 - decrease in the water column when pumping out at a lower intensity;
H2 - a decrease in the water column during pumping of greater intensity

We calculate the specific flow rate: D y \u003d 0.25 cubic meters per hour.

The specific flow rate shows us that an increase in the dynamic water level by 1 meter entails an increase in the well flow rate by 0.25 m 3 /hour.

After the specific and usual indicator is calculated, it is possible to determine the actual flow rate of the source using the formula:

Dr \u003d (H filter - H stat) * Du, where:

H filter - the depth of the upper edge of the filter section of the casing string;
H stat - static indicator;
Du - specific debit;

Based on the previous calculations, we have: Dr = (45-30) * 0.25 = 3.75 m 3 / hour - this is a high level of production for (classification of high-flow sources starts from 85 m³ / day, for our well it is 3.7 * =94 m³)

As you can see, the error of the preliminary calculation, in comparison with the final result, was about 60%.

2 Application of the Dupuis formula

The classification of wells in the oil and gas industry requires the calculation of their flow rate using the Dupuis formula.

The Dupuis formula for a gas well has the following form:

To calculate the oil production rate, there are three versions of this formula, each of which is used for different types of wells - since each classification has a number of features.

For an oil well with an unsteady supply regime.

Nozzle diameter calculation

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

Where - the diameter of the fitting, mm;

Consumption coefficient,;

Qg - gas flow rate, m3/day;

Pbur - buffer pressure, according to field data atm.

Calculate the diameter of the wellhead choke hole using formula (2.16) for well No. 1104:

Calculation of the minimum well flow rate that ensures the removal of the liquid phase

During the operation of gas wells, the most common complication is the ingress of the liquid phase (water or condensate). In this case, it is necessary to determine the minimum bottomhole flow rate of a gas well, at which there is still no accumulation of liquid at the bottomhole with the formation of a liquid plug.

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

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

Temperature under standard conditions, K,

Reservoir temperature, K,

Bottom hole pressure, MPa,

Atmospheric pressure, MPa,

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

Coefficient of gas supercompressibility.

The minimum gas velocity at which no water lock is formed:

Minimum gas velocity at which no condensate plug is formed:

During the operation of gas wells, the most common complication is the ingress of the liquid phase (water or condensate). In this case, it is necessary to determine the minimum bottomhole flow rate of a gas well, at which there is no accumulation of liquid at the bottomhole with the formation of a liquid plug.

Using formulas (2.17-2.19), we calculate the minimum flow rates of gas condensate well No. 1104 of the Samburgskoye OGCF, at which condensate will not settle at the bottomhole:

The minimum flow rate at which water is taken out:

Or thousand m3/day.

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

Minimum flow rate for condensate removal:

Or thousand m3/day.

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

Calculation of technological efficiency of sidetracking

The amount of additionally produced gas for the billing period due to drilling of the lateral horizontal wellbore No. 1104 in the productive formation is determined by the formula:

Where - the value of the actual oil produced by the well for the billing period, ;

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

Where - the flow rate of a well with a horizontal wellbore and a vertical one, ;

The flow rate of a vertical well, .

Correction factor taking into account compliance with additional gas production and depletion of recoverable reserves, n.u. For the first 2 years v=1;

The amount of additionally produced gas condensate is determined by the formula:

Where - the amount of additionally produced gas condensate for the billing period due to the drilling of a side horizontal wellbore, t;

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

Calculation for 2 years according to the formulas (2.23-2.34):

In this section, the calculation of technological efficiency was made by drilling a horizontal wellbore in a vertical well. Comparison of the "actual" indicators of the development of the site by horizontal wells with the indicators of the base case, once again shows the undeniable advantage of using BGS in the development of low-productive reservoirs of relatively small effective thickness. Over 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 these figures over the base case.

Conclusions on the second section

1. An analysis of modern methods for intensifying the production of natural gas and gas condensate showed the promise of using such methods as hydraulic fracturing and sidetracking in vertical and directional wells at the Samburgskoye oil and gas condensate field. Among these production stimulation methods, 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 Samburgskoye oil and gas condensate field to transfer wells to horizontal wells will not only reduce drilling volumes, increase the flow rate and profitability of wells, but also use reservoir energy more rationally, due to lower drawdowns on the reservoir.

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

3. Technological calculation of the parameters of a candidate well according to the method of Aliyev Z.S. showed that the flow rate of the design well after sidetracking can increase by 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, “window cutting” in the EC at a depth of 2650 m was chosen as the technology of the drilling method, with a maximum angle of curvature of 2.0° per 10 m in the range of 2940 - 3103 m vertically and a horizontal section length of 400 m.

5. The calculation of the main parameters of the technological mode of the well operation made it possible to determine the diameter of the wellhead choke, the minimum gas velocities (m/s, m/s) at the bottomhole, ensuring the complete removal of water and gas condensate to the surface, as well as the minimum flow rates at which bottomhole liquid plugs (thousand m3/day, thousand m3/day). Under other constant conditions, the complete removal of condensate is possible at higher flow rates of a gas well than the complete removal of water.

6. The calculation of the technological efficiency of sidetracking shows the undeniable advantage of using this technology in the development of low-productivity reservoirs of relatively small effective thickness. Over the period of operation in natural mode for two years, additional production will be natural gas and tons of gas condensate, which is 9 times higher than these indicators over the base option.

7. Thus, the performed calculations 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 at this field.

Vladimir Khomutko

Reading time: 4 minutes

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Methods for calculating oil production

When determining productivity, its flow rate is determined, which is a very important indicator when calculating the planned productivity.

It is difficult to overestimate the importance of this indicator, since it is used to determine whether the raw material received from a particular site will pay off the cost of its development or not.

There are several formulas and methods for calculating this indicator. Many enterprises use the formula of the French engineer Dupuy (Dupuy), who devoted many years to studying the principles of groundwater movement. Using the calculation according to this method, it is quite simple to determine whether it is expedient to develop one or another section of the field from an economic point of view.

The flow rate in this case is the volume of fluid that the well supplies for a certain period of time.

It is worth saying that quite often miners neglect the calculation of this indicator when installing mining equipment, but this can lead to very sad consequences. The calculated value, which determines the amount of oil produced, has several determination methods, which we will discuss later.

Often this indicator is called “pump performance” in another way, but this definition does not quite accurately characterize the value obtained, since the properties of the pump have their own errors. In this regard, the volume of liquids and gases determined by calculation in some cases differs greatly from the declared one.

In general, the value of this indicator is calculated in order to select pumping equipment. Having determined in advance the performance of a certain section by means of a calculation, it is possible to exclude pumps that are not suitable in terms of their parameters already at the development planning stage.

The calculation of this value is necessary for any mining enterprise, since oil-bearing areas with low productivity may simply turn out to be unprofitable, and their development will be unprofitable. In addition, incorrectly selected pumping equipment due to untimely calculations can lead to the fact that the company will receive significant losses instead of the planned profit.

Another important factor indicating the necessity of such a calculation for each specific well is the fact that even the flow rates of already operating wells located nearby can differ significantly from the flow rate of a new one.

Most often, such a significant difference is explained by the specific values \u200b\u200bof the quantities substituted into the formulas. For example, the permeability of a formation can vary significantly depending on the depth of the reservoir, and the lower the permeability of the formation, the lower the productivity of the area and, of course, the lower its profitability.

The calculation of the flow rate not only helps when choosing pumping equipment, but also allows you to determine the optimal location for drilling a well.

Installing a new mining rig is a risky business, because even the most qualified specialists in the field of geology do not fully know all the secrets of the earth.

Currently, there are many varieties of professional equipment for oil production, but in order to make the right choice, you must first determine all the necessary drilling parameters. The correct calculation of such parameters will allow you to choose the optimal working set, which will be most effective for a site with a specific performance.

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 many more parameters are used in his formula than in the standard method. However, we will consider 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 flow rate;

H is the height of the water column;

V - pump performance;

Нд – dynamic level;

Hst - static level.

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

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

The formula for calculating the average level of drawdown implies the value of the bottomhole pressure Рzab = 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 production rate often has to be reduced mechanically in order not to disturb the continuity of production and maintain the strength and integrity of the walls of the wellbore.

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

Dupuis calculation

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

He even deduced not one, but two formulas, the first of which is used to determine the potential hydraulic conductivity and productivity for pumping equipment and an oil-bearing reservoir, the second allows for calculation for a non-ideal 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 is the coefficient of hydraulic conductivity of the oil-bearing formation;

b is the coefficient taking into account the volume expansion;

∏ is Pi = 3.14;

Rk is the value of the loop feed radius;

Rc is the value of the bit radius, measured over the entire distance to the exposed reservoir.

Dupuy'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 flow resistance.

The remaining parameters are deciphered 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 is worth saying that in some cases, in order to increase the productivity of the field, the technology of hydraulic fracturing of the 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 bottom hole pressure, which leads to a decrease in the level of production and shows the actual potential of each oil-bearing area of the field.
In addition, 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 deposits of resins, salts and other chemicals formed during drilling and operation, which interfere with the high-quality and efficient development of a productive formation.
First, the acid fluid is poured into the wellbore until it fills the area in front of the formation being developed. Then the valve is closed, and under pressure this solution passes further inland. The remains of this solution are washed out either with 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 after certain periods of time. This helps in shaping the development strategy of any modern oil producing company that supplies raw materials to enterprises producing various petroleum products.

Ministry of Education and Science of the Russian Federation

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

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 anhydrous flow rate on the example of a well of the Komsomolskoye gas field."

Executed Kibishev A.A.

Checked by: Timashev A.N.

Moscow, 2014

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

1. Brief geological and field characteristics of the deposit

The Komsomolskoye gas condensate oil field is located on the territory of 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 State Reserves Committee of the USSR are Ust-Kharampurskoye (10-15 km to the east). Novo-Purpeiskoye (100 km to the west).

The field was discovered in 1967, initially as a gas field (S "Enomanskaya vent). As an oil field, it was discovered in 1975. In 1980, a development flow chart was drawn up, the implementation of which began in 1986.

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

The territory is a slightly hilly (absolute elevations plus 33, plus 80 m), marshy plain with numerous lakes. The hydrographic network is represented by the Pyakupur and Ayvasedapur 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 structure of the second order - the Pyakupurovsky dome-shaped uplift, which is part of the Northern megaswell.

The Pyakupurovskoe dome-shaped uplift is an irregularly shaped uplifted zone oriented in the southwest-northeast direction, complicated by several local uplifts of the III order.

An 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 to treat the bottomhole formation zone, the volume of injected fluid, and much more.

The physical and chemical properties of oil and dissolved gas of the Komsomolsk field were studied according to the data of surface and deep samples.

Some of the parameters were determined directly on the wells (measuring pressures, temperatures, etc.). Samples were analyzed under laboratory conditions in the TCL. LLC "Geohim", 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 for by the State Standards.

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

Table 1 - Component composition of petroleum gas.

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

The properties of oils also change along the section. An analysis of the results of laboratory studies of oil samples does not allow us to identify strict patterns, however, it is possible to trace the main trends in changes in the properties of oils. With depth, the density and viscosity of oil tend to decrease, the same trend persists for the content of resins.

The solubility of gases in water is much lower than in oil. With an increase in the mineralization of water, 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, vaporous water can condense from gas and water can flow to the bottom of the well from the formation. In gas condensate wells, hydrocarbon condensate is added to this liquid, which comes from the reservoir and forms in the wellbore. In the initial period of deposit development, at high gas flow rates at the bottom of wells and a small amount of liquid, it is almost completely brought to the surface. As the gas flow rate at the bottomhole decreases and the flow rate of the fluid entering the bottomhole of the well increases due to watering of the permeable interlayers and an increase in the volumetric condensate saturation of the porous medium, the complete removal of fluid from the well is not ensured, and an accumulation of the liquid column at the bottomhole occurs. It increases the back pressure on the formation, leads to a significant decrease in production rate, the cessation of gas inflow from low-permeability interlayers, and even a complete shutdown of the well.

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

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

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

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

To prevent the breakthrough of the cone of bottom water into a gas well, it is operated at the limiting anhydrous 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-saturated formations are isolated from flooded ones by packers. At underground gas storage facilities, a method has been developed to isolate flooded interlayers by injecting surfactants into them, preventing water from entering the well. Pilot tests have shown that to obtain a stable foam, the "foam concentrate" (in terms of the active substance) should be taken equal to 1.5-2% of the volume of the injected liquid, and the foam stabilizer - 0.5-1%. To mix surfactants and air on the surface, a special device is used - an aerator (such as a "perforated pipe in a pipe"). Air is pumped through a perforated branch pipe by a compressor in accordance with a given a, an aqueous solution of surfactant is pumped into the outer pipe by a pump at a flow rate of 2-3 l/s.

The effectiveness of the liquid removal method is substantiated by special well surveys and technical and economic calculations. The well is stopped for 2-4 hours to absorb fluid by the reservoir. The flow rates of the wells after start-up increase, but they do not always compensate for losses in gas production due to idle wells. Since the liquid column does not always go into the reservoir, and gas inflow may not resume at low pressures, this method is rarely used. Connecting the well to a low-pressure gas gathering network allows operating flooded wells, separating water from gas, and using low-pressure gas for a long time. 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 flow rate is restored for a long period (several days). However, this method has many disadvantages: the liquid is not completely removed from the bottomhole, the increasing drawdown on the reservoir leads to an intensive influx of new portions of water, the destruction of the reservoir, 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 the accumulation of a certain column of liquid at the bottom.

The gas from the well, together with the liquid, enters the low-pressure gas-gathering manifold, is separated from the water in the separators and enters for compression or is flared. The machine installed on the wellhead periodically opens the valve on the working line. The machine receives a command for this when the pressure difference between the annulus and the working line increases to a predetermined difference. The magnitude of this difference depends on the height of the liquid column in the tubing.

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

Downhole separation of the gas-liquid flow can be used to accumulate fluid at the bottomhole. This method of separation followed by fluid injection into the underlying horizon was tested after preliminary laboratory studies at the well. 408 and 328 Korobkovsky field. With this method, hydraulic pressure losses in the wellbore and the costs of collecting and utilizing formation waters are significantly reduced.

Periodic removal of liquid can also be carried out when applying surfactant to the bottom of the well. When water comes into contact with the blowing agent and the 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 small gas velocities (0.2-0.5 m/s) ensure the removal of the foamy mass to the surface.

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

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

The introduction of up to 300-400 liters of sulphonol solutions or Novost powder at individual wells of the Maykop 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 surfactants 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, which ensure the formation of a two-phase droplet 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 continuously flows to the bottom of the well. The diameter of the tubing string is selected to obtain flow rates that ensure the removal of fluid from the bottom. 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 a liquid column that is not removed from the bottomhole.

Gas-lift systems with a downhole valve are successfully used to remove liquid from the bottomhole. Gas is sampled through the annulus, and liquid is removed through the tubing, on which start-up gas-lift and downhole valves are installed. The valve is acted upon by the spring compression force and the pressure difference created by the fluid columns in the tubing and annulus (down), as well as the force due to the pressure in the annulus (up). At the calculated level of liquid in the annulus, the ratio of the acting forces becomes such that the valve opens and the liquid enters the tubing and further into the atmosphere or into the separator. After the liquid level in the annulus drops to the preset value, the inlet valve closes. Fluid builds up inside the tubing until the start gas lift valves operate. When the latter are opened, gas from the annulus enters the tubing and brings the liquid to the surface. After the liquid level in the tubing is lowered, the starting valves are closed, and liquid is again accumulated inside the pipes 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 X-mas tree. acts as a "piston".

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

At low formation 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 deposit development with a decrease in wellhead pressure to 0.2-0.4 MPa. Thus, downhole pumping units are used in conditions where 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 taken through the annulus. To prevent gas from entering the pump intake, it is placed below the perforation zone under the liquid buffer level or above the downhole valve, which allows only liquid to pass into the tubing.

field well flow rate anisotropy

3. Technological modes of operation of wells, reasons for the limitation of flow rates

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

Technological regime - these are specific conditions for the movement of gas in the reservoir, bottomhole zone and well, characterized by the value of the flow rate and bottomhole pressure (pressure gradient) and determined by some natural restrictions.

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 following have the greatest impact on well operation:

Deformation of the porous medium when creating 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 during the opening of 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 community collectors;

Opening of a layer of multi-layer deposits, taking into account the presence of a hydrodynamic connection between interlayers, etc.

All these and other factors are expressed by the following criteria, which have the form:

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

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

Pz(t) = Const -- constant bottom hole 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 wells, 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 taking into account 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 system "reservoir - the beginning of the gas pipeline" in the process of developing the deposit;

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

Timely change of previously established regimes 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 operation of wells, it is first necessary to establish a determining factor or a group of factors to justify the operation mode of project wells. At the same time, the designer should pay special attention to the presence of bottom water, multi-layeredness and the presence of hydrodynamic communication between the layers, the anisotropy parameter, the presence of lithological screens over the deposit area, the proximity of contour waters, the reserves and permeability of thin, highly permeable interlayers (super reservoirs), stability interlayers, on the magnitude of the limiting gradients from which the destruction of the reservoir begins, on the pressure and temperatures in the "reservoir-UKPG" system, on the change in the properties of gas and liquid from pressure, on the piping and on the conditions of gas drying, etc.

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

In most gas-bearing formations, vertical and horizontal permeabilities differ, and, as a rule, vertical permeability k is much less than horizontal k g. However, with low vertical permeability, the flow of gas from below into the area of influence of the imperfection of the well in terms of the degree of opening is also difficult. The exact mathematical relationship between the anisotropy parameter and the value of the allowable drawdown when the well penetrates an anisotropic reservoir with bottom water has not been established. The use of methods for determining Q pr, developed for isotropic reservoirs, leads to significant errors.

Solution algorithm:

1. Determine the critical parameters of the gas:

2. Determine the coefficient of supercompressibility in reservoir conditions:

3. We determine the density of the gas 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 the coefficient D:

8. We determine the coefficients K o , Q* and the maximum anhydrous flow rate Q pr.bezv. depending on the degree of formation penetration h and for two different values of the anisotropy parameter:

Initial data:

Table 1 - Initial data for the calculation of the anhydrous regime.

Table 4 - Calculation of the anhydrous regime.

5. Analysis of calculation results

As a result of the calculation of 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 received the following dependencies:

Figure 1 - Dependence of the limiting anhydrous flow rate on the degree of penetration 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 greater flow rate will be at a higher value of anisotropy, that is, at a greater ratio of vertical to horizontal permeability.

Bibliography

1. "Instruction for a comprehensive study of gas and gas condensate wells." M: Nedra, 1980. Edited by Zotov G.A. Aliyev Z.S.

2. Ermilov O.M., Remizov V.V., Shirkovsky A.I., Chugunov L.S. "Reservoir Physics, Production and Underground Gas Storage". M. Science, 1996

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