Determination of oil well flow rate: formula and methods of calculation. Method for measuring the flow rate of a gas well Calculation of the technological efficiency of sidetracking

Gas wells are operated in a flowing way, i.e. through the use of reservoir energy. The calculation of the lift is reduced to determining the diameter of the fountain pipes. It can be determined from the conditions of bottomhole removal of solid and liquid particles or to ensure the 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 velocity increases due to the increase in gas volume with decreasing pressure. The calculation is performed for the conditions of the shoe of the fountain pipes. The depth of descent of pipes into the well is taken taking into account the productive characteristics of the reservoir 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 holes of the perforations, then the velocity of the gas flow 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. Therefore, the lower part of the reservoir is cut off by a sandy-clay plug or liquid, while the well flow rate 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 Z, T Z - pressure and temperature of the gas at the bottomhole, Pa, K;

zo, zz - coefficient of gas supercompressibility, respectively, under the 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 bottom is 5 - 10 m/s. Then the maximum pipe diameter at which rock and liquid particles are brought to the surface:

During the operation of gas condensate wells, liquid hydrocarbons (gas condensate) are released from the gas, which create a two-phase flow in the fountain pipes. To prevent accumulation of liquid at the bottomhole and decrease in production rate, a gas condensate well must be operated with a production rate not less than the minimum allowable one, 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 pipe diameter:

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

where P 2 - pressure at the wellhead, MPa;

e is the base of natural logarithms;

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

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

L - length of fountain pipes, m;

d - pipe diameter, m;

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

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

The actual diameter of the fountain pipes is selected based on standard diameters. Note that in calculations based on two conditions, the determining factor is the removal of rock and liquid particles to the surface. If well flow rates are limited by other factors, then the calculation is carried out from the condition of reducing pressure losses to the minimum possible value from a technological and technical point of view. Sometimes, at a given pipe diameter, using the written formulas, the well flow rate or 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 Pz = 10.1 MPa; well depth H = 1320 m; gas compressibility factor under standard conditions z o = 1; the critical velocity 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 = H? G, (19)

where H - well depth, m

G - geothermal gradient.

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

where Р pl - reservoir pressure, MPa

Р 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 coefficient of gas compressibility at the bottomhole z z = 0.86 is determined from Figure 6 B (Appendix B).

1) Diameter of pumping compressor...

- 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 o C;
- concentration of fresh methanol C 1 % wt.

Calculation of the individual consumption rate of methanol for technological process in the preparation and transportation of natural and petroleum gas for each section is carried out according to the formula:

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

where H Ti - individual consumption rate of methanol in 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 DW - the amount of moisture taken from the gas, kg / 1000 m 3;

C 1 - weight concentration of the input methanol, %;

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

It follows from formula 24 that in order to determine the amount of methanol to saturate the liquid phase, it is necessary to know the gas humidity and methanol concentration 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 (by air) of 0.60, free of 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, they find the amount of moisture DW released from every 1000 m 3 of passing gas:

DW \u003d W 2 - W 1 (25)

We determine the humidity by the formula:

where P - 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 C 2 first determine the equilibrium temperature T (°C) hydrate formation. To do this, use the equilibrium curves for the formation of gas hydrates of various densities (Figure 7 B, Appendix B) based on the average pressure in the methanol supply section:

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

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

DT \u003d 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 the treated 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 \u003d 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 (the solubility of methanol in the gas).

The coefficient k m is determined for the conditions of the end of the section on which the formation of hydrates is possible, according to Figure 9 B (Appendix B) for pressure P 2 and temperature T 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. 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 (C "Enomanskaya vent). As an oil field, it was discovered in 1975. In 1980, it was compiled technology system development, 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 represents an uplifted zone irregular shape, oriented in the southwest-northeast directions, 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 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 reservoir, 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 cement mortar 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 the gas gathering network low pressure allows you to operate flooded wells, separate water from gas, use 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, pollution environment, loss of gas.

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 salinity 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 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 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 reduced, the starting valves are closed, and liquid again accumulates 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 the development of the field 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, multilayeredness and the presence of hydrodynamic communication between the 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 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 reservoir penetration h and for two different values 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.

How to determine

Everyone knows that the main purpose of the well is to provide owners with water. High Quality in sufficient quantity. This must be done before drilling is completed. Then these data must be compared with those obtained during geological exploration. Geological exploration provides information about whether there is an aquifer in a given place and how powerful it is.

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

Master data for debit determination

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

Dynamic and static level

Before you find out what the well's water flow 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.

It is important that the debit is a non-constant value. It depends entirely on seasonal changes and some other circumstances. Therefore, it is impossible to establish exactly its indicators. This means that you need to use approximate figures. This work is required to establish whether a certain water supply is enough for normal living conditions.

The static level shows how much water is in the well without sampling. Such an indicator is considered 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 production rates

In order for the information to be objective, you need to wait until the moment when the water is collected to the previous level. Only then can you continue your research. In order for the information to be objective, everything must be done consistently.

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

How is the debit calculated?

In order not to puzzle over how to increase the flow rate of the 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 up and the water yield decreases further, then the problem will only get worse.

If your well is about 80 meters deep, and the zone where the water starts is located at 75 meters from the surface, the static indicator (Hst) will be at a depth of 40 meters. Such data will help us calculate what is the height of the water column (Hw): 80 - 40 \u003d 40 m.

There is a very simple way, but its data is not always true, a way to determine the debit (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 \u003d V * Hw / Hd - Hst. The intensity of pumping 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 dropped by 12 m, then the dynamic level was 40 + 12 = 52 m. Now we can transfer our data to the formula and get a debit that is 10 m 3 / hour .

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

With a rope with a plumb line, you can 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 different power. Only in this way will the result be closest to the truth.

To carry out calculations by this method, after the first measurement, you need to wait until the water level is restored to its previous level. Then pump out 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 received during the two samplings 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 compared to static indicators. For us, they amounted to 24 and 12 m. Thus, we received a flow rate of 0.17 m 3 / hour.

The specific well flow rate 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 upper point where the water intake begins (filter). We took 75 m for this indicator. Substituting the values \u200b\u200binto the formula, we get an indicator that equals 5.95 m 3 / hour. Thus, this indicator is almost two times less than that recorded in the well passport. 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 flow rate of the well. It will show what the daily productivity of the well is.

In some cases, the construction of the well 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. Accurate information must 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.

YesNo

Methods for determining the limiting waterless flow rates of gas wells in the presence of a screen and the interpretation of the results of the study of such wells have not been developed enough. Until now, the question of the possibility of increasing the maximum waterless production rates of wells penetrating gas-bearing formations with bottom water by creating an artificial screen has also not been fully studied. Here, an analytical solution of this problem is presented and the case is considered when an imperfect well penetrated a uniformly anisotropic circular reservoir with bottom water and is operated in the presence of an impermeable screen. An approximate method for calculating the limiting anhydrous flow rates of vertical gas wells with a non-linear filtration law, due to the presence of an impermeable bottomhole screen, has been developed. It has been established that the value of the limiting anhydrous flow rate depends not only on the size of the screen, but also on its position along the vertical of the gas-saturated reservoir; the optimal position of the screen, which characterizes the highest marginal flow rate, is determined. Practical calculations are made on specific examples.

calculation method

anhydrous flow rate

vertical well

gas well

1. Karpov V.P., Sherstnyakov V.F. Character of phase permeability according to field data. NTS for oil production. – M.: GTTI. - No. 18. - S. 36-42.

2. Telkov A.P. Underground hydrodynamics. - Ufa, 1974. - 224 p.

3. Telkov A.P., Grachev S.I. and other Features of the development of oil and gas fields (Part II). - Tyumen: from-in OOONIPIKBS-T, 2001. - 482 p.

4. Telkov A.P., Stklyanin Yu.I. Formation of water cones during oil and gas production. – M.: Nedra, 1965.

5. Stklyanin Yu.I., Telkov A.P. Inflow to a horizontal drain and imperfect well in a banded anisotropic reservoir. Calculation of limiting anhydrous flow rates. PMTF Academy of Sciences of the USSR. - No. 1. - 1962.

This article provides an analytical solution to this problem and considers the case when an imperfect well penetrated a uniformly anisotropic circular reservoir with bottom water and is operated in the presence of an impermeable screen (Figure 1). We consider that the gas is real, the movement of the gas is steady and obeys the nonlinear law of filtration.

Fig.1. Three-zone scheme of gas inflow to an imperfect well with a screen

Based on the accepted conditions, the equations of gas inflow to the well in zones I, II, III, respectively, will take the form:

; ; (2)

; ; , (3)

where a and b are determined by formulas. The remaining designations are shown in the diagram (see Figure 1). Equations (2) and (3) in this case describe the inflow to enlarged wells, respectively, with radii rе and (re+ho).

The stability condition at the gas-water interface (see line CD) according to Pascal's law is written by the equation

where ρw is the density of water, is the capillary pressure as a function of water saturation at the gas-water interface.

Solving jointly (1)-(3), after a series of transformations, we obtain the inflow equation

From the joint solution of (2) and (4) we obtain a quadratic equation for the dimensionless limiting flow rate , one of the roots of which, taking into account (7) and after a series of transformations, is represented by the expression:

Where (7)

(8)

The transition to the dimensional limiting anhydrous flow rate is carried out according to the formulas:

(9)

where is the weighted average pressure in the gas deposit.

Table 1

The values of filtration resistance due to the screen at the bottom

Additional filtration resistances And , caused by the screen, are calculated on a computer according to formulas (6), tabulated (table 1) and presented by graphs (figure 2). Function (6) is calculated on a computer and presented graphically at (Figure 3). The maximum drawdown can be set according to the inflow equation (4.4.4) at Q=Qpr.

Fig.2. Filtration resistance And , due to the screen at a stable gas-water interface

Fig.3. Dependence of the dimensionless limiting flow rate qpr on the relative opening at the parameters , ρ=1/æ* and α

Figure 3 shows the dependences of the dimensionless limiting flow rate q on the degree of opening at the parameters Re and α. The curves show that as the screen size increases (<20) безводные дебиты увеличиваются. Максимум на кривых соответствует оптимальному вскрытию пласта, при котором можно получить наибольший предельный безводный дебит для заданного размера экрана. С увеличением параметра ρ=1/æ* (уменьшением анизотропии) предельный безводный дебит увеличивается, а уменьшение безводного дебита для малых вскрытий объясняется увеличением фильтрационных сопротивлений, обусловленных экраном на забое.

Example. A gas cap is drained in contact with the plantar water. It is required to determine: the maximum flow rate of a gas well, which limits the GWC breakthrough to the bottom, and the maximum flow rate in the presence of an impermeable screen.

Initial data: Рpl=26.7 MPa; K=35.1 10-3 µm2; Ro=300 m; ho=7.2 m; =0.3; =978 kg/m3; =210 kg/m3 (under reservoir conditions); æ*=6.88; =0.02265 MPa s (in reservoir conditions); Tm=346 K; Tst=293 K; Rath=0.1013 MPa; re=ho=7.2 m and re=0.5ho=3.6 m.

Defining the placement parameter

From the graphs we find the dimensionless limiting anhydrous liquid flow rate q(ρо,)q(6.1;0.3)=0.15.

According to formula (9) we calculate:

Qo=52.016 thousand m3/day; thousand m3/day

We determine the dimensionless parameters in the presence of a screen:

According to the graphs (see Figure 2) or the table, we find additional filtration resistances: С1= С1(0.15;0.3;1)=0.6; C2=C2(0.15;0.3;1)=3.0.

By formula (7) we find the dimensionless parameter α=394.75.

According to formula (9), we calculate the flow rate, which amounted to Qo47.9 thousand m3/day.

Calculations by formulas (7) and (8) give: Х=51.489 and Y=5.773·10-2.

The dimensionless limiting flow rate calculated by formula (6) is equal to q=1.465.

We determine the dimensional limiting flow rate, due to the screen, from the ratio Qpr \u003d qQo \u003d 1.465 47.970.188 thousand m3 / day.

The estimated maximum flow rate without a screen with similar initial parameters is 7.8 thousand m3/day. Thus, in the case under consideration, the presence of a screen increases the marginal flow rate by almost 10 times.

If we accept re = 3.6 m; those. two times smaller than the gas-saturated thickness, then we obtain the following design parameters:

2; C1=1.30; C2=5.20; X=52.45; Y=1.703 10-2; q=0.445 and Qpr=21.3 thousand m3/day. In this case, the marginal flow rate increases only 2.73 times.

It should be noted that the value of the marginal flow rate depends not only on the size of the screen, but also on its position along the vertical of the gas-saturated reservoir, i.e. from the relative opening of the reservoir, if the screen is located directly in front of the bottomhole. The study of solution (6) showed that there is an optimal position of the screen, depending on the parameters ρ, α, Re, which corresponds to the highest marginal flow rate. In the considered problem, the optimal opening is =0.6.

We accept ρ=0.145 and =1. According to the above method, we obtain the calculated parameters: С1=0.1; C2=0.5; X=24.672; Y=0.478.

We determine the dimensionless debit:

q=24.672(-1) 5.323.

The dimensional limiting flow rate is found by the formula (9)

Qpr \u003d qQo \u003d 5.323 103 \u003d 254.94 thousand m3 / day.

Thus, the flow rate increased by 3.6 times compared to the relative opening = 0.3.

The method described here for determining the limiting anhydrous flow rate is approximate, since it considers the stability of the cone, the top of which has already reached the radius of the screen re.

When from the above solutions, we obtain formulas for determining q() for an imperfect gas well under the conditions of a nonlinear filtration law, taking into account additional filtration resistances. These formulas will also be approximate, and an overestimated value of the limiting anhydrous flow rate is calculated from them.

To construct a two-term gas inflow equation under the conditions of an extremely stable bottom water cone, it is necessary to know the filtration resistances under these conditions. They can be determined based on the Musket-Charny theory of stable cone formation. The equation of the streamline that limits the area of spatial movement to an imperfect well in a homogeneously anisotropic reservoir, when the cone apex has already broken through to the bottom of the well, in accordance with the theory of non-pressure movement, we write in the form

(10)

where q= - dimensionless limiting anhydrous flow rate, determined by the given (known) approximate formulas and graphs; is a dimensionless parameter.

Expressing the filtration rate through the flow rate , substituting the interface equation (10) into the differential equation (1), taking into account the law of the gas state and integrating over pressure P and radius r within the appropriate limits, we obtain an inflow equation of the form (12) and formula (13), in which should be accepted:

; , (11)

(12)

where Li(x) is the integral logarithm, which is related to the integral function by the dependence .

(13)

For x>1 integral (13) diverges at the point t=1. In this case, Li(x) should be understood as the value of the improper integral. Since the methods for determining the dimensionless limiting waterless flow rates are well known, there is obviously no need to tabulate functions (11) and (12).

1. An approximate method has been developed for calculating the limiting waterless flow rates of vertical gas wells with a nonlinear filtration law, due to the presence of an impermeable bottomhole screen. Dimensionless limiting flow rates and the corresponding additional filtration resistances are calculated on a computer, the results are tabulated and the corresponding graphical dependencies are shown.

2. It has been established that the value of the limiting anhydrous flow rate depends not only on the size of the screen, but also on its position along the vertical of the gas-saturated reservoir; the optimal position of the screen, which characterizes the highest marginal flow rate, is determined.

3. Practical calculations were made on a specific example.

Reviewers:

Grachev S.I., Doctor of Technical Sciences, Professor, Head of the Department "Development and Operation of Oil and Gas Fields", Institute of Geology and Oil and Gas Production, FGBOU Tsogu, Tyumen;

Sokhoshko S.K., Doctor of Technical Sciences, Professor, Professor of the Department "Development and Operation of Oil and Gas Fields", Institute of Geology and Oil and Gas Production, FGBOU Tsogu, Tyumen.

Bibliographic link

Kashirina K.O., Zaboeva M.I., Telkov A.P. METHOD FOR CALCULATION OF LIMITED WATER-FREE RATES OF VERTICAL GAS WELLS UNDER A NON-LINEAR FILTRATION LAW AND THE PRESENCE OF A SCREEN // Contemporary Issues science and education. - 2015. - No. 2-2.;
URL: http://science-education.ru/ru/article/view?id=22002 (date of access: 01.02.2020). We bring to your attention the journals published by the publishing house "Academy of Natural History"

The formula for calculating the flow rate of an oil well is a necessary thing in modern world. All enterprises that extract oil products must calculate the debit for their brainchildren. Many people use the formula of Dupuis, a French engineer who devoted many years to studying motion. ground water. His formula will help you easily understand whether the performance of a particular source of money for well equipment.

What is the flow rate of an oil well?

Debit - the volume of fluid supplied through the well for a certain unit of time. Many neglect his calculations when installing pumping equipment, but this can be fatal for the entire structure. The integral value that determines the amount of oil is calculated using several formulas, which will be given below.

The flow rate is often referred to as pump performance. But this characteristic is a little out of the definition, since all pump properties have their own errors. And a certain volume of liquids and gases is sometimes fundamentally different from the declared one.

Initially, this indicator should be calculated to select pumping equipment. When you know what the productivity of the site is, it will be possible to immediately exclude several unsuitable units from the selectable list of equipment.

It is imperative to calculate the flow rate in the oil industry, since low-productivity areas will be unprofitable for any enterprise. And an incorrectly selected pumping unit, due to missed calculations, can bring losses to the company, and not the profit expected from the well.

It is obligatory for calculation at all types of oil producing enterprises - even the flow rates of nearby wells may differ too much from the new one. Most often, a huge difference lies in the values \u200b\u200bsubstituted in the formulas for calculation. For example, the permeability of a reservoir can vary significantly per kilometer underground. With poor permeability, the indicator will be less, which means that the profitability of the well will decrease exponentially.

The flow rate of an oil well will tell you not only how to choose the right equipment, but also where to install it. Installing a new oil rig is a risky business, as even the smartest geologists cannot unravel the mysteries of the earth.

Yes, thousands of models of professional equipment have been created that determine all the necessary parameters for drilling a new well, but only the result seen after this process will be able to show the correct data. Based on them, it is worth calculating the profitability of a particular site.

Methods for calculating well flow rates.

There are only a few methods for calculating the flow rate of an oil field - standard and Dupuis. The formula of a person who has been studying this material and deriving a formula for almost all his life shows the result much more accurately, because it contains much more data for calculation.

Formula for calculating well flow rates

For calculations according to the standard formula - D \u003d H x V / (Hd - Hst), you only need the following information:

Height of the water column;
pump performance;
Static and dynamic level.

The static level in this case is the distance from the beginning of groundwater to the first layers of soil, and the dynamic level is the absolute value obtained by measuring the water level after pumping.

There is also a concept as an optimal indicator of the oil field production rate. It is determined both for the general establishment of the level of drawdown of an individual well, and the entire reservoir as a whole. The formula for calculating the average level of depression of the field is defined as P zab=0. The flow rate of one well, which was obtained at optimal drawdown, will be the optimal flow rate of an oil well.

However, such a formula and the indicator of the optimal flow rate itself are not used in every field. Due to mechanical and physical pressure on the formation, part of the inner walls of oil wells may collapse. For these reasons, it is often necessary to reduce the potential flow rate mechanically in order to maintain the continuity of the oil production process and maintain the strength of the walls.

This is the simplest calculation formula, which will not be able to accurately obtain the correct result - there will be a large error. In order to avoid incorrect calculations and direct yourself to get a more accurate result, use the Dupuis formula, in which you need to take much more data than in the one presented above.

But Dupuis was not just smart person, but also an excellent theorist, so he developed two formulas. The first is for the potential productivity and hydraulic conductivity that the pump and the oil field generate. The second is for a non-ideal field and pump, with their actual productivity.

Consider the first formula:

N0 = kh/ub * 2Pi/ln(Rk/rc).

This formula for potential performance includes:

N0 – potential productivity;

Kh/u is the coefficient that determines the property of the hydraulic conductivity of the oil reservoir;

B is the volume expansion coefficient;

Pi - Number P \u003d 3.14 ...;

Rk is the radius of the loop supply;

Rc is the bit radius of the well in terms of the distance to the penetrated reservoir.

The second formula looks like this:

N = kh/ub * 2Pi/(ln(Rk/rc)+S).

This formula for the actual productivity of the field is now used by absolutely all companies that drill oil wells. It only changes two variables:

N - actual productivity;

S-skin factor (parameter of filtration resistance to flow).

In some methods, to increase the production rate of oil fields, the technology of hydraulic fracturing with minerals is used. It is implied by the formation of mechanical cracks in the productive rock.

The natural process of reducing the production rate of oil fields occurs with an indicator of 1-20 percent per year, based on the initial data of this indicator at the start of the well. The technologies applied and described above can intensify the production of oil from a well.

Periodically, mechanical adjustment of the flow rate of oil wells can be carried out. It is marked by an increase in bottomhole pressure, which leads to a decrease in production levels and a high indicator of the opportunities of a single field.

The thermal acid treatment method can also be used to increase the performance and production rate. With the help of several types of solutions, such as an acid liquid, the elements of the deposit are cleaned of tar deposits, salt and other chemical components that interfere with the quality and efficient passage of the extracted rock.

Acid fluid initially penetrates the well and fills the area in front of the formation. Next, the process of closing the valve is carried out and, under pressure, the acid solution penetrates into the deep formation. The remaining parts of this fluid are washed with oil or water after the production operation continues.

The calculation of the flow rate should be carried out periodically to form a strategy for the vector development of an oil producing enterprise.