One of the characteristics of a drilled well is the rate of production from a drilled subterranean formation, or the ratio of volume to a certain time period. It turns out that the flow rate of a well is its performance, measured in m 3 / hour (second, day). The value of the well flow rate must be known when choosing the productivity of a well pump.
Factors determining filling rate:
Debit: calculation methods
The power of the pump for an artesian well must correspond to its productivity. Before drilling, it is necessary to calculate the volume required for water supply and compare the obtained data with the indicators of the exploration of the geological service in relation to the depth of the reservoir and its volume. The well flow rate is determined by a preliminary calculation of statistical and dynamic indicators relative to the water level.
Wells with a productivity of less than 20 m 3 /day are considered low-rate.
Reasons for a small well flow rate:
The calculation of the well flow rate is carried out at the stage of determining the depth of the aquifer, drawing up the design of the well, choosing the type and brand of pumping equipment. At the end of drilling, experimental filtration work is carried out with the indicators recorded in the passport. If an unsatisfactory result is obtained during commissioning, this means that errors were made in determining the design or selection of equipment.
Small well flow rate, what to do? There are several options:
Basic parameters for calculating the flow rate
The debit calculation formula is based on an exact mathematical calculation:
D \u003d H x V / (Hd - Hst), meter:
Well rate calculation example:
Substituting the data, we get the estimated flow rate - 5.716 m 3 / h.
For verification, a trial pumping with a larger pump is used, which will improve the dynamic level readings.
The second calculation must be performed according to the above formula. When both flow rates are known, the specific indicator is known, which gives an accurate idea of how much productivity increases with an increase in the dynamic level by 1 meter. For this, the formula is applied:
Dsp = D2 – D1/H2 – H1, where:
Work on the creation of a well in the adjacent area includes drilling, strengthening the head. Upon completion, the company that executed the order draws up a document for the well. The passport indicates the parameters of the structure, characteristics, measurements and calculation of the well.
Well Calculation Procedure
Employees of the company draw up an inspection protocol and an act of transfer to use.
The procedures are mandatory, since they provide an opportunity to obtain documentary evidence of the design's serviceability and the possibility of putting it into operation.
Geological parameters and technological characteristics are included in the documentation:
In order to check the correctness of the calculation, a test pumping of water is started at a high pump power. This improves the dynamics
In practice, for the accuracy of the calculation, the second formula is used. After receiving the flow rate values, an average indicator is determined, which allows you to accurately determine the increase in productivity with an increase in dynamics by 1 m.
Calculation formula:
Doud= D2 – D1/H2 – H1
- Dud - specific debit;
- D1, H1 - indicators of the first test;
- D2, H2 - indicators of the second test.
Only with the help of calculations, the correctness of the research and drilling of the water intake is confirmed.
Design characteristics in practice
Acquaintance with the methods for calculating a water well provokes the question - why does an ordinary user of a water intake need this knowledge? It is important to understand here that water loss is a single way to assess the health of a well in order to satisfy the needs of residents for water before signing the acceptance certificate.
To avoid problems in the future, proceed as follows:
- The calculation is carried out taking into account the number of residents of the house. The average water consumption is 200 liters per person. Added to this are the costs of economic needs and technical use. When calculating for a family of 4 people, we get the highest water consumption of 2.3 cubic meters / hour.
- In the process of drawing up the contract in the project, the value of the water intake productivity is taken at a level of at least 2.5 - 3 m 3 / h.
- After completion of work and calculation of the level of the well, water is pumped out, the dynamics are measured and the water loss is determined at the highest flow rate of the home pump.
Problems may arise at the level of calculating the well's water flow rate in the process of control pumping out by a pump owned by the contractor company.
The moments that determine the rate of filling the well with water:
- The volume of the water layer;
- The speed of its reduction;
- Groundwater depth and level changes depending on the season.
Wells with a water intake productivity of less than 20 m 3 /day are considered unproductive.
Reasons for low flow rates:
- features of the hydrogeological situation of the area;
- changes depending on the season;
- filter clogging;
- blockages in the pipes that supply water to the top or their defloration;
- natural wear of the pump.
If problems are found after the well is put into operation, this indicates that there were errors at the stage of calculating the parameters. Therefore, this stage is one of the most important, which should not be overlooked.
In order to increase the productivity of the water intake, increase the depth of the well in order to open an additional layer of water.
Also, they use methods of pumping water experimentally, apply chemical and mechanical effects on the water layers, or transfer the well to another place.
CALCULATION OF DEBIT OF GAS WELLS WITH A HORIZONTAL TERMINATION Ushakova A.V.
Ushakova Anastasia Vadimovna - undergraduate, Department of Development and Operation of Oil and Gas Fields, Tyumen Industrial University, Tyumen
Abstract: in order to justify the well operation mode and predict the development parameters, it is necessary, first of all, to calculate the well productivity - to establish the relationship between the well flow rate and drawdown. The flow rate of the well, as well as the depth of the formation in which drilling is planned, affect the design of the well, in addition, when choosing a design, it is necessary to ensure the minimum values of pressure losses along the wellbore. In the case of a horizontal (sloping) well, pressure losses also appear in the horizontal part of the wellbore. This paper describes the main types of hydraulic resistance encountered when gas moves to a horizontal well, and provides methods for calculating the inflow profile and flow rate of a horizontal well.
Key words: horizontal gas well, inflow profile, pressure loss.
The issue of gas inflow to horizontal wells was dealt with by Z.S. Aliev, V.V. Sheremet, V.A. Chernykh, Sokhoshko S.K. , Telkov A.P. .
The main difficulties of analytical solutions to the problems of inflow to horizontal wells are related to the nonlinear relationship between the pressure gradient and the filtration rate, as well as the determination of friction losses during the movement of gas and gas condensate mixture in a horizontal wellbore, especially with significant flow rates and long wellbore.
Sokhoshko S.K. distinguishes 3 groups of works devoted to the productivity of horizontal gas wells:
1 Relatively accurate solution of gas inflow to a horizontal well with a linear relationship between pressure gradient and filtration rate;
2. Approximate solution of the problem of gas inflow to a horizontal well with a nonlinear relationship between pressure gradient and filtration rate;
3 Exact numerical solution of the problem of gas inflow to a horizontal well with a nonlinear law of filtration, set out in the work and a linear law;
The disadvantage of these works is that they assume constant bottomhole pressure along the length of the horizontal wellbore, and also do not take into account the effect of wellhead pressure on the productivity of horizontal wells. As a result, a direct ratio of productivity and the length of the horizontal section was obtained.
However, many researchers claim that this performance calculation scheme is fundamentally wrong. For horizontal wells, knowledge about the distribution of bottom hole pressure is more important than for vertical wells. This is due to the fact that the area of the drainage zone in a horizontal well is larger than in a vertical well.
One of the solutions, which takes into account the change in bottomhole pressure when calculating productivity, was obtained by Z.S. Aliyev and A.D. Sedykh. Also, the solution of the inflow profile for the first time, taking into account all types of hydraulic resistance, including local resistance of perforations, their location and density, as well as taking into account the angle of inclination for a horizontal gas well, was obtained by Sokhoshko S.K. .
| 37 | Modern innovations № 2(30) 2018
Bibliography
1. Aliev Z.S., Sheremet V.V. Determination of the productivity of horizontal wells that have opened gas and gas-oil reservoirs. M.: Nedra, 1995.
Well flow rate is main well parameter, showing how much water can be obtained from it in a certain period of time. This value is measured in m 3 / day, m 3 / hour, m 3 / min. Therefore, the higher the well flow rate, the higher its productivity.
First of all, you need to determine the well flow rate in order to know how much liquid you can count on. For example, is there enough water for uninterrupted use in the bathroom, in the garden for watering, etc. In addition, this parameter is of great help in choosing a pump for water supply. So, the larger it is, the more efficient the pump can be used. If you buy a pump without paying attention to the flow rate of the well, then it may happen that it will suck water out of the well faster than it will be filled.
Static and dynamic water levels
In order to calculate the flow rate of a well, it is necessary to know the static and dynamic water levels. The first value indicates the water level in a calm state, i.e. at a time when the pumping of water has not yet been made. The second value determines the established water level while the pump is running, i.e. when the rate of its pumping is equal to the rate of filling the well (water stops decreasing). In other words, this debit directly depends on the performance of the pump, which is indicated in its passport.
Both of these indicators are measured from the surface of the water to the surface of the earth. The unit of measurement is usually the meter. So, for example, the water level was fixed at 2 m, and after turning on the pump, it settled at 3 m, therefore, the static water level is 2 m, and the dynamic one is 3 m.
I would also like to note here that if the difference between these two values is not significant (for example, 0.5-1 m), then we can say that the flow rate of the well is large and most likely higher than the pump performance.
Well flow rate calculation
How is the flow rate of a well determined? This requires a high-performance pump and a measuring tank for pumped water, preferably as large as possible. The calculation itself is best considered on a specific example.
Initial data 1:
- Well depth - 10 m.
- The beginning of the level of the filtration zone (the zone of water intake from the aquifer) - 8 m.
- Static water level - 6 m.
- The height of the water column in the pipe - 10-6 = 4m.
- Dynamic water level - 8.5 m. This value reflects the remaining amount of water in the well after pumping out 3 m 3 of water from it, with the time spent on this being 1 hour. In other words, 8.5 m is the dynamic water level at a debit of 3 m 3 / h, which decreased by 2.5 m.
Calculation 1:
Well flow rate is calculated by the formula:
D sk \u003d (U / (H dyn -H st)) H in \u003d (3 / (8.5-6)) * 4 \u003d 4.8 m 3 / h,
Conclusion: well debit is equal to 4.8 m3/h.
The presented calculation is very often used by drillers. But it carries a very large error. Since this calculation assumes that the dynamic water level will increase in direct proportion to the pumping speed of the water. For example, with an increase in pumping water to 4 m 3 / h, according to him, the water level in the pipe drops by 5 m, which is not true. Therefore, there is a more accurate method with the inclusion in the calculation of the parameters of the second water intake to determine the specific flow rate.
What should be done about it? It is necessary after the first water intake and data recording (previous option), to allow the water to settle and return to its static level. After that, pump out water at a different speed, for example, 4 m 3 /hour.
Initial data 2:
- The well parameters are the same.
- Dynamic water level - 9.5 m. With a water intake intensity of 4 m 3 / h.
Calculation 2:
The specific well flow rate is calculated by the formula:
D y \u003d (U 2 -U 1) / (h 2 -h 1) \u003d (4-3) / (3.5-2.5) \u003d 1 m 3 / h,
As a result, it turns out that an increase in the dynamic water level by 1 m contributes to an increase in the flow rate by 1 m 3 / h. But this is only on condition that the pump will be located not lower than the beginning of the filtration zone.
The real flow rate is calculated here by the formula:
D sc \u003d (N f -H st) D y \u003d (8-6) 1 \u003d 2 m 3 / h,
- H f = 8 m- the beginning of the level of the filtration zone.
Conclusion: well debit is equal to 2 m 3 /h.
After comparison, it can be seen that the values of the well flow rate, depending on the calculation method, differ from each other by more than 2 times. But the second calculation is also not accurate. The well flow rate, calculated through the specific flow rate, is only close to the real value.
Ways to increase well production
In conclusion, I would like to mention how the well flow rate can be increased. There are essentially two ways. The first way is to clean the production pipe and the filter in the well. The second is to check the performance of the pump. Suddenly, it was for his reason that the amount of produced water decreased.
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 gas flow rate in the production string opposite the perforated productive formation increases from zero to a certain value from bottom to top. 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 fluid 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 minimal 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 wellhead pressure P 2, the diameter of the flow 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.
The calculation of the individual methanol consumption rate for the 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 is 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.
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