Selecting the operating mode of a gas well. Advances of modern natural science Calculation of gas well flow rate

test

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

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

Solution algorithm:

1. Determine the critical parameters of the gas:

2. Determine the supercompressibility coefficient under reservoir conditions:

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

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

5. Determine the coefficients a* and b*:

6. Determine the average radius:

7. Find coefficient D:

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

Initial data:

Table 1 - Initial data for calculating the anhydrous regime.

Table 4 - Calculation of anhydrous mode.

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MINISTRY OF EDUCATION AND SCIENCE OF THE RUSSIAN FEDERATION

higher vocational education

"Tyumen State Oil and Gas University"

Features of oil field development with horizontal wells

Guidelines

For independent work in the discipline “Features of field development with horizontal wells” for masters studying in the specialty 131000.68 “Oil and Gas Engineering”

Compiled by: S.I. Grachev, A.S. Samoilov, I.B. Kushnarev

Ministry of Education and Science of the Russian Federation

Federal state budget educational institution
higher professional education

"Tyumen State Oil and Gas University"

Institute of Geology and Oil and Gas Production

Department of Development and Operation of Oil and Gas Fields

Guidelines

In the discipline “Features of oil field development with horizontal wells”

for practical, laboratory classes and independent work for bachelors of direction 131000.62 “Oil and Gas Engineering” for all forms of education

Tyumen 2013

Approved by the editorial and publishing council

Tyumen State Oil and Gas University

The guidelines are intended for bachelors of the direction 131000.62 “Oil and Gas Engineering” for all forms of study. IN methodological guidelines The main tasks with examples of solutions in the discipline “Features of oil field development with horizontal wells” are given.

Compiled by: Associate Professor, Ph.D. Samoilov A.S.

Associate Professor, Ph.D. Fominykh O.V.

laboratory assistant Nevkin A.A.

© state educational institution of higher professional education

"Tyumen State Oil and Gas University" 2013

INTRODUCTION 2

Topic 1. Calculation of production rates of wells with horizontal termination and comparison of results. 7

Topic 2. Calculation of the flow rate of a horizontal well and an inclined well with a hydraulic fracturing fracture using the given formulas, comparing the results. 2

Topic 3. Calculation of the flow rate of a multilateral well. 17

Topic 4. Calculation of the optimal grid of horizontal wells and the comparative efficiency of their work with vertical ones. 21

Topic 5. Interpretation of the results of hydrodynamic studies of wells with horizontal completion in steady-state modes (according to the method of V.S. Evchenko). 2

Topic 6. Production rate of a horizontal well with hydraulic fractures located in an anisotropic, band-like formation. 34

Topic 7. Calculation of the maximum anhydrous drawdown of a well with a horizontal end…………………………………………………………………………………30

Topic 8. Modeling of unsteady fluid movement to a horizontal well using a two-zone scheme……………………………45

INTRODUCTION

With large-scale implementation in the early 2000s and over the next decade into the field development system Western Siberia horizontal wells (HS) and horizontal lateral trunks (HSS), accelerated production of oil reserves was achieved with a quick return on investment without the construction of new wells. The implementation was carried out in a prompt manner, not always consistent with the adopted design solutions, or by transformation existing system development. However, without a systematic justification for the technology of horizontal opening and operation of objects, the design values ​​of the oil recovery factor (ORF) are not achieved.

IN last years horizontal opening technology is given much more attention when designing a development system; in some companies, the justification for the construction of each horizontal well is carried out in the form of a mini-project. This was also influenced by the global financial crisis, when, in order to optimize production, the error and the share of uncertainty were reduced to a minimum. New approaches have been applied to horizontal drilling technology, as evidenced by the operating results of GS and BGS built since 2009 (more than 350 wells have been built at Surgutneftegaz OJSC, more than 200 wells at Lukoil OJSC, and more than 100 wells at TNK-BP. , in OJSC NGK Slavneft there are more than 100 wells, in OJSC Gazprom Neft there are more than 70 wells, in OJSC NK Rosneft there are more than 50 wells, in OJSC NK RussNeft there are more than 20 wells).

It is known that it is not enough to determine only the basic parameters of the use of horizontal wells: length, profile, location of the trunk relative to the roof and base, limiting technological operating conditions. It is necessary to take into account the placement and parameters of the well pattern, formation patterns and regulation of their operating modes. It is necessary to create fundamentally new methods for monitoring and managing the production of oil reserves, especially for complex deposits, which will be based on a reliable study geological structure through the study of horizontal wells, the dependence of oil flow rate on the heterogeneity of the geological structure and hydraulic resistance along the length, creating uniformity in the production of oil reserves throughout the entire volume of the reservoir of the drained horizontal well, high-precision determination of the drainage zone, the possibility of carrying out and predicting the effectiveness of methods for increasing oil recovery, determining the main rock stresses, the efficiency of the flooding system directly depends on their accounting and mechanical methods impact on the formation (hydraulic fracturing).

The purpose of this guideline is to provide students with the knowledge used by modern science and production in well productivity management.

The methodological instructions for each problem by topic present a calculation algorithm and provide an example of a solution typical task, which significantly contributes to the successful completion of the task. However, its application is possible only after studying the theoretical foundations.

All calculations should be carried out within the framework international system units (SI).

Theoretical basis The disciplines are well presented in textbooks, the links of which are given.

Topic 1. Calculation of production rates of wells with horizontal termination and comparison of results

To determine the oil production rate in a single horizontal well in a uniformly anisotropic formation, the S.D formula is used. Joshi:

Where, Q g– oil flow rate of a horizontal well m 3 /sec; k h– horizontal permeability of the formation m2; h– oil-saturated thickness, m; ∆P– reservoir drawdown, Pa; μ n– oil viscosity Pa s; B 0– volumetric coefficient of oil; L– length of the horizontal section of the well, m; r c– wellbore radius in the productive formation, m; – semimajor axis of the drainage ellipse (Fig. 1.1), m:

, (1.2)

Where Rk– radius of the power circuit, m; – permeability anisotropy parameter, determined by the formula:

kv– vertical permeability of the formation, m2. The calculations assumed a vertical permeability of 0.3· k h, the averaged parameter of terrigenous sediments of Western Siberia, also for a reliable calculation the condition - , must be met.

Figure 1.1 - Inflow diagram to a horizontal wellbore in a circular formation

Borisov Yu.L. when describing an elliptic flow, he proposed another condition for determining Rk. The main radius of the ellipse (Fig. 1.2), which is average value between axle shafts:

(1.4)

Figure 1.2 - Scheme of inflow to a horizontal wellbore in a circular formation

The general formula for the inflow to the gas station, obtained by Yu.P. Borisov, has the following form:

, (1.5)

Where J– filtration resistance, determined by the formula:

. (1.6)

Giger proposes to use formula (1.8), where for the filtration resistance J take expression

(1.7)

The general formula for the inflow to the gas station, obtained Giger is similar to the equations of previous authors:

. (1.8)

All symbols parameters are similar to those presented for the Joshi S.D. equation.

Task 1.1. For the geological and physical conditions of the PK 20 formation of the Yarainerskoye field, presented in Table 1.1, calculate the flow rate of a well with a horizontal end Q g using the presented methods, compare the results obtained, determine the optimal length of the horizontal section according to the graph of the dependence of the well flow rate on the length of the horizontal line for 10 values ​​(from the initial one) with a step of 50 meters for the solutions of the considered authors.

Table 1.1

Solution. The problem is solved in the following order:

1. Let’s calculate the flow rate of the gas pipeline using the Joshi S.D. method. To do this, it is necessary to determine the anisotropy parameter from expression 1.3 and the semimajor axis of the drainage ellipse (expression 1.2):

Substituting the results obtained into expression 1.1 we obtain,

2. Let's calculate the flow rates of the gas pipeline using the method of Borisov Yu.P.

Filtration resistance determined by formula 1.6:

To determine the daily flow rate, we multiply the result by the number of seconds in a day (86,400).

3. Let's calculate the flow rates of the gas pipeline using the Giger method.

Filtration resistance J take expression (1.7)

We determine the flow rate of the gas pipeline:

To determine the daily flow rate, we multiply the result by the number of seconds in a day (86,400).

4. Compare the results obtained:

5. Let us calculate the well flow rates for 20 values ​​of the length of the horizontal section in increments of 50 meters using the presented methods and construct a graphical dependence:

Figure 1.3 – Dependence of changes in well flow rate on the length of the horizontal section

Conclusions: Based on the results of calculating the predicted flow rate of a horizontal well using the methods of Joshi S.D., Borisov Yu.P., Giger for the geological and physical conditions of the PK 20 formation of the Yarainerskoye field, the following follows:

- with a slight difference (inflow shape in horizontal projection) analytical models the work of horizontal wells that penetrated a homogeneously anisotropic formation in the middle between the roof and the bottom, the difference in calculated flow rates is quite large;

- for the conditions of the PK 20 formation of the Yaraynerskoye field, graphical dependences of the predicted well flow rate on the length of the horizontal section were constructed; according to the results of the analysis, it follows that the optimal options will be in the interval L 1=150 m. Q 1=2620 m 3 /day up to L 2=400 m. Q 2=3230 m 3 /day;

- the obtained values ​​are the first approximate results of the selection optimal length horizontal section of the well, further justification is based on clarifying the predicted flow rates using digital reservoir models and recalculating the economics, based on the calculation results of which the most rational option will be selected.

Options Task No. 1

Control questions.

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

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

Flow definitions

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

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

Dynamics, statics and height of the water column

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

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

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

You can take a measurement using:

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

Determining pump performance

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

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

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

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

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

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

Simplified calculation

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

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

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

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

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

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

Specific flow rate

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

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

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

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

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

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

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

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

Real flow rate

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

DT= (Hf-Hst) * Doud, Where

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

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

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

Decrease in flow rate

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

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

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

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

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

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

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

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

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

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

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

F - flow area of ​​fountain pipes, m 2

d - diameter (internal) of fountain pipes, m.

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

During the operation of gas condensate wells, liquid hydrocarbons (gas condensate) are released from gas, which create a two-phase flow in the fountain pipes. To prevent the accumulation of liquid at the bottom and a decrease in flow rate, a gas condensate well must be operated with a flow rate no less than the minimum permissible, ensuring the removal of gas condensate to the surface. The value of this flow rate is determined by the empirical formula:

where M - molecular mass gas Then the pipe diameter:

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

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

e is the base of natural logarithms;

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

c g is the relative density of gas in air;

L - length of fountain pipes, m;

d - pipe diameter, m;

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

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

l - coefficient of hydraulic resistance;

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

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

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

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

1) Well temperature T is determined by the formula:

T = N? G, (19)

where H is the well depth, m

G - geothermal gradient.

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

where Ppl - reservoir pressure, MPa

P cr - critical pressure, MPa

For methane P cr = 4.48 MPa

where T cr - critical temperature, TO

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

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

1) Diameter of pump-compressor...

• - daily gas volume q, nm 3 / day,
• - initial and final pressure in the gas pipeline P 1 and P 2, MPa;
• - initial and final temperatures t 1 and t 2, o C;
• - concentration of fresh methanol C1, wt.%

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

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

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

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

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

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

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

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

C 1 - weight concentration introduced methanol,%;

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

From formula 24 it follows that in order to determine the amount of methanol to saturate the liquid phase, it is necessary to know the gas humidity and the concentration of methanol at two points: at the beginning and at the end of the section where hydrate formation is possible.

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

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

DW = W 2 - W 1 (25)

Let's determine humidity using the formula:

where P is gas pressure, MPa;

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

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

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

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

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

DT = T - T 2, (28)

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

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

The amount of methanol (q g, kg/1000 m3) required to saturate the gaseous medium is determined by the formula:

q g = k m C 2, (29)

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

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

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

The formula for calculating the flow rate of an oil well is a necessary thing in modern world. All enterprises that extract petroleum products must calculate the flow rate for their offspring. Many people use the formula of Dupuis, a French engineer who devoted many years to the study of movement. groundwater. Its formula will help you easily understand whether the performance of a particular source is worth the money for well equipment.

What is the flow rate of an oil well?

Flow rate is the volume of liquid supplied through a well in a certain unit of time. Many people neglect its 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.

Flow rate is often referred to as pump performance. But this characteristic does not fit the definition a little, since all the properties of the pump have their own errors. And a certain volume of liquids and gases is sometimes radically different from what was declared.

Initially, this indicator must be calculated to select pumping equipment. When you know the productivity of the area, you can immediately exclude several unsuitable units from the selected 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 the wrong one pumping unit due to missed calculations, it may bring losses to the company rather than the expected profit from the well.

It is required to be calculated at all types of oil production enterprises - even the flow rates of nearby wells may differ too much from the new one. Most often, the huge difference lies in the values ​​​​substituted into the calculation formulas. For example, the permeability of a formation can differ significantly a kilometer underground. With poor permeability, the indicator will be lower, which means 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 have been created professional equipment, which determines all the necessary parameters for drilling a new well, but only the result seen after this process can 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 spent almost his entire life studying this material and deducing the formula shows the result much more accurately, because it contains much more data for calculation.

Formula for calculating well production

For calculations using the standard formula - D = 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 groundwater to the first layers of soil, and the dynamic level is absolute value, obtained by measuring the water level after pumping.

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

However, this formula and the optimal flow rate indicator itself are not used in every field. Due to mechanical and physical pressure on the formation, collapse of part of the internal walls of oil wells may occur. 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 cannot accurately obtain correct result- there will be a big error. In order to avoid incorrect calculations and direct yourself to obtain a more accurate result, use the Dupuis formula, in which it is necessary 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 oil field produce. 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 – coefficient that determines the hydraulic conductivity property of an oil reservoir;

B – coefficient of expansion by volume;

Pi – Number P = 3.14…;

Rk – circuit power radius;

Rc – bit radius of the well according to the distance to the exposed formation.

The second formula looks like this:

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

This formula for the actual productivity of a field is now used by absolutely all companies that drill oil wells. Only two variables are changed in it:

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 of formations containing minerals is used. It involves the mechanical formation of cracks in productive rock.

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

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

To increase the performance and flow rate, the thermal acid treatment method can also be used. Using several types of solutions, such as acidic liquid, the elements of the deposit are cleaned from tar deposits, salt and other chemical components that interfere with the high-quality and effective passage of the mined rock.

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

Flow rate calculations should be carried out periodically to formulate a strategy for the vector development of an oil producing enterprise.

Calculation of well productivity