Device and method for simulation of well structure and operating performances

FIELD: oil-and-gas industry.

SUBSTANCE: evaluation of fluid inflow fraction from every productive zone of multi-zone productive well comprises determination of pressure at wellhead. Integrated indicator curve (IPR1) is obtained to describe the relationship between pressure and fluid yield from first productive zone and integrated indicator curve (IPR2) is obtained to describe the relationship between pressure and fluid yield from second productive zone. Value for integrated indicator curve at the point of mixing (IPRm) is obtained with the help of IPR1 and IPR2. Initial fluid inflow fraction from first productive zone at mixing points and initial fluid inflow fraction from second productive zone are defined. First total curve of outflow (TPR1) is obtained describing the relationship between fluid pressure and yield, fluid flowing from mixing point to wellhead. First portion of fluid inflow from first productive zone (Q11) and first portion of fluid inflow from second productive zone (Q21) are defined at mixing point with the help of IPRm and TPR1. Machine-readable carrier accessible for processor comprise program including instructions for above listed jobs.

EFFECT: more efficient evaluation of the portion of influx from productive seam.

20 cl, 5 dwg

 

The technical field to which the invention relates.

The present invention relates generally to the simulation of the design and operational characteristics of the wells, and monitoring wells.

The level of technology

Drilling wells in subterranean formations is carried out with the purpose of production of hydrocarbons (oil and gas). The penetration of some of these wells is vertical or close to vertical through more than one collector/one productive zone. The usual practice has been the drilling of deviated and horizontal wells, where the well intersects the productive zone is predominantly in the horizontal direction, that is, mainly through the longitudinal profile of the reservoir. In many wells the production of hydrocarbons is carried out from two or more productive areas (also referred to as headers). To regulate the flow of fluid from each production zone in the well is installed shut-off and control valves. In such multi-zone wells (production or injection fluids from different productive zones are mixed in one or more points on the path of their movement in the well. The flow of the mixture of fluids delivered to the mouth of the well on a tubing string of pipe. The parameters of this thread facing surface, depend on the properties or characteristics of the reservoir (such as permeability, PLA is preset pressure and temperature and so on), the configuration of the path of flow of the fluid and used in this way equipment (e.g., diameter tubing, the dimensions of the annular space, used for the passage of fluid, a gravel filter, fitting and shut-off and control valves, temperature distribution and pressure in the well, etc). Prior to the design and completion of multi-zone wells it is often desirable to perform simulations of fluid flow from each production zone. In determining the share of the flow of fluids coming from different areas, through the methods and models used in the industry, are often not taken into account some of the above characteristics. The present invention offers an improved method and model to determine the percentage of fluid flow from each productive zone multi-zone production well.

Disclosure of inventions

As one of the objects of the present invention proposes a method of estimating the proportion of fluid flow from each productive zone multi-zone production well, comprising: detecting the pressure at the wellhead, the first integrated indicator curve (characteristic) (IPR1)showing the relationship between pressure and flow rate of the fluid from the first production zone and the second integrated the Anna indicator curve (IPR2), showing the relationship between pressure and flow rate of the fluid from the second production zone, obtaining values for the integrated indicator of the curve at the point of mixing (IPRc) using IPR1 and IPR2, the determination at the point of initial mixing proportion of fluid flow from the first production zone and the initial share of the inflow of fluid from the second production zone, the first total curve (characteristic) outflow (TPR1), showing the relationship between pressure and total flow rate of the fluid moving from the point of mixing in the direction of the mouth, and the definition at the point of mixing with IPRc and TPR1 first fraction of fluid flow from the first production zone (Q11) and the first fraction of fluid flow from the second production zone (Q21).

For a better understanding of the following detailed description of the invention, specialists in this area quite extensively covered examples of the most important distinguishing characteristics relevant to determining the percentage of fluid flow from each productive zone multi-zone production well. There are, of course, other distinctive signs, are described below and are the subject of the invention presented in the claims.

Brief description of drawings

For a better understanding of the systems and methods of monitoring and control of production wells, are presented in the detailed description and the claims, below the attached drawings, in which identical elements have the same reference numbers. The drawings show:

figure 1 - schematic representation of the example system multi-zone production well designed for the extraction of fluid from multiple productive zones and the corresponding present invention,

figure 2 is a functional diagram illustrating the mixing of fluids from different productive zones downhole system, shown in figure 1,

figure 3 - functional diagram showing the nodes on the path of fluid flow from each productive zone to the point of mixing and from the point of mixing to the surface in the system multi-zone production well, for example presented in figure 2,

4 is a block diagram illustrating the sequence of operations in the method of determining the proportion of fluid flow from each productive zone multi-zone production well, for example, presented in figure 3,

figure 5 - examples of curves of pressure from the flow rate or mass flow rate, which can be used in the way presented in figure 4.

Detailed description of the invention

Figure 1 shows the schematic of the system multi-zone production well 100 shown as an example. The system 100 includes a bore 150 drilled in the reservoir 15 and giving products in the form of reservoir fluids a and 156b, coming from two shown for illustration productive zones - 152a, respectively (upper producing zone or the upper reservoir) and 152b (lower producing zone or the lower reservoir). Well 150-lined casing 157 containing the perforations a adjacent to the upper productive zone 152a, and the sprocket holes 154b, adjacent to the lower productive area 152b. Over the perforations a lower production zone is located packer 164, which can be extracted and which divides the flow of fluid from the lower production zone 152b and the upper productive zone 152a. In the immediate vicinity of the perforation holes 154b can be installed strainer 159b, preventing the penetration of solid particles, such as sand, into the hole 150 of the lower production zone 152b. Similarly in the immediate vicinity of the perforations a can be installed strainer 159b, preventing the penetration of solid particles, such as sand, into the hole 150 of the upper productive zone 152a.

Wireline fluid 156b from the lower production zone 152b enters the annular space a bore 150 through the perforations 154b and Elevator column 153 through the device 167 for flow control. The valve 167 flow control can represent irculation valve type sliding coupling with a remote control or other suitable valve or fitting, designed to regulate the flow of fluid from the annular space a in the Elevator column 153. Wireline fluid a from the upper productive zone 152a enters the annular space 151b (above the packer 164) through the perforations a. Wireline fluid a enters the Elevator column 153 at point 170, referred to in this description of the point of mixing. Fluids a and 156b are mixed at the point of mixing. Adjustable device 144 control the flow of fluid (upper regulating valve), United with the Elevator column 153 above the point of mixing 170 may be used to regulate the flow of fluid moving from the point of mixing 170 to the mouth of the bore 150. Packer 165 above the point of mixing 170 prevents the surface of the fluid from the annular space 151b. Installed on the surface of the equipment wellhead 150 regulates the pressure of the outgoing fluid, keeping it at the required level. System 100 may include various sensors 145, which provide information about some of downhole parameters of interest.

Figure 2 presents a functional diagram 200 showing the flow of fluid a from the upper productive zone 152a and the flow of fluid 156b from the lower production zone 152b (Fig 1). Fluid a from the upper productive zone, or the first collector, 152a moves to the point of confusion 210 through the ring of the second space (which may also include piping for fluid) 211 and valve flow control or fitting 212. The valve 212 flow control can have any number of adjustment positions, each of which determines the degree of opening of the valve. Fluid 156b from the lower production zone or the second header 152b is moving to the point of confusion 210 through discharge line 213 and the valve 214 flow control, which can be set at any degree of opening. The flow of the mixture 215 fluid moves from the point of mixing of 210 to 230 mouth of the well through the system 218 tubing (tubing).

Figure 3 presents a functional diagram showing examples of nodes on the path of fluid flow from each productive zone to the mouth of 230 wells and then into the storage tank 380. Wireline fluid a from the upper productive zone, or the first reservoir (Res-1), 152a passes through the mesh filter in the first node 312 in the well and moves towards the mouth on the way 314 in the annular space to the second node 316 until contact with the downhole valve or fitting 318. In one embodiment of the invention, the node 312 can choose a center punch hole 159a (1) or any other suitable point in the well. The second node 316 may be a point located in the immediate vicinity of the entrance of fluid into the valve 318. Coming out of the valve 318, fluid a comes to the point of mixing 340 where it mixes with the fluid 156b of the lower productive h is HN 152b. The pressure at the node 312 represents the pressure in the well and has a reference designation Pwf_1, and the pressure at node 316 (after the path 314 in the annular space and to the fitting 318) denoted by Pchk1_up. The pressure PC at the point of mixing 340 is equal to the pressure Pchk1_dn after valve 318. Wireline fluid 156b of the second production zone, or the second header (Res-2), 152b passes through the mesh filter in the first node 322 in the well and moves towards the mouth on the way 324 in the annular space to the second node 326 until contact with the downhole valve or fitting 328. Pressure Pwf_2 node 322 is a downhole pressure near the perforations in the lower productive area 152b. In one embodiment of the invention, the node 322 can choose a center punch hole 159b, or any other suitable point in the well. The second node 326 may be the entry point of the fluid 156b in the valve 328. Coming out of the valve 328, the fluid enters the third node 330, and then mixed after passing through the tubing 332 - fluid a from the first production zone 152a at the point of mixing 340. The pressure at the node 322 represents the pressure in the well and has a reference designation Pwf_2, the pressure at the node 326 denoted by Pchk2_up, the pressure at the node 330 denoted by Pchk2_down and pressure at the point of mixing denoted by Pchk1_down, or RS. The flow of the mixture of fluids moving from site/the glasses mixing 340 to 370 mouth of the well through a system of tubing 342. To regulate the flow of fluid emerging from the well to the surface, can be used terrestrial valve or fitting 372. The pressure at the wellhead 370 wells can be adjusted and marked through the Pwh. From ground fitting 372 fluid flows through flow line 376 and gazoochistnoe separator 378 in the reservoir 380 for storage. The pressure in the node 373 between ground fitting 372 and discharge line 376 denoted by Pfl, node 377 between the discharge line 376 and the separator 378 - via Psp and node 379 between the separator 378 and reservoir 380 for storage - via Pst. Figure 2 and 3 shows a flowsheet for a downhole system with two productive zones. The following methods are equally applicable to downhole systems containing more than two productive zones.

To determine the percentage of fluid flow from each productive zone in one embodiment, it is possible to use the pressure PC at the point of mixing 340 as a reference value, as described in more detail below with reference to figure 4 and 5. The purpose of the present invention can be achieved by using any suitable method for determining the point of mixing 340, including the method described below. The value of the reservoir pressure is usually known and is taken from the data available for previous years, or in wells previously drilled in the e layer. Pressure Pwf_1 node 312 is a downhole pressure. If Pwf_1 more reservoir pressure, or equal to, the inflow of fluid into the well 150 is not happening. For the first set value Pwf_1 (less than formation pressure Pres_1) flow, or mass flow rate, Q1 fluid corresponding to the collector 152a, can be calculated from the equation Q1=PI [Pres_1 - Pwf_1], where PI is a well - known factor productivity for the path of the fluid, a Pres_1 can be taken from previously obtained data. Pressure Pchk1_up can be calculated from equation Pchk1_up=Pwf_1 - Q1/PI, where Pwf_1 and Q1 are taken from the calculation above. Similarly, the pressure PC at the point of mixing can be calculated using known values of Q1 and the above calculated pressure Pchk_1 as the input pressure. Thus, using the above method you can calculate the pressure PC at the point of mixing for any given pressure at the wellhead and any of the adjustment provisions of the fittings on the path of flow of the fluid. Therefore, each value of the pressure at the wellhead are mapped to values of RS and Q for each production zone.

There is a need in the simulation mode, the flow of fluid in the system multi-zone production well prior to the execution of the design and completion of such wells. One of the problems solved in esteem the invention, is a method of numerical simulation of the mode of flow of fluid for each productive zone for a given configuration of wells. In one embodiment, in the computational model uses a method of modeling of thermal processes in the borehole as a thermodynamic system with the aim of playback of motion of the fluid streams which are separated by paths, similarly to that shown in figure 2. In one embodiment, the method presented in the present description, use the simulation mode changes in pressure, volume and temperature (PVT characteristics) for each collector. Reservoir characteristics such as pressure, temperature, permeability, density and viscosity of the fluid, etc. will vary from well to well. To determine the mode changes PVT characteristics of the simulated collector, you can use any suitable method, including, without agrarias this method, known as "correlation properties of the oil system and including correlation Standings (Standing), correlation of Lasater (Lasater), correlation of Vazquez and Beggs (Vasquez and Beggs), etc. and the correlation of the z-factor, for example the correlation of the z-factor Bril and Beggs (Brill and Beggs) or Hall and Arbore (Hall and Yarborough). The flow of fluid in the borehole is often multiphase and may contain gas, especially in the case of the, when the pressure in the well below the point of degassing. A direct solution for multiphase flow in the wellbore with a complex profile, such as shown in figure 2, can take a long time. One aspect of the present invention is a method using nodal analysis, referred to in this description of the "method integrated indicator curve (characteristic) (IPR)", to determine the percentage of fluid flow from each productive zone in the system multi-zone wells. One of the aspects underlying this method is the assumption that there is a balance of pressure in the system, that is about balancing the pressure at the point of mixing 340 (3) in steady state conditions. This assumption allows us to obtain an integrated model combining the indicator curve for fluid coming from a particular production zone, with the characteristics of the flow path, and the characteristics of devices, flow control and other devices in the flow path, and describing the pressure ratio and flow rate (or mass flow rate)corresponding to the point of mixing 340. Curve outflow (also called in the industry "lift curve " and "characteristic of the tubing string, and in this description referred to as "TPR"), showing the flow of fluid emerging from the point of mixing or upper adjusting what about the valve and moving back to the wellhead, can be obtained by using a suitable TPR model related to the characteristics of a tubing string for single-phase/multi-phase flow, including, but not limited to, a modified model Hagedorn-brown (Hagedorn-Brown). Elevator curve shows the ratio between the pressure at a given point and the total flow rate or mass flow. Using these curves (integrated indicator and the Elevator), you can predict the flow rate, the limits of the production zones and the downhole pressure, related to the point of mixing, taken as a bridle in the process of finding solutions.

4 shows a block diagram of an iterative process 400 that can be used to determine the portions of the flow of fluids (limits production zones) system as an example, dual-zone wells, similar to the one shown in figure 2 and 3. In the process 400 receives an integrated indicator IPR curve (i.e. the relationship between pressure and flow rate) for a given pressure at the wellhead and each productive zone (step 410). In one embodiment, upon receiving an integrated indicator curve/ratio IPR recorded IPR for multiple devices control the flow and tubing located in the flow path of the fluid, up to the point of mixing 340. For example, when receiving integrated indicatores curve/ratio IPR 350 for the path 352 fluid flow, corresponding to the first manifold 152a, are accounted for IPR path 314 in the annular space and for downhole valve 318 (Fig 3). Similarly, when receiving an integrated indicator curve/ratio IPR 360 for the path 362 corresponding to the second manifold, accounted for IPR path 324 flow in the tubing and downhole valve 328 (Fig 3). Figure 5 presents a plot of the pressure PC from the flow rate, relative to the system shown in figure 3. The value of the pressure PC at the point of confusion here pending on the vertical axis and the values of the flow rate Q along the horizontal. Curve 510 represents an example of the integrated indicator IPR curve corresponding to the path 352 flow and curve 520 represents an example of the integrated indicator IPR curve corresponding to the path 362 stream. Integrated indicator IPR curves 510 and 520 for these productive zones can be combined to obtain an integrated curve for the total flow rate (IPRc), the corresponding point of mixing 340. Curve 530 represents such joint integrated indicator curve IPRc system, an example of which is depicted in figure 3 (step 412). Another element of the source data used in nodal analysis presented in the present description, is the characteristic curve of tubing string (Elevator curve) for flow of the mixture of fluid is. Elevator curve shows the relationship between pressure and flow, or mass flow, fluid. To calculate the values to build the lift curve can be set on the basis of previously obtained data, the estimated value characteristics in reservoir conditions (e.g. temperature, density, viscosity, gas-oil ratio in the dissolved gas, water etc) for a mixture of fluids from each production zone (step 414). Then these expected values, you can build a lifting curve corresponding to the point of mixing (or upper adjusting valve), using any suitable model, such as Hagedorn-brown, Erkezeskor (Orkiszewski), Aziz (Aziz) and so on (step 416). Curve 550 is an example of a lift curve corresponding to the point of mixing 340 for a system with two productive zones, shown in figure 3.

You can then determine the fraction of fluid flow from each production zone (first iteration)using nodal analysis applied to the point of mixing or upper adjusting valve (step 418). The proportion of flow can be determined by lifting the curve 550) and the joint integrated indicator curve IPRc 530 corresponding to the point of mixing, as described below. The point of intersection of 570 determines the pressure and total flow, or the flow of the mixture, Qc fluids corresponding to the point of mixing 340, originally selected or expected values of pressure at the wellhead and originally intended share of the inflow of fluids from each production zone. As a rule, originally proposed in the share of inflow can be, for example, 50% for each productive zone or have a different value estimated in accordance with the adjustment provisions of the valves for each production zone. The intersection point of the line 552, corresponding to the pressure at the point of mixing, and integrated IPR curve 510 for the first production zone, determines the amount of flow Q11 from the first production zone 152a. Similarly, the point of intersection of the 574 line 552 and integrated IPR curve for the second production zone, determines the amount of inflow Q21 from the second production zone 152b. Step 420 provides the pressure P1 and limits production Q11 and Q21 after the first iteration the node (point of confusion). As one of the most important parameters at the point of mixing/node often considered temperature. In one embodiment, the model presented in the present description, the temperature at the point of mixing is used as control parameter for the prediction of flow from different productive zones. In one embodiment, the temperature T1 at the point of mixing can be determined using any suitable thermal model,such as model Hasan-Kabir (Hasan-Kabir), etc.

You can then use the limits production Q11 and Q21 (rule of mixture - step 422) and characteristics in formation conditions (temperature, density, viscosity, free gas, water cut, as free gas, gas factor, and so on)related to the mixture Qln Q2 ((n-1)-e values)) (step 424), to obtain (n-1)-th lift curve (step 426). Using (n-1)-th Elevator curve and obtained previously integrated indicator IPR curves 510 and 520 (5) (step 428), the calculated joint integrated indicator curve IPRc (step 430) and then following the above nodal analysis (step 432), define (n-1)-th values of the pressure and the fraction of inflow of fluid from the first production zone (Q12) and the second production zone (Q22) with temperature Tn-1at the point of mixing (step 440). This iterative process can be continued to obtain the n-th values of the pressure and the proportion of the inflow of fluids from each productive zone with temperature Tna n-th lift curve (steps 442, 444 and 445).

The above-described iterative process can be continued as long as the difference between the values of temperature at the point of mixing for two consecutive iterations will not be in a given range, or within the tolerance (step 450). If this is not the case, an iterative process may be continued (step 452). For example, if the difference between the values of the temperature calculated is suspended in n-th and (n-1)-th iteration, is within the specified range, then the proportion of the flow of fluids that are defined after the n-th iteration for each productive zone, can be considered as the resultant values for the nodal model presented in the present description (step 450). If this temperature difference is outside the specified range, the process may be continued as described above (step 452). Total value of shares inflows from different productive zones can then be used to design the well or any other purpose. Although in the above-described iterative process to determine the fraction of flow from each productive zone uses the values defined integrated indicator IPR curve and corresponding to each path of the extracted fluid, the purpose of the present invention can be achieved using any other dependencies of the characteristics of the influent. As a control option, you can also use pressure or any other parameter. It should be noted that the methods presented in this description are equally applicable to systems of wells containing more than two productive zones. As a node used in the process of solving the problem in the framework of the present invention can be any point on the flow path of the mixture of fluids. In addition, the terms used are "subject to the practical curve tubing string (TPR)", the Elevator curve and curve outflow" are used interchangeably.

The object of the invention is also machine-readable medium accessible to the processor and containing a program, which includes the following commands, executed by the processor: command to set the pressure at the wellhead; instructions for receiving the first integrated indicator curve (IPR1), representing the ratio between the pressure at the point of mixing and the flow rate of the fluid from the first production zone and the second integrated indicator curve (IPR2), representing the ratio between the pressure at the point of mixing and the flow rate of the fluid from the second production zone; command to get the value for the integrated indicator of the curve at the point of mixing (IPRc) using IPR1 and IPR2; command to determine at the point of initial mixing proportion of fluid flow from the first production zone and the initial share of the inflow of fluid from the second production zone; instructions for obtaining a first total outflow curve (TPR1) for the path of fluid moving from a point of confusion towards the mouth, with certain initial shares of fluid flow; and commands for determining at the point of mixing with IPRc and TPR1 first fraction of fluid flow from the first production zone (Q11) and the first fraction of fluid flow from the second production zone (Q21).

In private embodiments, machine-readable medium mo the et also contain commands to retrieve the second total outflow curve (TPR2) through Q11 and Q21; and command to determine the second fraction of the flow of fluid from the first production zone (Q12) and the second fraction of the flow of fluid from the second production zone (Q22) with IPRc and TPR2. The program can also enable the team to continue to receive the total outflow curve using only that certain shares of fluid flow from the first and second productive zones and determine the portions of the inflow of fluids from the first and second productive zones with IPRc up to get interesting option that meets a given criterion. The parameter of interest may be a temperature, and the program then includes commands for determining the temperature at the point of mixing using thermal model. The program may also include commands to retrieve TPR1 using Energobalance model. In this application Energobalance model includes the use of at least one parameter selected from the group comprising pressure, temperature, density of fluid, permeability, viscosity, water cut, gas-oil ratio and quality of free gas. The initial proportion of the fluid flowing into the well from the first and second productive zones are determined by adjusting the positions of the valves for the first and second productive zones. Commands to retrieve the first integrated indicator curve IPR1 can turn to the team to determine the range of values of pressure at the point of mixing, the corresponding range of values of the flow rate determined by the flow from the first production zone to the point of mixing and depending on the equipment located in the flow path between the first productive area and a point of confusion.

Although the invention is illustrated in the present description of a specific implementation options and methods that are experts in this field will be obvious possibility of different changes. It is implied that all appropriate changes are within the scope of the invention covered by the attached claims, considering the submitted disclosure.

1. The method of estimating the proportion of fluid flow from each productive zone multi-zone production well, including:
determination of the pressure at the wellhead;
obtaining an integrated indicator curve (IPR1)showing the relationship between pressure and flow rate of the fluid from the first production zone, and integrated indicator curve (IPR2), showing the relationship between pressure and flow rate of the fluid from the second production zone;
obtaining values for the integrated indicator of the curve at the point of mixing (IPRc) using IPR1 and IPR2;
the definition at the point of initial mixing proportion of fluid flow from the first production zone and the initial share of the inflow of fluid from the second production zone;
obtaining p is pout total outflow curve (TPR1), showing the relationship between pressure and flow rate of fluid moving from the point of mixing in the direction of the mouth;
the definition at the point of mixing with IPRc and TPR1 first fraction of fluid flow from the first production zone (Q11) and the first fraction of fluid flow from the second production zone (Q21).

2. The method according to claim 1, including:
a second total outflow curve (TPR2) through Q11 and Q21;
the definition of the second share of the inflow of fluid from the first production zone (Q12) and the second fraction of the flow of fluid from the second production zone (Q22) with IPRc and TPR2.

3. The method according to claim 1, further including:
obtaining a new curve outflow using only that certain shares of fluid flow from the first and second productive areas;
definition share of the inflow of fluids from the first and second productive zones using the new curve outflow and IPRc up to receive the necessary parameter that meet a specified criteria.

4. The method according to claim 3, in which the parameter of interest is the temperature at a given point in the flow path of the fluid, and the predetermined criterion is that the difference between the temperature values for successive operations of determining the shares of fluid flow from the first and second productive zones were within the specified range.

5. The method according to claim 3, in which the parameter of interest is the pressure in a given the th point on the flow path of the fluid, as specified criterion is that the difference between the pressures for sequential operations of determining the shares of fluid flow from the first and second productive zones were within the specified range.

6. The method according to claim 4, comprising using a thermal model to determine the temperature.

7. The method according to claim 1, in which for getting TPR1 used Energobalance model, which uses at least one parameter from the group comprising pressure, temperature, density of fluid, permeability, viscosity, water cut, gas-oil ratio and quality of free gas.

8. The method according to claim 1, in which coming to the point of mixing the initial portion of fluid flow from the first production zone and the initial share of the inflow of fluid from the second production zone are determined by adjusting the positions of the control devices stream corresponding to the first and second production zones.

9. The method according to claim 1, in which receiving IPR1 includes determining a set of values of pressure at the point of mixing, corresponding to a series of values of the flow rate determined by the flow from the first production zone to the point of mixing and depending on the equipment located in the flow path between the first productive area and a point of confusion.

10. The method according to claim 9 in which the said equipment comprises at least one of the following: ø user, the tubing and the annular space in the well.

11. Machine-readable medium accessible to the processor and containing a program, which includes the following commands, executed by the processor:
command to set the pressure at the wellhead;
commands to retrieve the first integrated indicator curve (IPR1), representing the ratio between the pressure at the point of mixing and the flow rate of the fluid from the first production zone and the second integrated indicator curve (IPR2), representing the ratio between the pressure at the point of mixing and the flow rate of the fluid from the second production zone;
commands to obtain the values for the integrated indicator of the curve at the point of mixing (IPRc) using IPR1 and IPR2;
command to determine at the point of initial mixing proportion of fluid flow from the first production zone and the initial share of the inflow of fluid from the second production zone;
commands to retrieve the first total outflow curve (TPR1) for the path of fluid moving from a point of confusion towards the mouth, with certain initial shares of fluid flow; and
command to determine at the point of mixing with IPRc and TPR1 first fraction of fluid flow from the first production zone (Q11) and the first fraction of fluid flow from the second production zone (Q21).

12. Machine-readable medium according to claim 11, containing:
commands to the floor of the treatment of the second total outflow curve (TPR2) through Q11 and Q21; and
command to determine the second fraction of the flow of fluid from the first production zone (Q12) and the second fraction of the flow of fluid from the second production zone (Q22) with IPRc and TPR2.

13. Machine-readable medium according to claim 11, in which the program includes commands to continue receiving total outflow curve using only that certain shares of fluid flow from the first and second productive zones and determine the portions of the inflow of fluids from the first and second productive zones with IPRc up to receive the necessary parameter that meet a specified criteria.

14. A machine-readable medium of clause 13, where the parameter of interest is the temperature.

15. Machine-readable media 14 in which the program includes commands to determine the temperature at the point of mixing using thermal model.

16. Machine-readable medium according to claim 11, in which the program includes commands to retrieve TPR1 using Energobalance model.

17. Machine-readable medium according to clause 16, where the use Energobalance model includes the use of at least one parameter selected from the group comprising pressure, temperature, density of fluid, permeability, viscosity, water cut, gas-oil ratio and quality of free gas.

18. Machine-readable medium according to claim 11, where the initial proportion of fluid postupayushie what about in the borehole from the first and second productive zones, determined by adjusting the positions of the valves for the first and second productive zones.

19. Machine-readable medium according to claim 11, in which commands to retrieve the first integrated indicator curve IPR1 include commands to determine the number of values of pressure at the point of mixing, corresponding to a series of values of the flow rate determined by the flow from the first production zone to the point of mixing and depending on the equipment located in the flow path between the first productive area and a point of confusion.

20. Machine-readable medium according to claim 19, where the said equipment comprises at least one of the following: device flow control, tubing and the annular space in the borehole.



 

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4 dwg

FIELD: oil and gas industry.

SUBSTANCE: in addition, analysis of isotopic composition of carbon of sum of hydrocarbons C2-C6 is performed and limits of values of isotopic composition of carbon, methane and isotopic composition of carbon of sum of hydrocarbons C2-C6 for reference horizons are determined. Tables and/or graphs represent ranges of values of isotopic composition of gases from reference horizons and gases are represented from inter-string space of wells or drilling fluid; as per the degree of similarity or coincidence of the above ranges of those values (or individual points) there evaluated is nature of investigated inter-string gas shows.

EFFECT: improving reliability in determination of nature of inter-string gas shows.

1 ex, 2 tbl, 1 dwg

FIELD: oil and gas industry.

SUBSTANCE: method for assessing a gas-recovery ratio for the volume drained by at least one productive gas well comprises: calibration of the changes of an isotopic composition of at least one component of the natural gas recovered from the gas well with the gas-recovery ratio gain. Sampling of the natural gas recovered from the production well, and analysis of the sample for preparing the isotopic composition of the component of the natural gas. Use of the previous calibration and the specific isotopic composition for assessing the gas-recovery ratio for the volume drained by the gas well. Use of the assessed gas-recovery ratio and total volume of the natural gas produced from the gas well to determine the volume drained by the gas well.

EFFECT: amended assessment of the gas-recovery ratio which is based on the calibrated relation of the changes in the isotopic composition of one or more components of the produced gas and the gas-recovery ratio for the volume drained by the productive gas well.

3 dwg, 9 cl

FIELD: oil and gas industry.

SUBSTANCE: in process of sampling, values of specific electric conductivity are measured on liquid arriving into a sampling chamber. At the same time measured values of specific electric conductivity and readings of pressure and temperature sensors are recorded with a surface receiving-processing station, and to form a channel of communication with it and to provide for sampler lowering and lifting, an armoured geophysical cable is used, which is withdrawn from a drilling string via a sealing device. Besides, before opening of a potentially producing bed, the sampler at the vibration and impact safe distance from a bit is fixed on the cable in the above-packer space of the above-bit packering unit, providing for direct circulation of the mud. And after opening the sampling operation is carried out by means of multiple sampling and remote express-analysis of fluid composition in every sample according to specific electric conductivity, for this purpose the chamber by means of piston displacement is released from the first sample with fluid discharge into the above-packer space. Then it is put into the initial working condition, and similarly to the first sample taking, further sampling is carried out, until extremum of specific electric conductivity values is achieved, and on the basis of this parameter, a decision is made to lift the last sample from the well or to continue drilling process, and bed parameters are identified on the basis of pressure, temperature sensor readings, and by the value and speed of increments of specific electric conductivity.

EFFECT: increased efficiency of sampling of oil reservoirs opened with drilling, also in abnormal boreholes.

8 cl, 6 dwg

FIELD: oil and gas industry.

SUBSTANCE: method includes taking of a downhole sample by a sampler and its transportation to the surface. At that at the surface the sealed sampled chamber is set in different positions under vertical angles less than 180 degrees and measurements of the fluid are made by primary detectors installed inside the chamber on the surface of a dividing piston; then content of the downhole sample is analysed and calculated.

EFFECT: checkout of parameters for the total downhole sample, acquisition of reliable data on the fluid, creation of cost-effective control method.

7 dwg

FIELD: oil and gas industry.

SUBSTANCE: method and tool that implements the method involving the measurement of viscosities and flow rates of fluid media of the formation and obtainment of the ratio of relative permeabilities of formation fluid media and formation wetting ability using those viscosities and flow rates of the formation fluid media.

EFFECT: testing of bottom-hole formation for determination of relative permeability under bottom-hole conditions.

18 cl, 5 dwg

FIELD: oil and gas industry.

SUBSTANCE: invention relates to the method and system for obtaining characteristics of the composition gradients and fluid medium properties of the involved header, and analysis of the header properties based on such gradients.

EFFECT: improvement of the device.

20 cl, 3 dwg

FIELD: oil and gas industry.

SUBSTANCE: method lies in continuous measurement of total consumption parameters of the well pad: mass flow rate Ml, volumetric gas discharge Qg, volumetric water cut Wl and coefficient Kg/v=0,01ΔQgΔWl, where Qg and ΔWl are differences of the previous and current average numerical values of total consumption of the well pad respectively for free volumetric gas discharge Q¯g and volumetric water cut W¯l. When the value of Kg/v is outside the preset points of ±ΔKg/v, parameters Mli, volumetric gas discharge Qgi and water cut Wli are calculated for each well respectively. The value of Kg/vi=Qgi100Wli coefficient is calculated. Values of Kg/vi coefficients are compared for each well with the current value of Kg/v. The well with variable value of volumetric water cut Wli is identified against minimum difference attribute between the value of Kg/vi of one of wells in the well pad and the value of Kg/v coefficient.

EFFECT: probable identification of the well with variable volumetric water cut of the well pad directly in measurement process of the oil well flow rate.

2 cl, 1 dwg

FIELD: physics; geophysics.

SUBSTANCE: invention relates to oil and gas well survey and specifically to determining the movement profile of fluids into a well from producing layers of multilayer reservoirs. When using the method, there is no need for thermal equilibrium time between well cleanout and perforation, and there is no need to measure the rate of change of temperature in the well before perforation thereof. The technical result is achieved by cooling the bottom-hole area before well perforation; performing well perforation and measuring flow temperature in the well over each perforation area; determining the flow rate of each producing layer, taking into account the thickness of the perforation area and using temperature measurement results obtained in the interval between the end of the initial extraction stage, characterised by the strong effect of the volume of the well and rapid change of flow temperature n the well, and the time, at the beginning of which the cooling effect of the bottom-hole area of the well on the temperature measurement becomes negligible.

EFFECT: high accuracy and reliability of determining the flow profile in a multi-pay well at the initial extraction stage, immediately after well perforation.

8 cl, 10 dwg

FIELD: oil and gas industry.

SUBSTANCE: the method is realized in two stages. At the first stage to the lower horizontal producer a flow string is run in to the beginning of a slotted filter. A heat insulated filter is set in the upper horizontal injector above the slotted filter. In the upper horizontal injector temperature tests are made in the interval from the well head up to the packer. Steam is injected to the lower horizontal producer and temperature tests are made simultaneously in the upper horizontal injector. Upon completion of steam injection to the lower well the final temperature test is made in the upper well. At the second stage fresh water is injected to the upper horizontal injector and a heat insulated flow string is run in with a thermal packer and shank. The packer is set before the slotted filter and control temperature test is made in tubular annulus in the interval from the well head up to the packer. Steam is injected to the upper horizontal injector though the heat insulated flow string, through the packer and shank to the beginning of the slotted filter. At that, periodically, upon commencement of injection, temperature tests are made in tubular annulus in the interval from the well head up to the packer. Upon completion of steam injection the final temperature test is performed in the upper horizontal injector. When required, tests in the lower producer and operational procedures for the wells are interchanged.

EFFECT: improving authenticity of the obtained results during identification of intervals with cross flows behind the casing for wells operated in deposits of viscous and superviscous oil.

FIELD: oil and gas industry.

SUBSTANCE: to the well a package is run in that is equipped bottom-up from a funnel, a packer placed in the interval between the productive strata, a string of pipe with low heat conductivity with self-contained well instruments placed at external surface, an ejector for wells surveys and a casing string; the packer is set, the process is withheld in order to recover temperature conditions, water is pumped along the casing string through the ejector for well surveys and annular space, bottomhole pressure is decreased under the packer, inflow is induced from the lower productive stratum, the packer is broken, the package is lifted and interpretation is made for readings of the self-contained well instruments, at change of less than 0.4 of degree recorded by the self-contained well instruments conclusion is made on non-availability of circulation behind the string, at change of more than 0.4 of degree conclusion is made on availability of circulation behind the string.

EFFECT: determination of the behind-the-casing flows at downward flow of fluid behind the well.

1 dwg, 1 ex

FIELD: oil and gas industry.

SUBSTANCE: well is equipped with a flow string and packer, the packer is set between two strata at 3 m and below from the bottom in the upper perforated interval. The well is shut down in order to align temperature field, records of gamma-ray and temperature log are made for the flow string to register a curve of background temperature distribution along the whole length of the well. Active water volume is pumped through the flow string to the lower stratum; simultaneously the metre intended to measure water flow rate in annular space is shifted from the length of packer seat to the distance of at least 50 m above the roof of the upper stratum with registration of reading of the thermometer and a flow meter. The repeated record is made for the well temperature survey and curve of background temperature distribution along the whole length of the well is registered; data are analysed and conclusion is made about technical status of the well.

EFFECT: improving authenticity of upward crossflows behind the production casing and vertical fluid movement in behind-the-casing space in wells with two and more perforated strata.

2 cl

FIELD: oil and gas industry.

SUBSTANCE: method of hydrodynamic research for gas-bearing formations without gas release to the surface includes running in at the drill string of flow string of the testing equipment in the form of a formation tester with a packer and geophysical sensors to the preset research interval of the gas-bearing formation. The research interval is isolated by the packer upstream the gas-bearing formation. Influx mode and pressure recovery mode are created in sequence and the further interpretation of the received data is made. At that in process of the testing equipment running in to the drill or flow string the design quantity of at least two-component viscoelastic mixture with the target parameters of viscosity and elasticity is poured additionally; the mixture is made without a crosslinker and based on polyacrylamide and zeolite or mud powder; above the testing equipment assembly it creates a viscoelastic plug. The plug ensures creation of depression to the value not exceeding 10-20% of the expected formation pressure. Further the hydrodynamic research is made as per the drill stem test procedure.

EFFECT: improving accuracy and efficiency of the research.

2 cl

FIELD: oil and gas industry.

SUBSTANCE: in method of water breakthrough control in the gas well which includes recording of gas consumption and bottomhole pressure between the dates of gas-dynamic research by pressure transient test, determination of values for the first and second master components corresponding to the biggest characteristic numbers of input data covariance matrix including values of zero and firs-order derivatives for gas flow rate, square gas flow rate, bottomhole pressure, analysis of dynamics for the first and second master components in time, plotting curves of their changes in time, conclusion on increase of flooding degree in the bottomhole zone of the stratum when curves of the first and second master components cross, periodical sampling is made for the mixed bottom and condensate water, determination of total minerals content for water samples, determination of specific quantity of bottom water in the well production, inclusion of the rated values for total minerals content for water samples and specific quantity of bottom water in the well production to the input data matrix.

EFFECT: specification of data on changes in gas flow coefficients for the bottomhole zone due to consideration of the main factors characterising flooding degree of the stratum bottomhole zone.

FIELD: oil-and-gas industry.

SUBSTANCE: in compliance with this method, seam is subjected to cycling, every cycle including gas injection therein with subsequent gas withdrawal. Cycling includes at least 10 cycles. Current seam pressure (Ptf) and gas withdrawal (or injection) volume are measures at regular intervals in every cycle. Measured parameters allowed for design pressure in underground storage facility (Ptd) is determined for facility operation without gas leaks and with leaks. Function (F) is defined as mean arithmetic value of (Ptd) deviations from (Ptf) obtained at every ith measurement for operation without leaks and function (Fl) for operation with leaks. Given Fl<F, leaks are considered available.

EFFECT: simplified control, higher safety and reliability.

1 tbl

FIELD: oil and gas industry.

SUBSTANCE: method lies in continuous monitoring of the total mass flow rate Mli and volumetric gas discharge Qgi and calculation of the coefficient Ki=ΔMliΔQgi, where ΔMli and ΔQgi respectively for the difference of the previous (stored) and current average numerical values of the total expense parameters of the well pad M¯li and Q¯gi. When the numerical value Ki deviates from the range of the preset values, the total flow mass rate of the liquid Mli(n-1) and the total flow mass rate of free gas Qgi(n-1) for (n-1) wells, where n is the total number of wells in the well pad, the flow mass rate of the liquid (water-oil mixture) Mli=Mli-M(n-1), the flow mass rate of free gas Qgi=Qgi-Qgi(n-1) and Ki=MliQgi coefficient is calculated for each well. Thereafter the numerical values of Ki are compared for each well with the current numerical value Ki, and the well with a variable flow mass rate in the well pad is identified against the minimum difference between the numerical value Ki of one well in the well pad and the numerical value of Ki coefficient.

EFFECT: identification of the well with the variable flow mass rate of the liquid in the well pad directly in the process of the well flow rates measurement.

2 cl, 1 dwg

FIELD: oil and gas industry.

SUBSTANCE: determination is carried out in a well equipped with a tubing string with an electric-centrifugal pump and a return valve at the end. In order to determine water cut the well is selected in the middle of an oil deposit with production modes close to the average values for the deposit. The well is operated not less than the time required to reach full operation. The well is stopped and process holding is made till gas separation from the well product and breakage into oil and water. Height of the liquid column is measured, volume of the water cut is determined against the boundary line of liquid and gas and water and oil.

EFFECT: improving accuracy of the water cut determination in the well.

FIELD: measurement equipment.

SUBSTANCE: system (100) of sensors for measurement of a technological parameter of a fluid medium in a well location, comprising a resonator (110) of a parameter, which is located in a well (106), having resonance frequency that varies depending on the technological parameter of the fluid medium and which in response generates a resonant acoustic signal on the resonance frequency that indicates the technological parameter. Besides, the system comprises an acoustic sensor (118), arranged in the location near above the surface, spaced from the parameter resonator, a measurement circuit (102), connected with the acoustic sensor, and an acoustic source connected with a pipe in the location near above the surface and spaced from the parameter resonator placed in the well. At the same time the acoustic sensor is made as capable of receiving the resonant acoustic signal, transmitted from the parameter resonator, the measurement circuit is arranged as capable of formation of an output signal of the technological parameter, corresponding to the technological parameter of the fluid medium, in response to the received resonant acoustic signal, and the acoustic source is arranged as capable of transmission of the acoustic signal into the well.

EFFECT: provision of measurement of well fluid medium properties in real-time mode both in process of drilling and in process of well operation.

20 cl, 6 dwg

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