This invention relates to the oil and gas industry, more specifically, to the operation of production wells, and can be used for the development of oil, gas and gas condensate fields.

This invention can be used, for example, for:

- determining water breakthrough time and intervals along the wellbore (including vertical, deviated and horizontal wells in oil and gas fields);

- determining wellbore cleanup efficiency for different intervals during the well developing operation;

- determining inflow fluid phase composition in multilateral wells;

- determining inflow fluid phase composition in multilayer reservoir co-separate production.

The following well development monitoring methods are currently used: injection of tracers into a bed (the tracer method), installation of bottomhole pressure and temperature gages (or sets of gages) into production wells, installation of distributed fiberoptic temperature gages along the wellbore or geophysical well survey methods.

Typically, the tracer method comprises monitoring the distribution of injected water that contains tracers earlier not present in the reservoir fluid. Tracer methods used for the exploration and survey of oil reserves and for hydrocarbon production monitoring can be divided into three groups.

The first group is based on tracing the infiltration flows between wells in large rock masses. This group of methods comprises test wells drilling methods or injected liquid or gas tracing methods. These methods allow one to determine the true flow and direction of reservoir fluids and injected water and to evaluate the reservoir properties of naturally occurring beds in-situ. Other data retrieved using these methods include flow distribution between separate layers and wells, water cut sources, hydrodynamic relationship across rock areas and sections, the inhomogeneity degree of deposits, oil and gas displacement efficiency and the extent to which this efficiency is affected by specific wells and their drainage and injection regimes.

The use of tracers in these methods provides the most valuable information on deposits in inhomogeneous formations when complex reserves development systems and new methods of oil recovery stimulation are used. The tracer methods help solving the most important task of the current oil industry development stage which is to increase the efficiency of productive layers water flooding operations as the main process currently providing for high oil production countrywide. It is well known that efficient control of formation development processes requires reliable control of water flooding operations. This in turn raises the need for data on the rate and type of oil displacement by water, causes of production well water cut and the effect of regimes of water injection into the reservoir.

The second group includes stationary tracer source, single test well, radon, behind-the-casing flow testing and other methods. Their common step is the injection of tracer bearing fluids into the wellbore zone of a formation and recording the relevant changes in tracer concentration or location. These methods allow - regardless of the stage of reservoir survey, exploration or development they are used at - revealing permeable horizons in the section, determine the intake capacity of wells, evaluate the oil and water saturation of rocks, reservoir type, main fractured deposit parameters, bed anisotropy, deposit filtration and capacity properties, hydrodynamic relationship between layers, reservoirs and wells, presence of cross flows behind the casing etc.

The third group of methods is based on the injection of tracer bearing fluids into the borehole only. These methods are used for determining the technical condition of casing strings, equipment and production tubing, drilled borehole volume and the true oil saturation of the layers based on core data. Changes in the bottomhole tracer concentration also provide data on filtration flow parameters, e.g. flow speed, direction and velocities in the reservoir.

Sets of conventional pressure and temperature gages can be used as point gage chains. However, this distributed metering method, in spite of its evident merit consisting in the high accuracy of temperature (to hundredths of a degree) and pressure measurements, requires lowering quite massive cables into the borehole which may consist of decades or even hundreds of wires connected to separate gages. Power supply of these systems is another cumbersome task. Furthermore, these systems have problems inherent to any other multichannel metering devices: failure of a single sensor may distort' the overall measurement results for different reasons.

Distributed fiber-optic gage systems are free from these problems. Their operation principle is based on the measurement and analysis of light pulse backscattering spectrum. The use of fiber-optic cables as distributed temperature gages provides realtime data on the temperature distribution along the entire cable length with 1 m intervals and does not require exact wellbore depth positioning. These systems eliminate the need for borehole electronic devices which is another contribution to the safety and accuracy of measurements. Fiber-optic systems have a wider operation temperature and pressure range compared to point gages. The dimensions of fiber-optic cables are far smaller than those of conventional temperature metering systems, and this allows placing fiber-optic cables in the annular space between the casing and production strings. Moreover, these cables can be installed either into wells being drilled or into already completed production or injection wells without interrupting their operation.

Distributed fiber-optic gage systems can be used for the location of productive intervals in production wells and intake intervals in injection wells; retrieving production yield distributions and injectivity profiles in multilayer systems; determining fluid phase composition profile across the borehole depth; locating behind-the-casing flows and casing leaks; measuring the static and dynamic fluid levels and oil/water boundary in the annular space; obviously these systems are of special importance for the monitoring of thermal development techniques.

The main disadvantage of these methods (the use of pressure and temperature gages and the fiber-optic temperature measurement system) is their insufficient suitability for data interpretation in horizontal wells. The absence of a geothermal gradient in horizontal wellbores complicates inflow profile assessment. Locating gas breakthrough requires a large pressure drawdown. Water breakthrough is almost impossible to locate. The use of these systems requires making significant and complex modifications to the well completion system with a large risk of damaging the equipment during installation or equipment failure during operation.

Geophysical well survey methods allow not only evaluating productive intervals and assessing inflow (intake capacity) profiles but also determining borehole fluid composition and locating water breakthrough and gas breakthrough using density, moisture and resistivity metering methods.

Unfortunately, most of the existing commercial well logging methods suffer from drawbacks like discrete metering data, necessity of well production interruption before the works and in many cases restriction of well operation parameters during the measurements. The time discrete well logging data often fail to detect the onset of important processes occurring in beds and near wellbore zones of wells e.g. fluid phase transformations, displacement agent breakthrough, change in reservoir filtration properties etc.. Moreover, well production interruption or even minor modifications to well operation mode required for the measurements may cause a distinctive deviation of well parameters from the earlier established ones or lead to a significant redistribution of bed fluid inflows. Yet any intervention into well operation is often quite undesirable due to potential consequent reduction of well output and large hydrocarbon production losses brought about by process operations and well downtime. Further disadvantages include difficult equipment delivery to the bottomhole in case of horizontal wells or large horizontal deviation wells. If a well is operated with submersible downhole pumps, well logging is not always feasible.

Known is (A.I. Gritsenko et al., Well Logging Handbook, Moscow, Nauka, 1995, p. 487) a well development and operation control method and a diaphragm critical flow meter (DCFM) for that method. For the method, the DCFM device is installed at the Christmas trees torch line to let the gas out to the atmosphere through the device by opening the torch line valve. The DCFM device measures the gas flow, humidity and temperature. DCFM comprises two orifices for connection to the pressure gage, blowout vents, a temperature gage well and a membrane. However, this method does not provide data on the filtration properties of the bed and the processes actually occurring in the well with time and space referencing.

Known is (RU Patent 2052094) an oil-saturated reservoir location method comprising surface oil sampling and testing various oil parameters as reservoir property indicators.

However, this method does not provide data on the filtration properties of the bed and the processes actually occurring in the well with time and space referencing.

Known is (RU Patent 21 22107) an oil deposit development control method based on the use of residual oil saturated rock thickness maps and comprising well logging, laboratory tests of bed fluid and porous rock properties, calculation of residual oil saturated rock thickness in the vicinity of the z-th well having the (x, y) coordinates based on well product water cutting using the Buckley-Leverett model and recovery of the residual oil saturated rock thickness field for arbitrary points of deposits having the (x, y) coordinates based on the current well logging and geological survey data. Furthermore, these data are used for plotting initial oil saturated rock thickness maps, determining overall produced oil volumes for production wells and overall injected volumes for injection wells and analyzing the permeability distribution across layers and the contribution of well operation to the formation of the residual oil saturated rock thickness field. Although this method allows efficiently controlling the development of a one-bed field based on the permeability distribution across the interlayers of the reservoir and taking into account the overall produced oil volumes and the overall injected volumes for each well by plotting and analyzing the residual oil saturated rock thickness maps and earlier well development and geological survey works, it still does not provide any data on the filtration properties of the bed and the processes actually occurring in the well with time and space referencing.

Known is (SU Inventor's Certificate 1473405) a bed fluid filtration property determination method comprising tracer injection into an injection well and its further detection in the production well fluid, wherein tracer destruction and sorption by the host rock are avoided by flooding the injection well with bed fluid resistant luminophores (various dyes) to act as tracers that were preliminarily introduced into microorganism cells (microorganism biomass).

Also known is (SU Inventor's Certificate 1 730442) a multilayer oil field development control method comprising product fluid sampling from each oil bearing layer and well product sampling, chemical composition analysis of the well fluid water phase, sequential injection of tracers containing water solutions of the same chemical components (e.g. haloid and alkaline metal nitrate solutions) into the oil bearing layers and judging on the filtration properties of the oil bearing layers and the relative water yield based on the change in the concentrations of these chemical components in the well product samples. Disadvantage of the abovementioned methods is the impossibility of locating water breakthrough or gas breakthrough in a specific well. However, when exploring wells it is necessary to know which quantity of hydrocarbons different well intervals yield.

The object of this technical solution is increasing the scope of data on the filtration properties of the reservoir and the processes actually occurring in the well with time and space referencing.

It is suggested to achieve said object suing the hydrocarbon field development control method provided herein. For the method, at least one container/matrix comprising tracers is installed to downhole equipment and lowered into the borehole to the specified depth from the wellhead, and then the well fluid or gas is controlled for the presence of the tracer, wherein the case of said container/matrix is made either from a material capable of dissolving or decomposing in water or gas but resistant to hydrocarbon media or from a material capable of dissolving in hydrocarbon media only. In the preferred embodiment of this invention, multiple containers/matrix are installed in different well zones, each container/matrix comprising an individual tracer. The distance between said tracer containers/matrix is selected based on reservoir and near wellbore zone parameters. In some embodiments the zones with installed containers/matrix can be mutually isolated in order for the different tracers not to be mixed. Isolation can be provided, for example, by installing packers. The method comprises the installation of tracer containers/matrix on the bottomhole completion equipment. Different tracers are installed in different well zones. The containers/matrix may be capable of retain integrity for a long time in the initial hydrocarbon media at the bed pressure and temperature. In case of water breakthrough or gas breakthrough into oil producing well (or water breakthrough into a gas well) the container case or matrix starts decomposing or destroying to release the respective tracers.

Regular surface fluid sampling and analysis for the presence of the tracers allows not only determining the time of water or gas breakthrough but also quantifying and locating the breakthrough (because different well intervals have different tracers).

Different tracer container/matrix downhole installation options are presented below:

- if the well is completed with sand filters (with wire, mesh, metallic chip or other fillers), the tracer containers/matrix are installed on the outer surface of the screened pipe, and then the filter elements are installed thereupon. In another embodiment of this option, the tracer containers/matrix are installed on the inner or the outer surface of the filter;

- for multilateral wells and dual completion production wells, short pipes with preinstalled tracer containers/matrix can be used. Said pipes are included into the bottomhole completion equipment, installed in the required zones and used for monitoring. If the well 1

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is completed with slotted liners or perforated pipes, container/matrix pipes can be added to that equipment.

More than 100 different materials can be used as tracers. Some examples are provided hereinbelow: fluorescent materials (sodium fluorescein, disodium eosin salt, erythrosine, rhodamine G, S etc.); different dyes (e.g. nitrous compounds: urea, ammonia sulfur, stable nitroxile radicals and their derivatives (amines and amine salts)). The advantages of these tracers are their water solubility, lack of naturally occurring counterparts, biological inertia, lack of chemical interaction with oil and stability in bed media; high heat neutron absorption materials (e.g. barium salt solutions, boron, cadmium and rare earth metals); radioactive isotopes (e.g. tritium that has a long half life period).

Said containers/matrix can be made from gelatin, gypsum, water soluble polymer films (polyvinyl alcohol), soluble paper and materials used for capsule fabrication in the pharmaceutical industry. The typical composition of the well fluid does not dissolve these shells, but water breakthrough will cause a dramatic increase of the water concentration in the well fluid resulting in the destruction of the containers/matrix.

In case of gas breakthrough the container shell or matrix material will be abraded by the solid particles entrained by the gas. This method may have the following embodiments.

1 . Horizontal well water breakthrough detection. The well is divided into multiple intervals depending on its permeability profile and the distance to aquifers. The well is completed with wire sand filters, and the intervals are mutually isolated with swelling packers installed at the interval boundaries. Then the chemicals that can be used as tracers are placed inside the sand filters so to be in contact with the reservoir fluid supplied to the well. In each well interval, its specific tracer is placed (e.g. ammonia thiocyanate in the first interval, urea in the second interval, thiocarbamide in the third interval, trisodium phosphate in the fourth interval etc.). For standard production, well fluids contain approx. 80% oil and 20% water. In case of water breakthrough from the aquifers the oil to water percentage in the product fluid changes dramatically, e.g. to 20% oil and 80% water. To locate the water breakthrough, one should sample the wellhead fluid and determine which tracers have the highest content in the sample. This will indicate the interval where the breakthrough occurred and help eliminate it faster.

2. Horizontal well gas breakthrough detection. The well is divided by analogy with the previous example into multiple intervals depending on its permeability profile etc.. In each well interval, its specific tracer is placed (e.g. ammonia thiocyanate in the first interval, urea in the second interval, thiocarbamide in the third interval, trisodium phosphate in the fourth interval etc.). The tracers are installed to produce extra impedance to the flow. This can be achieved, e.g. by installing the tracer containers/matrix in a spiral arrangement wrapped onto a gas pipe. In case of gas breakthrough the gas flow into the pipe will be much higher than the liquid flow, and this will cause intense wear of the containers/matrix and the release of the tracers. The interval in which the gas breakthrough occurred is determined by analyzing the tracer concentrations in the samples.

3. Determination of outputs of different well intervals during well development. The well is divided by analogy with the previous example into multiple intervals depending on its permeability profile etc. In each well interval, its specific tracer is placed. The type of the tracers is selected such that to dissolve in hydrocarbon media only. Wellhead sampling for tracer concentrations al lows one to determine the quantities of hydrocarbons delivered to the wellbore from different intervals.

This invention can be used at least for the following purposes:

- determine along the production wellbore water breakthrough time and intervals (including vertical, deviated and horizontal wells in oil and gas fields);

- determining wellbore cleanup efficiency during the development of different productive intervals; - determining inflow fluid phase composition in multilateral well offshoots;

- determining inflow fluid phase composition in multilayer reservoirs systems during co-separate production.

The advantages of this method include:

- possibility of locating water breakthrough or gas breakthrough based on wellhead sampling data;

- elimination of the necessity to interrupt well operation for the works;

- data availability regardless of downhole equipment type used;

- suitability for horizontal or complex profile wells;

- low cost of tests compared with other methods.