Method to inject carbon dioxide

FIELD: packing industry.

SUBSTANCE: invention relates to the method of carbon dioxide (CO2) storage in a porous and permeable underground reservoir bed) and in particular, to the method for injection of CO2 into a hydrocarbon reservoir for its storage. The concept of the invention is as follows: the method includes the following stages: (a) extraction of a produced fluid flow from a development well, which contains produced hydrocarbons, water and CO2; (b) direction of the produced fluid flow to a process facility, where a steam phase flow is separated from this flow, containing carbon dioxide and volatile hydrocarbons; (c) compression of the produced steam phase flow to the pressure above the maximum pressure, when two phases of gas and liquid may coexist, for the composition of the produced steam phase flow; (d) cooling of the compressed flow with formation of the cooled flow in a dense phase condition; (e) direction of the CO2 flow towards the injection equipment, which arrives from the side and may be in a liquid phase or in a supercritical condition; (f) mixing of the cooled flow from the stage (d) with the flow of CO2 arriving from the side to form a combined flow, which represents a flow of a dense phase substance; and (g) injection of the specified combined flow into the hydrocarbon reservoir via an injection well.

EFFECT: increased efficiency of the method.

22 cl, 2 dwg

 

The present invention relates to a method for storing carbon dioxide (CO2in porous and permeable underground formation-manifold (the so-called reservoir) and, in particular, to a method of injection CO2the collector of hydrocarbons for storage.

CO2the gas, which in large quantities is obtained as a by-product of several industrial processes such as ammonia production, power plants using fossil fuels, such as coal, oil, or gas, and the production of hydrogen, where hydrogen is produced by reforming of hydrocarbons. Emissions into the atmosphere of this by-product is undesirable, as CO2refer to gases that create the greenhouse effect. Many efforts have been undertaken to develop methods of disposal of CO2in order to prevent its emission into the atmosphere. In particular, one such method, the calling of special interest, offers underground disposal of CO2the injection of CO2in the existing rock caverns or porous layer. A useful advantage from the utilization of CO2can be obtained by the injection of CO2in porous and permeable reservoir of hydrocarbons, in which the injected CO2can be used to displace hydrocarbons (e.g. oil) in the reservoir in the direction explotar is evident wells (wells, from which is extracted hydrocarbons), thereby achieving a higher degree of oil recovery from the reservoir.

Injection of CO2in the reservoir, especially in order to increase hydrocarbon production, entitled "methods of enhanced oil recovery" (MPNO or EOR methods) or oil secondary methods described, for example, in US 2002/0036086. According to this document, CO2extracted from operational wells may be re-injected into the reservoir via the injection well in order to reduce the viscosity of the oil at the place of its occurrence in the productive horizon, to increase its mobility and ease of its production. However, this is extracted from operational wells CO2contains some hydrocarbon impurities that may have unintended effects on the saturation pressure of the reservoir oil. The method disclosed in US 2002/0036086 aims at removing the above-mentioned contaminants from the produced CO2prior to re-injection of CO2into the reservoir. Moreover, in the US 2002/0036086 said that sequestration of CO2that, by definition, inherent in this process is actually a disadvantage of this process, the result of which are "lost" CO2and need more CO2.

Despite the fact that the injection of CO2in the reservoir, due to vysheskazanyh the th, known as in order to improve oil recovery, and for its underground storage requirements for CO2for underground storage are significantly different from the requirements for CO2to improve oil recovery.

Therefore, from the point of view of enhanced oil recovery according to the ideas of the solutions disclosed in US 2002/0036086, any underground storage of CO2that is, regarded as a "loss" and is a disadvantage. In contrast, when the sequestration of CO2preferably, the reservoir remained more pumped CO2.

Therefore, in General, the CO2that it is advisable to cut out, should be in such a physical condition that would prevent its mixing with the hydrocarbon reservoir, while the reverse is typical for CO2that pump in order to improve oil recovery. Similarly, it is desirable that CO2that it is advisable to cut out, would be in a state that maximized the possibility of its underground storage, in particular in the form of a substance of high density with a maximum mole fractions of CO2per unit volume. In contrast, from the point of view of enhanced oil recovery, as a rule, it is desirable to increase oil recovery by the use of the CO 2in minimal effective for this purpose the volume.

In addition, the amount of CO2that for recycling into the reservoir hydrocarbons is very high, typically of the order of several million tonnes, which is significantly higher compared to the amounts of CO2required for enhanced oil recovery. Because of the amount of CO2such significant equipment for injection to provide reliable pumping coming from CO2into the reservoir. In other words, it must be always ready to upload all coming from CO2. Moreover, the collector shall be designed for the secure storage of injected CO2typically, during a period of at least 1000 years.

Typically, if possible, it would be desirable to CO2injected for sequestration, was admitted to the manifold at a considerable distance from the production well and in such a state of aggregation, so that it could not be mixed with the hydrocarbon reservoir, in order to maximize the storage capacity while minimizing the transport of injected CO2to operating the well. However, the distance from any injection wells prior to any operational wells shall be limited for example, due to the constraints in the infrastructure. In any case, the presence of injected CO2in large quantities over time will lead to an increase in the volume formed by CO2-containing vapors extracted from the operating wells. Such CO2can have a positive effect on the volume of oil production, however, proposed in the present invention method, the enhancement layer has a lower priority than ensuring a constant and reliable injection of CO2into the reservoir and secure underground storage of injected CO2.

Next, there is a need to solve problems related to the increasing with time amounts received CO2. Although operating wells are often injection wells for associated gas, which is used to discharge the received CO2-containing vapors, even in the absence of sequestration CO2, increasing amounts of CO2-containing vapors which result from the sequestration of CO2the collector may become too big for the said oil field facilities and require drilling a larger number of injection wells and associated capital costs, and all this for the collector, the peak selection rules oil which remained in the distant past.

It was found that if transfer the resulting vapor stream to be back pumping into the reservoir of hydrocarbons from the vapor phase to the dense phase of matter, then the resulting pulse dense phase flow of the substance can be mixed with the stream coming from CO2that is either in liquid phase or in the supercritical state, thus forming a combined stream that will flow pulse dense phase of matter. Such combined stream can then be directed into one or more injection wells, whence it is pumped under pressure into the reservoir of hydrocarbons.

Accordingly, the present invention provides a method of underground storage of CO2in porous and permeable reservoir hydrocarbons having at least one injection well and at least one development well, revealing (passing through) the collector, comprising the following steps:

(a) removing from operating wells flow of produced fluid (fluid medium), consisting of extracted hydrocarbons, produced water and produced CO2;

(b) the direction of flow of the produced fluid at the processing facility, at which fluid flow is separated vapor stream comprising carbon dioxide and volatile hydrocarbons;

(C) compressed the e obtained vapor stream to a pressure above the maximum pressure, where else can coexist two phases of gas and liquid (recondenser), for the composition of the obtained vapor stream;

(g) cooling the compressed stream, thus forming a cooled stream in pulse dense phase state;

(d) the incoming direction of the flow of CO2to the discharge equipment, and coming from CO2can be either in liquid phase or in a supercritical state;

(e) mixing the cooled stream from step (g) with the stream coming from CO2, thus forming a combined stream; and

(g) pumping-mentioned combined stream into the reservoir of hydrocarbons via the injection well.

The obtained vapor stream is a multi-component composition. Therefore, the compressed stream is cooled stream and the combined stream is also a multi-component compositions.

The term "pulse dense phase condition" refers to a multi-component composition, which has no definite volume or of the characteristic features of the phase boundary. Therefore, the fluid in the pulse dense phase condition, behaves like a gas, in the sense that the fluid will expand to fill the container in which it is placed. However, pulse dense phase fluid will have physical properties similar to the physical t what you liquid medium. In particular, pulse dense phase fluid will have a density similar to the density of the liquid medium. Therefore, the pressure pulse dense phase fluid can be increased by using a pump, and the column pulse dense phase fluid into the injection well will demonstrate significant hydrostatic pressure. In addition, pulse dense phase state of CO2- this state, when the molar fraction of CO2per unit volume is high. Also, since the characteristic features of the phase boundary is missing, it is assumed that the pulse dense phase fluid will be a single-phase medium.

The collector of hydrocarbons may be oil reservoir bed or a gas condensate reservoir-kolektor, and to represent any geological structure, the thickness of the rocks, oil sand reservoir, rock-collector etc. in which there are natural deposits of oil or gas condensate. Preferably, the reservoir of hydrocarbons was opened several operational wells. Preferably, the reservoir of hydrocarbons was also encountered several injection wells.

Further, it is preferable that the hydrocarbon reservoir was a collector of an oil field. Usually oil field may have more than one oil reservoir. Generally, for the efficient is economically viable underground storage of CO 2in the oil field this field should be large enough, with the content of the original oil in the reservoir in excess of five million barrels. Preferably, the oil field was located in the place with the existing infrastructure of distribution pipelines, which could be used to deliver the flow of CO2from the side. As a rule, oil field should be injection equipment and injection pipelines for multiple injection wells.

In particular, the method proposed in the present invention is economically feasible where the period of productive life of an oil field is approaching the end (depleted oil reservoir). As the extract stream of produced fluid containing hydrocarbons, produced water (buried water and any previously pumped water) and extracted CO2from operating wells is being phased out, forcing the above-mentioned combined flow is terminated, and the available amount of CO2will sequestrian. The extraction of hydrocarbons and water from the oil reservoir during the injection of the above-mentioned combined stream is important for the formation of a space for underground storage of CO2in this collect the re. In the absence of hydrocarbons and water from the oil manifold the manifold pressure will increase to the initial reservoir pressure for a relatively short period of time, for example, over a period of time from 2 to 5 years, and the amount of CO2that can be sequestrian, consistently reduced.

The method proposed in the present invention, may be used where the collector hydrocarbon opened many existing gas-injection wells and / or wells for alternating injection of water and gas (WAG), and consequently, the injection equipment are real production possibilities to discharge gas. However, such real production possibilities to discharge gas can be limited by high capital costs for the acquisition of additional compressors and refrigerators, limited space and weight limitations, particularly on offshore platforms, or insufficient capacity of gas turbines, generating electricity for gas-injection compressors. Therefore, the advantages of the present invention include that the resulting vapor stream exceeding the production capacity of the current injection equipment, can be directed back into the collective is the PR due to its conversion from the vapor phase in the dense phase before what he is mixed with a stream of CO2coming from the side. Therefore, there is no need to increase production capacity for gas charging current injection equipment. Typically, the conversion of surplus obtained vapor flow from the vapor phase in the dense phase requires a higher production capacity for gas production and gas-injection equipment, approximately 250 million standard cubic feet of gas supplied per day (million STD. cubic feet/day) (7 million cubic meters received a couple a day). Typically, the total volume of the obtained vapor stream to be back injection into the reservoir is at least 100 million standard cubic feet of gas supplied per day (million STD. cubic feet/day) (2.8 million cubic meters received a couple a day). Therefore, a portion of vapor stream (in the amount not exceeding the production capacity of the existing gas-injection compressor) can be pumped into the vapor phase in one or more existing gas-injection wells and / or wells for alternating injection of water and gas in the gas-injection compressor (compressors). The remaining part of the resulting vapor stream is revocat from the vapor phase in the dense phase before mixing with the flow of CO 2coming from the side, thus forming a combined stream. This combined stream can then be uploaded to one or several existing water injection wells and / or one or several injection wells designed to pump such combined stream. However, it is assumed that one or more of the existing gas-injection wells and / or wells for alternating injection of water and gas can be used to pump combined flow, thereby increasing the number of injection wells, which can be used to pump combined stream.

It is also assumed that the discharge obtained vapor flow in the vapour may be excluded. So you can not use the existing gas-injection power and convert essentially all the obtained vapor flow in pulse dense phase condition prior to its mixing with the flow of CO2coming from the side. Therefore, the present invention allows to translate all existing gas-injection wells and / or wells for alternating injection of water and gas injection combined stream, providing higher assurance that CO2coming from the outside can be reliably injected into the reservoir. Therefore, t is such an approach ensures a higher degree of flexibility in case if one or more (but not all) of the injection wells will be stopped, for example, for maintenance and repair.

In addition, another advantage of the present invention is the ability to use large amounts obtained vapor stream, which must be sent back to the collector, in the absence of any existing gas-injection capacities and existing gas-injection wells. Therefore, it is possible to essentially all the obtained vapor stream has been subjected to compression and cooling prior to its mixing with the flow of CO2coming from outside, and to all injection wells, revealing the collector hydrocarbons (for example, active water injection wells, and(or) injection wells that have been specially designed to pump combined flow), were designed to pump mentioned combined stream into the reservoir.

In addition, another advantage of the present invention is that the compression ratio (compression) and cooling the product vapor stream (converting the thus obtained vapor flow from the vapor in pulse dense phase state) and mixing the resulting cooled stream coming from CO2(which is either in the liquid is aznom, or in the supercritical state) lead to lower operating costs for the discharge of the stream is compared with the costs of separate injection of CO2coming from the side (which is either in liquid phase or in the supercritical state), in wells for injection of fluid, and received compressed vapor stream, respectively, in the gas-injection wells. This is because in the injection well pressure in the bore consists of two components: (a) pressure at the wellhead, and (b) static pressure or weight of the column of fluid in the injection well. The static pressure of the column pulse dense phase fluid into the injection well is much higher static pressure of the column of steam. Accordingly, the pressure at the wellhead of the combined stream is lower than the pressure at the wellhead received compressed vapor stream. Moreover, the operating costs for compression vapor stream to a higher pressure higher than the cost of building a higher pressure pulse dense phase flow pumps.

Another advantage of the present invention is that the injection of the combined stream into the reservoir hydrocarbons can lead to higher standards of production of liquid hydrocarbons (e.g., the ti or gas condensate from the collector. This increased production may be possible due to the higher displacement ratio pulse dense phase combined stream compared to displacement ratio of water used as the displacing fluid, because, unlike water, the combined stream has a viscosity similar to the viscosity of the oil, and, therefore, less likely that the flow will bypass the oil passes through the oil. In addition, the increase in production rate may be possible by dissolving the United pulse dense phase flow of oil from the surface of the collector breed. Increasing the production rate of gas condensate may be possible where the combined stream is injected into the lower part of the condensate collector.

If the resulting vapor stream has a low content of CO2which is less than 15 vol.%, part of the obtained vapor stream can be used as fuel gas for production and injection equipment, for example, as a fuel gas to one or more generators of electricity. However, since the concentration of CO2in the resulting vapor stream with time increases, this may lead to lower calorific value of the obtained vapor stream. Therefore, the fuel gas can be formed by omitting poruchenoprorabotatj flow (for example, stream with the content of CO2more than 50% vol. or more than 75 vol.%) through the membrane module for separating fuel gas with a content of CO2less than 15 vol.%. If the content of CO2in the resulting vapor stream is greater than 75 vol.%, this will require processing a large amount of the obtained vapor stream. For example, the amount of vapor flow, which is used to produce fuel gas, can be in the range of 5 to 10 million standard cubic feet of steam per day (million STD. cubic feet/day) (from 0.14 to 0.28 million cubic meters of steam per day). Exhaust stream with a high content of CO2can be re-United with the rest of the obtained vapor stream prior to compression of the obtained vapor stream in step (C) implementation of the present invention. The advantage of this re-Association mentioned exhaust flow with the rest of the obtained vapor stream is that the cooled stream from step (g) of the method proposed in the present invention, will have a higher molecular fraction of CO2. Therefore, the cooled air flow will flow more high density (compared to the if-mentioned exhaust stream did not unite again with the obtained vapor-phase flow). Therefore, the combined p the current will also have a higher density, and the pressure in the wellbore will be more conducive factor due to the static pressure of the column of fluid combined stream into the injection well.

The flow of CO2coming from the side, may be a byproduct stream coming from the plant (for example, stream a by-product extracted from flue gases), or may be a byproduct of installing hydrogen (for example, a by-product, selected from a stream containing hydrogen and carbon dioxide, where the hydrogen will then be used to generate electricity at the power plant). The flow of CO2coming from the side, can also be obtained with the installation of natural gas, which CO2separated from the product stream of natural gas. In addition, CO2may be a byproduct of ammonia production.

The flow of CO2coming from, preferably composed of at least 98% of the CO2in terms of dry substance. Therefore, the flow of CO2coming from the side, may include trace amounts of additional components selected from hydrogen, carbon monoxide, nitrogen and mixtures of the abovementioned compounds. For example, if the flow of CO2comes with the installation of hydrogen, the additional components, mainly, are hydrogen and the led carbon. Typically, the content of hydrogen in the CO2coming from the side, less than 1 wt.%.

Although the flow of CO2coming from the side, not a single component stream, the contaminants in the flow of CO2coming from the side, so low that the phase behavior of this flow is similar phase behavior of the stream of net CO2. In this regard, the flow of CO2coming from the outside, can be considered as a stream located either in liquid phase or in the supercritical state. Under "supercritical state" it should be understood that CO2coming from the side, has a pressure above the critical pressure of pure CO2and the temperature, which is above the critical temperature of pure CO2. Therefore, the compression ratio of net CO2at a temperature slightly below its critical temperature, component of 31.1°C, leads to liquefaction of natural gas at a pressure of approximately 73,8 bar (7.4 Psi) abs. However, the compression of net CO2when the temperature and pressure corresponding to its critical temperature and pressure or above its critical temperature and pressure, increases its density to the liquid state, however, does not lead to phase changes. If the temperature and pressure of CO2meet or exceed its critical temperature is round and the pressure it is about CO2referred to as a fluid in supercritical state. Despite the fact that CO2in the supercritical state can be compressed to the density as the liquid medium, and, therefore, can be pumped by the pump, it stores the diffuse properties of the gas and will grow up to fill the container in which it was placed.

CO2coming from, preferably guided to the injection equipment on the pipeline. This pipeline can be active gas pipeline to supply gas from the side, which was switched on transportation coming from the flow of CO2to the discharge equipment. In cases where the above-mentioned CO2come by pipeline, he usually arrives at ambient temperature, which, in the case of transport of CO2marine subsea pipeline, will be equal to the average temperature of the bottom layer (from 2 to 7°C, for example, from 4 to 6°C). The pressure of CO2flowing through the pipeline is preferably from 75 to 250 bar (7.5 to 25 MPa abs., preferably from 100 to 200 bar (from 10 to 20 MPa) abs. Therefore, the pressure coming from the side of the flow of CO2is above the maximum pressure at which can coexist two phases of gas and liquid, for all components merge the frame of the stream, regardless of the molecular fractions of CO 2in this merged thread). It is assumed that coming from the flow of CO2can be transported by pipeline under pressure at the wellhead required for the combined flow. In the alternative, the pressure of the flow coming from CO2may be lower than the pressure at the wellhead that is required for the combined flow. Therefore, the pressure coming from the side of the flow of CO2may be increased to the desired pressure at the wellhead before this stream is mixed with the stream, cooled in step (e) of the method proposed in the present invention. However, it is preferable to mix coming from the flow of CO2with the cool flow when the inlet pressure is coming from the flow of CO2and then to increase the pressure of the combined stream to the desired value of pressure at the wellhead. Usually coming from the flow of CO2transported by pipeline to the injection equipment in the amount of at least 5000 tons per day (5 million kg/day), preferably at least 5,500 tonnes per day (5.5 million kg/day). 5500 tons per day equal to the volume of injected CO236 million barrels per day, in situ, with a typical pressure at the well bottom 7500 pounds/inch (52 MPa) and standard temperature at the bottom of the wells the ins 25°C.

It also assumes that come from the flow of CO2can be delivered to the discharge equipment tanker (road, rail, sea). In those cases, when coming from the direction of flow of CO2transported to the discharge equipment tanker, such CO2as a rule, is in a liquid state. The tanker, as a rule, includes a pressurized container for the carriage of liquid CO2a pump for pumping the product inside the container and used for pumping liquid CO2and its direction through the pipeline to the injection equipment (thereby forming the incoming side stream CO2). Usually for pumping coming from the flow of CO2to the discharge equipment is also provided for external additional (booster) pump. CO2transported in tankers, as a rule, subject to freezing, otherwise the pressure required to maintain CO2in the liquid state, would be too high, which would result in the need to increase the thickness of the walls of the vessels, working under pressure, which, in turn, led would increase the cost of such tankers. As a rule, large-scale transportation CO2tankers optimum temperature liquid is asnago CO 2is in the range from -55 ° C to -48°C and a pressure of from 5.2 to 10 bar (from 0.52 to 1 MPa abs., preferably from 5.5 to 7.5 bar (from 0.55 to 0.75 MPa) abs. This corresponds to the position on the phase equilibrium diagram for net CO2that is, in terms of pressure and temperature, just above the triple point. The triple point of the phase diagram for pure CO2corresponds to a pressure of 5.2 bar (5,2 MPa) abs. and temperature -56,6°C. Usually, when CO2coming from the side, leaves the storage container, the pressure increases up to 30-70 bar (3-7 MPa abs., which corresponds to temperatures from -50 to 0°C. Then the pressure received from the stream of CO2can be increased to the required value of the pressure at the wellhead, before such CO2will be mixed stream, cooled in step (e) proposed in the present invention a method for the formation thereby combined stream. Alternatively, the stream received from CO2can be mixed with the stream, cooled in step (e) proposed in the present invention a method at this pressure, which is below the required value of the pressure at the wellhead, but above the maximum pressure at which can coexist two phases of gas and liquid, to form a combined stream. Then the pressure of this volume is Intego flow increases to the desired value of pressure at the wellhead. Transportation of liquid-phase CO2tankers at temperatures below the ambient temperature is costly because it requires freezing. There is also the danger that freezing CO2can lead to the formation of solid-phase CO2. According to this preferred method of transportation CO2is transported by pipelines.

If the combined stream is formed when the pressure is below the required value of the pressure at the wellhead, such combined stream can be fed to the injection pump or pumps (e.g., one or two, three, four consecutive pump) equipment for injection to achieve the desired value of pressure at the wellhead, preferably from about 100 to 350 bar (from 10 to 35 MPa abs., in particular, from 150 to 300 bar (15 to 30 MPa abs. It is also assumed that the pressure of such combined stream can be further increased in the trunk injection wells, for example, by a downhole electric submersible pump.

Specialists in the art it is well known that the average pressure of the reservoir hydrocarbons (and, hence, the desired pressure at the well bottom for pumping the above-mentioned combined stream into the reservoir hydrocarbons), among other things, inalsa depending on the depth of the reservoir and the type of rock. For example, the deeper the reservoir of hydrocarbons, the higher will be the pressure in the wellbore, In most cases, the average pressure of the reservoir hydrocarbons is regulated by the pressure in the injection well and the pressure of the operating wells. Typically, the pressure in the barrel injection wells at least 200 pounds/inch2(1.4 MPa) above the average pressure of the reservoir hydrocarbons, for example, 200-500 pounds/inch2(1.4 to 3.4 MPa) above the average pressure of the reservoir hydrocarbons, thereby ensuring that the above-mentioned combined stream will be pumped into the reservoir. However, for certain reservoirs is characterized by the phenomenon of cracking due to thermal shock, which occurs in the cases, when the amount of injection fluid into the formation increases when the pressure of the pressurized fluid exceeds the pressure of the crack opening. Thus, cracks in the reservoir can be opened and closed depending on the discharge pressure. Therefore, you may need to increase the discharge pressure of the combined stream to a pressure greater than the pressure of the crack opening, which may be at least 500 pounds/inch2(3.4 MPa) above, for example, at least 800 pounds/inch2(5.5 MPa) above the average manifold pressure.

The call is Thor hydrocarbons is usually uglevodosoderjati geological horizon below it (due to the higher density of water) aquifer (water-bearing zone). Usually aquifer zone is reported, i.e. has a connection in the form of channels for fluid flow, with uglevodosoderjati geological horizon. According to the method proposed in the present invention, the combined stream can be pumped into uglevodosoderjati the horizon or below the aquifer, preferably, in a place located as far as possible from any of the operating wells that reveal this uglevodosoderjati the horizon, to minimize transportation CO2to operating the well. Based on the foregoing, the injection well may open as uglevodosoderjati geological horizon and below the aquifer. The advantage of placing the combined stream in which is located below the aquifer lies in the fact that CO2has a high degree of solubility in water of the aquifer and, therefore, in the aquifer can store CO2in large volumes. Moreover, the injection of CO2in the aquifer leads to increased pressure, which helps to increase the production of hydrocarbons from uglevodosoderjati horizon.

As mentioned above, it is preferable that, to the extent possible, to upload referred to the combined stream into the reservoir on the significance of the considerable distance from any of the operating wells to minimize the transport of injected CO 2to operating the well. The possibility of maximizing the distance to the injection mentioned combined stream from any of the operating wells may depend on the structure and location of reservoir hydrocarbons, in particular on the number and location of injection and operating wells. Basically, the most effective storage CO2reach the injection combined stream through an injection well located on the edge (periphery) of the collector. In cases where the reservoir hydrocarbons is not horizontally bedded horizon, the combined stream is preferably injected at a low point located collector, for example in the bottom layer ("down dip").

On terrestrial deposits location operational and injection wells typically corresponds to the requirements of the oil, for example, such holes may be located on a geometric grid, called "schema flooding on a geometric grid", in which many operational and injection wells have so near each operating well there were several injection wells, and Vice versa. For example, one development well can serve six injection wells, with practice the Cesky hexagonal configuration with respect to operating the well. Also near each injection well can be three operating wells. This configuration can be repeated throughout the site with respect to the required number of operating wells. Preferred may be such a configuration, in which an injection well used to pump combined flow into the reservoir, not surround operational wells, for example, injection well located at the edge of the layout of the wells, so that not all CO2uploaded as part of the joint flow, flow direction operating wells. Further advantages when downloading the combined flow into the reservoir through injection wells that are part of the "scheme of flooding on a geometric grid, can be obtained through the suspend of the wells as injection, and operational) in order to optimize the underground storage of CO2due to the increase of the collector in the interval between injection wells and operating well.

The offshore fields in the injection wells, usually less, due to the high capital costs of drilling, and the operator has less flexibility, but, again, it is best to upload the combined stream at the periphery of the collector (NASK is like possible) and, preferably, located in low point of the reservoir, in order to maximize the distance between injection and operating wells.

It is preferable to store CO2in the reservoir for at least 1000 years. Hence, the pressure of the combined flow in the wellbore must be such that the pressure in the reservoir does not exceed the pressure of the overlying strata. When the pressure exceeds the pressure of the overlying layers will be cracking and destruction of reservoir rocks, which will subsequently lead to the leakage of CO2. Therefore CO2no longer will then be stored in the reservoir for a long period of time. As the life of a collector of hydrocarbons is approaching the end, it may be preferable to killing operational and injection wells caps to reduce the pressure in the reservoir to a value lower than the initial pressure in the reservoir. This will reduce the risk of leakage of stored CO2in the atmosphere as a result of damage to one of the caps wells. Therefore, the fluids from the surrounding rocks penetrated in the header and will keep CO2in the storage location in the header.

Volatile hydrocarbons in the resulting vapor stream, subject to the separation in step (b) of the method proposed in the present invented and, include methane, ethane, propane and butane. Therefore, as mentioned above, the obtained vapor stream, the compressed stream is cooled stream and the combined stream are multicomponent flows. Moreover, the composition of the obtained vapor flow and, consequently, the composition of the compressed stream, the cooled stream and the combined stream will change over time in the implementation proposed in this invention method (due to the increase with time of the molecular fractions of CO2in the resulting vapor stream). Therefore, to discharge CO2in the collector the amount of CO2present in the resulting vapor stream (natural CO2)may be within, for example, from 5 to 25 vol.%. After the beginning of the implementation proposed in this invention method, the amount of CO2in the resulting vapor stream will increase (for several years) until an amount in the range from 75 to 95 vol.%, for example, from 80 to 90 vol.%.

Therefore, it is preferable that the obtained vapor stream has been subjected to compression in step (C) proposed in the present invention of a way to pressure above the maximum pressure at which can coexist two phases of gas and liquid, for all compositions obtained vapor flow (and hence for all compositions of the compressed stream and ohla the established flow), which may occur during implementation of the method proposed in the present invention (regardless of the molecular fractions of CO2in these streams). Also, it is preferable to choose such pressure combined stream so that it is above the maximum pressure at which can coexist two phases of gas and liquid, for all compositions obtained vapor flow (and hence for all compositions of the compressed stream and the cooled stream)that may occur during the implementation proposed in this invention method (regardless of the molecular fractions of CO2in these streams). Where come from the flow of CO2is under pressure exceeding the maximum pressure at which can coexist two phases of gas and liquid, for all compositions obtained vapor flow, it is preferable that the obtained vapor stream has been subjected to compression to the pressure of the flow of CO2coming from the side.

The compressed stream is subjected to cooling to remove the heat of compression, thus forming a cooled stream in pulse dense phase condition. Typically, the compressed stream is cooled in a heat exchanger with a cooling agent such as water. It is important that this step cooling flow pressure was maintained above the value of the Maxi is social pressure, where can coexist two phases of gas and liquid, to avoid the risk of formation of two-phase connection. It is preferable to cool the compressed stream without any significant reduction in its pressure. However, the differential pressure up to 5 bar (0.5 MPa), preferably up to 3 bar (0.3 MPa) may be acceptable provided that the pressure of the above-mentioned flow will remain above the maximum pressure at which can coexist two phases of gas and liquid.

As a rule, the temperature of the cooled stream below the maximum temperature at which two phases coexist gas (cricondentherm), and liquids, for any changes in the composition of the compressed stream (regardless of the molecular fractions of CO2). Thus, with reference to figure 1, which shows a typical diagram of phase equilibria for multicomponent composition is an area which is above the maximum pressure at which can coexist two phases of gas and liquid, and to the right of the maximum temperature at which can coexist two phases of gas and liquid, generally regarded as the vapor region of the fluid, while the area that is above the maximum pressure at which can coexist two phases of gas and liquid, and to the left of the Maxim is through temperature, where can coexist two phases of gas and liquid, generally regarded as the pulse dense phase region of the fluid. Density pulse dense phase fluid increases with decreasing temperature. Therefore, it is preferable to cool the compressed stream to a temperature below the critical temperature for any changes in the composition of the compressed stream (regardless of the molecular fractions of CO2). Usually cooled stream has a temperature below 40°C, preferably below 30°C, for example, in the range from 10 to 40°C, preferably from 20 to 30°C, in particular from 20 to 25°C.

As mentioned above, the temperature of feed of the flow of CO2if this thread goes on marine subsea pipeline, is in the range from 2 to 7°C. Therefore, the temperature of the combined stream will be an average temperature between the temperature of the incoming of the flow of CO2and the temperature of the cooled stream. Typically, the temperature of the combined stream is in the range from 5 to 15°C, for example, from 12 to 15°C, depending on the extent to which the compressed and cooled stream was mixed with the stream coming from CO2.

It was noted that the ratio of the cooled stream (from step (g)) to the stream coming from CO2with time will grow, thanks to an ever-increasing volumes of injected CO2 extracted from a header of the hydrocarbons that will increase the volume of incoming vapor stream, which must be pumped back into the reservoir. Usually these two streams are mixed with the formation of the combined stream in such a ratio at which the molar % CO2in the combined stream is at least 70 mol.%, preferably, at least 80 mol.%, even more preferably, at least 85 mol.%. Typically the cooled stream is mixed with the stream coming from CO2with the formation of the combined stream in the amount of from 50 to 200 million STD. cubic feet/day (1.4 to 5.6 million cubic meters per day), preferably from 75 to 200 million STD. cubic feet/day (from 2.1 to 5.6 million cubic meters per day) (depending on the received vapor stream from which is formed the cooled stream).

It is assumed that the mixture flowing from the flow of CO2with the cooled stream can be performed on the injection equipment located on the platform, if it is the marine reservoir hydrocarbons, or ground injection equipment, if the collector of hydrocarbons located under the ground or in the coastal zone.

Usually for mixing the incoming of the flow of CO2with the cool flow using a flow mixing device. E.g. the measures mentioned mixing device has an input for the coming of the flow of CO2the entrance to the cooled stream and an outlet for the combined flow. Mentioned mixing device can have, for example, a static mixer or propeller mixer, which ensures uniform mixing of the two mentioned threads with the formation of the combined stream. This combined stream is usually sent to pipelines for further transportation mentioned combined stream to one or more injection wells and later in the header.

The cooled stream formed in step (g)may not be two-phase, since the pressure of the composition of the obtained vapor flow is above the maximum pressure at which can coexist two phases of gas and liquid. The cooled stream will be in pulse dense phase state (i.e., to have properties similar to the properties of the fluid). Therefore, the cooled stream and the stream coming from CO2(which may be either in the liquid or supercritical state) are characterized by high Miscibility and mixing quickly form a combined stream, which is a single homogeneous phase.

The combined stream formed in step (e), cannot be mushy because of the composition of the combined stream will be higher than the value of maximum pressure, where can coexist two phases of gas and liquid. Therefore, there is no risk of separation of the vapor phase from the combined stream into the injection well and therefore there is no risk of the presence of the phase tube into the injection well.

Typically, injection wells comprise at least one system of pipes, wells, tightly connected with the borehole wall. Typically, such a system (system) pipes injected into the injection well to the mark, bordering the reservoir hydrocarbons to which you want to upload referred to the combined stream. It is assumed that such a system (system) pipes in injection wells (wells used for injection of the combined stream in the manifold may have an internal diameter ranging from 3 to 12 inches (7.6 to 30.5 cm), preferably from 4 to 8 inches (10.2 to 20.3 cm), in particular from 4.5 to 7 inches (from 11,4 to 17.8 cm). However, in cases when the mixture cooled stream coming from the direction of flow of CO2is slow, you may need to use pipes of a smaller diameter, for example, pipes with an internal diameter of 4.5 " (11,4 cm).

If the collector is characterized by the phenomenon of cracking due to thermal shock, it may be necessary to increase the diameter of the pipe h is gnetales well to the combined stream can be injected into the reservoir in an amount sufficient to maintain cooling of the porous rock collector. Therefore, the combined stream will have a lower heat capacity compared with the heat capacity of water (for example, pure liquefied CO2has a specific heat capacity, which is about half the calorific value of water). In addition, the combined stream typically has a discharge temperature at the wellhead around 12°C, compared with a temperature of about from 4 to 7°C for pumped water. Therefore, to maintain the cooling manifold and thereby prevent closing of the cracks, we need more high speed injection into the reservoir.

The resulting flow of fluid may be directed at the processing facility on normal commercial pipeline or pipeline connecting the offshore platform with underwater field. Technological object can be onshore terminal, an offshore drilling platform or floating oil storage offloading unit (FPSO). Technological object, as a rule, includes the step of separating gas/liquid - for the Department received vapor stream from the received stream of fluid; a step of separation of liquid hydrocarbons/water - for separating the flow of liquid hydrocarbons (e.g., raw is not the ti) from the stream associated water; a compression step for compressing the selected vapor stream; and a cooling step for cooling the compressed stream.

Typically, the extracted fluid is supplied to the technological object at an elevated temperature, for example at a temperature in the range from 35 to 100°C, in particular from 75 to 100°C, for example, from 90 to 100°C. However, the exact temperature of the produced fluid will depend on the depth of the reservoir hydrocarbons and the degree of cooling of the produced fluid as the fluid rises to the surface for operating the well (and for any pipeline connecting the offshore platform with underwater field, field pipelines and so on).

Typically, the produced fluid has a lower pressure before it will be sent to the step of separation of gas/liquid on the technological object on which the vapor stream comprising volatile hydrocarbons and carbon dioxide, are separated from the produced fluid to at least one gas-liquid separator. Preferably, the technological object includes several consecutive gas-liquid separators, for example, from 2 to 4 gas-liquid separators. Further, the method proposed in the present invention will be illustrated in example 2 consecutive gas-liquid separators. Vapor stream, the rationale for asno to pick out the top or near the top of the first of the consecutive gas-liquid separators. It is advisable that vapor flow is released from the first gas-liquid separator under pressure in the range from 30 to 50 bar (3 to 5 MPa abs., for example, from 35 to 45 bar (3.5 to 4.5 MPa) abs. Usually the vapor stream exits the first gas-liquid separator at a temperature in the range from 35 to 100°C, for example, from 75 to 100°C, in particular at a temperature of about 90°C. Vapor stream is subjected to cooling to a temperature of about 25 to 30°C in a heat exchanger by heat exchange with a cooling agent, for example with a mixture of water / glycol in the resulting liquid from the vapor stream forms a condensate which is separated from the second of consecutive gas-liquid separators. The obtained vapor stream is withdrawn from the top or near the top of the second gas-liquid separator. The obtained vapor stream is preferably directed to dehydration, for example, by omitting the above-mentioned flow through at least one layer in the drying reagent (consisting, for example, molecular sieves or silica gel). Part of the resulting vapor stream may bypass the above-mentioned layer drying of the reagent before this thread will be again connected with the ferry that went to dehydration. This is an advantage of the present method, since dehydration is a potential of the Noah "bottleneck" methods for the treatment of vapor-phase flows. However, for reasons of control of technical condition of the well (for example, for reasons of control of corrosion), the amount of water to the volume pair in the resulting vapor stream must be less than 50 ppm million while reducing the pressure of the received fluid in most cases is sufficient for removal of volatile hydrocarbons and CO2from the produced liquid hydrocarbons and produced water, the resulting fluid, which is directed to a gas-liquid separator (separator) technological object, may be subjected to heat for faster and more complete removal of volatile hydrocarbons and CO2from the produced liquid hydrocarbons and associated water.

The obtained vapor stream is then directed to step compression process the object on which the vapor stream is compressed to a pressure greater than the pressure value, which can coexist two phases of gas and liquid, the composition of the obtained vapor stream, with the formation thereby compressed vapor stream. As a rule, to compress the vapor stream using at least one low-pressure compressor, preferably, two or three low-pressure compressor. Compared with the obtained vapor stream, after compression, this flow has a higher temperature due to the heat of compression.

Compressed stream C is sent to the step of cooling the process object, where, as a rule, use a heat exchanger in which cooling occurs, for example, by heat exchange with water with the formation of the cooled compressed stream, which is a pulse dense phase condition (see above).

Liquid-phase stream composed of a mixture of liquid hydrocarbons and water away from the bottom or near the bottom of each of the gas-liquid separators used in the splitting step, the gas processing facility. Obtained such liquid streams are combined and the combined liquid stream is directed to the step of separation of liquid hydrocarbons and water processing facility, which combined liquid-phase stream is separated into a stream of liquid hydrocarbons and water flow. Step separation of liquid hydrocarbons and water, typically includes at least one separator liquid hydrocarbons/water, preferably several consecutive separators liquid hydrocarbons/water. The principle of operation of the separator (separator) to separate the liquid hydrocarbons and water is well known to specialists in this field of technology. Any resulting steam, which is separated from the combined liquid stream in step separation of liquid hydrocarbons and water, can be used either as fuel gas, or may be combined with the vapor pot is kOhm, obtained in step separation of gas/liquid.

Where it is proposed to use the existing capacities of the discharge gas, a part of the compressed stream (in the amount not exceeding production capacity for gas charging current injection equipment) direct at least one gas-injection compressor. Gas-injection compressor (the compressor is a compressor operating at high pressure, which can further compress the gas, raising the pressure of the compressed gas stream to the desired pressure at the mouth of the injection well (thus forming a discharge stream that is in the vapor phase). The pressure at the wellhead for gas-injection wells will depend on the pressure manifold. Typically, the pressure at the wellhead is in the range from 250 to 450 bar (25 to 45 MPa abs., for example, from 350 to 400 bar (35 to 40 MPa) abs. The pressurized stream is in the vapor phase due to the heat of compression. Thus, with reference to the model diagram of phase equilibria for multicomponent composition (figure 1), the heat of compression will help to ensure that the values of the temperature of the exhaust stream will be located to the right of the maximum temperature, which can coexist two phases of gas and liquid. Therefore, as discussed the axis above mentioned injection flow is considered as a vapor, even though its pressure exceeds the maximum pressure, which can coexist two phases of gas and liquid.

As noted above, the combined stream is pulse dense phase condition. Therefore, the temperature of this combined stream below the maximum temperature, which can coexist two phases of gas and liquid, preferably below the temperature at the critical point for the composition mentioned combined stream.

In those cases where the injection well was stopped and the column of fluid combined stream into the injection well is heated to the values of the geothermal gradient, you may need to re-run this injection well using flow coming from CO2by applying additional forcing due to the low gravitational pressure in the injection well. Injection combined stream will be started again after the heated column of fluid will be displaced into the reservoir when using the coming of the flow of CO2.

An alternative method of placing the combined flow of fluid from the pumping of water (where there is more than one injection well) may represent the manage benefits in the early stages of discharge CO 2.

It is advisable that the injected water would be produced water, which was separated from the extracted liquid hydrocarbons in the separator (the separator) to separate the liquid hydrocarbons/water. In the later stages of injection water should be avoided because the water will occupy the space required for the sequestration of CO2.

Further, the present invention is disclosed in the following description and illustrated in the accompanying drawings, in which:

Figure 1 shows a typical diagram of phase equilibria for multicomponent composition. The region, located in the center of the diagram phase equilibria, is a two-phase structure. The area to the left in the diagram phase balance represents the liquid phase, and the region on the right - vapour phase; the area located in the center of the diagram phase equilibria, is a two-phase structure, and the area located at the top (above recondenser, i.e. the point of maximum pressure, which can coexist two phases of gas and liquid) - solid phase.

The term "maximum pressure, which can coexist two phases of gas and liquid (recondenser) means the highest pressure at which coexist the two above-mentioned phases. Therefore, where the pressure previse the value of the maximum pressure, where can coexist two phases of gas and liquid, multicomponent composition cannot be two-phase (liquid and vapor).

The term "maximum temperature at which can coexist two phases of gas and liquid" (cricondentherm), means the highest temperature at which coexist the two above-mentioned phases.

The term "critical point" for multicomponent composition is experimentally determined point, which represents a point (temperature and pressure) on the diagram of phase equilibria in which the properties of the mixture in the vapor phase and the liquid phase are equal.

The terms "maximum pressure, which can coexist two phases of gas and liquid, maximum temperature, which can coexist two phases of gas and liquid", "critical point"used in the present invention, relate to the composition of the thread in question.

Figure 2 thread 1 received from CO2,served in a mixing apparatus 2 by the pump 3. The obtained vapor stream 4, consisting of volatile hydrocarbons and CO2direct compression in the compressor 5 to the pressure of stream 1, coming from CO2, thus forming a compressed stream 6, the pressure above the maximum pressure at which can coexist two phases of gas and liquid, the La composition obtained vapor stream 4. Compressed stream 6 is then sent to the cooling in the heat exchanger 7, using as a cooling agent is water, in which it is cooled to a temperature less than 30°C, preferably to a temperature of from 20 to 25°C, with the formation of the cooled stream 8, which represents the pulse dense phase flow. The cooled stream 8 is further directed to a mixing device 2 where it is mixed with stream 1, coming from CO2with education combined stream 9, which represents the pulse dense phase flow. Referred to the joint 9 is a flow single-phase flow that can be pumped into the reservoir of hydrocarbons (not shown) via the injection well (not shown).

1. Way to store CO2in porous and permeable reservoir of hydrocarbons, which penetrates at least one injection well and at least one operational borehole, comprising the following stages:
(a) removing from operating wells flow of produced fluid, consisting of extracted hydrocarbons, water, and CO2;
(b) the direction of flow of the produced fluid at the processing facility, where this flow of fluid is separated vapor stream comprising carbon dioxide and volatile hydrocarbons;
(in) compression ratio obtained vapor stream to a pressure above the maximum pressure the Oia, where can coexist two phases of gas and liquid, the composition of the obtained vapor stream;
(g) cooling the compressed stream with the formation of the cooled stream into pulse dense phase condition;
(d) the direction of injection equipment coming from the flow of CO2that can be either in liquid phase or in a supercritical state;
(e) mixing the cooled stream from step (g) with the stream coming from CO2with the formation of the combined stream, a flow pulse dense phase of matter; and
(g) pumping-mentioned combined stream into the reservoir of hydrocarbons via the injection well.

2. The method according to claim 1, where the reservoir of hydrocarbons has several injection wells, including at least one gas-injection well and/or well for alternating injection of water and gas, and at least one water injection well and/or well designed for injection combined stream, and in the exercise of which:
part of the resulting vapor stream separated in stage (b), is injected into the vapor state in the gas-injection well and/or well for alternating injection of water and gas;
the remaining part of the above mentioned vapor stream separated in stage (b), is used as the Otok, fed to stage (b); and
the combined stream obtained in stage (e), pumped at least one water injection well and/or well, designed to pump combined stream.

3. The method according to claim 1, in which essentially all the obtained vapor stream is separated in stage (b), used for direction on stage (in).

4. The method according to claim 3, in which the reservoir of hydrocarbons has several existing injection wells, selectable from the gas-injection wells, wells for alternating injection of water and gas and water injection wells, and these existing injection wells is transferred to the injection mentioned combined stream.

5. The method according to claim 4, in which the collector hydrocarbon has at least one injection well, designed for pumping combined stream, and at least part of these combined stream is injected into this injection well.

6. The method according to claim 1, in which the injection mentioned combined stream into the reservoir of hydrocarbons increases the production of liquid hydrocarbons from the reservoir.

7. The method according to claim 1, in which the vapor stream is separated in stage (b)has a content of CO2less than 15 vol.%, and part of the resulting vapor stream is used in quality is the firmness of the fuel gas to one or more generators of electricity, used at the above-mentioned technological object and/or injection equipment.

8. The method according to claim 1, in which the vapor stream is separated in stage (b)has a content of CO2more than 50 vol.%, and at least part of the obtained vapor stream is used to produce fuel gas for one or more generators of electricity used at the above-mentioned technological object and/or injection equipment, passes through the mentioned parts of the resulting vapor flow through the membrane module for separating fuel gas with a content of CO2less than 15% vol. and exhaust stream enriched in CO2and mentioned exhaust stream re-unite with the rest of the obtained vapor stream prior to compression of the obtained vapor stream at the stage (b).

9. The method according to claim 1, in which the incoming side stream CO2is a by-product obtained in the plant, the plant producing hydrogen, an installation for the separation of natural gas or on the plant to produce ammonia.

10. The method according to claim 1, in which the incoming side stream CO2is at least 98% of the CO2in terms of dry substance.

11. The method according to claim 1, in which the incoming side stream CO2send to magnetfeld the mu hardware pipeline, in which pressure is in the range from 75 to 250 bar (7.5 to 25 MPa) abs.

12. The method according to claim 1, in which the incoming side stream CO2bring to pressure equipment in the tanker.

13. The method according to claim 1, in which the incoming side stream CO2mix with the cooled stream in stage (e) when the supply pressure coming from the side of the flow of CO2and , if necessary, the pressure of the combined stream is subsequently further expanded to the desired pressure at the mouth of the injection wells.

14. The method according to claim 1, in which the combined stream is injected into the injection well at a pressure in the range from 100 to 350 bar from 10 to 35 MPa abs.

15. The method according to claim 1, in which the reservoir of hydrocarbons is uglevodosoderjati geological horizon below him aquifer, communicating with uglevodosoderjati geological horizon, and referred to the combined stream is injected into the aquifer.

16. The method according to claim 1, in which mentioned the combined stream is injected through injection well located on the edge of the periphery of the collector.

17. The method according to claim 1, where the reservoir of hydrocarbons is not horizontally-lying layer and in which the combined stream is injected into the low-lying point of such header.

18. JV the property according to claim 1, in which the collector is used for underground pumped storage CO2for at least 1000 years.

19. The method according to claim 1, in which the compressed stream is cooled in step (g) through its passes through the heat exchanger and heat exchange with a cooling agent.

20. The method according to claim 1, in which the compressed stream is cooled in stage (d) to a temperature in the range from 10° to 40°C, preferably from 20° to 30°C.

21. The method according to claim 1, in which the combined stream formed in stage (e), has a temperature in the range of 5° to 15°C.

22. The method according to claim 1, in which the incoming side stream CO2and the cooled stream in stage (g) is mixed at stage (e) to form combined stream in such a ratio that the molar % CO2in this merged thread was at least 70 mol.%, preferably at least 80 mol.%, more preferably at least 85 mol.%.



 

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5 dwg

FIELD: transport.

SUBSTANCE: device for batching and transportation of powder and/or loose solid material in a range of low or high pressure has housing containing inlet with input valve in input area, outlet with output valve in output area and linear drive actuating piston with variable speed of forward movement respectively back. The piston is made at least partially as hollow body with internal piston space and with at least one inward hole to accept material into internal piston space and outward hole to extract material from internal piston space. The piston at driving side rests on sealing support and is sealed by it relative to atmosphere, and at nondriving side the piston rests on scraping support which seals input area from output area relative to passage of solid material. In this device, there is bypass connecting input area and output area and there are pressure reducing valve and loading valve to establish pressure in internal device space including input area and output area.

EFFECT: invention provides better batching and transportation of materials without their compaction while providing equal pressures before and behind scraper support and excluding material throw-over.

22 cl, 8 dwg

FIELD: oil and gas production.

SUBSTANCE: proposed device comprises water feed tube with bottom head Note here that the latter features length exceeding radius of reservoir and is made of flexible water feed tube furnished with mechanical muscles secured thereto and pneumatically or hydraulically communicated with pressure source to control every muscle for positioning tube end in space.

EFFECT: higher efficiency.

3 dwg

FIELD: transport.

SUBSTANCE: invention relates to power machine building. When powdery medium is transferred from bin to transmission pipeline via inlet valve powdery medium piston formation of design volume and density is created in transmission pipeline by means of affecting the powdery medium by at least one pneumatic impact of compressed air which volume is less than design volume of piston formation. At the same time, design air pressure is established in the first receiver. Compressed air is fed to transmission pipeline in the form of air-blast to act on powdery medium piston formation. After pneumatic impact on powdery medium from the first receiver, feed in transmission pipeline is performed sequentially from several receivers with interrupters of additional pneumatic impacts in the form of air-blasts created in boost sections of pipelines between each interrupter and transmission pipeline after the inlet valve has been closed, and time of sequential feed of additional pneumatic impacts is chosen less than time of powdery medium movement to transmission pipeline section.

EFFECT: invention provides increase in transportation range and longer life of pneumatic system units.

1 dwg

FIELD: transport.

SUBSTANCE: invention relates to power machine building. When powdery medium is transferred from bin to transmission pipeline via inlet valve powdery medium piston formation of design volume and density is created in transmission pipeline by means of affecting the powdery medium by at least one pneumatic impact of compressed air which volume is less than design volume of piston formation. At the same time, design air pressure is established in the first receiver. Compressed air is fed to transmission pipeline in the form of air-blast to act on powdery medium piston formation. After pneumatic impact on powdery medium from the first receiver, feed in transmission pipeline is performed sequentially from several receivers with interrupters of additional pneumatic impacts in the form of air-blasts created in boost sections of pipelines between each interrupter and transmission pipeline after the inlet valve has been closed, and time of sequential feed of additional pneumatic impacts is chosen less than time of powdery medium movement to transmission pipeline section.

EFFECT: invention provides increase in transportation range and longer life of pneumatic system units.

1 dwg

FIELD: oil and gas extractive industry.

SUBSTANCE: method includes performing a test pumping of liquid waste into absorbing well before operational pumping, while changing flow step-by-step. From equation of absorption base hydrodynamic parameters are determined for calculation of predicted coefficients of operation characteristics of absorbing well and reserve well. During operational pumping of liquid waste together with thermometry along absorbing well shaft, registration of actual pressures and flow on pump devices, actual pressures on mouth in tubing pipes of absorbing well, actual pressures on face are additionally registered in absorbing well as well as pressures on mouth in behind-pipe space, actual loss at mouth in behind-pipe space, actual loss of waste on mouth, actual positions of face well, upper and lower limits of absorption range from well mouth. In reserve well actual pressures on face are registered, as well as actual positions of liquid level from reserve well mouth, upper and lower limits of absorption range. Prediction coefficients are compared for operation characteristics of absorbing well and reserve well to actual coefficients. 9 conditions of hydrodynamic bed conditions at reserve well and absorbing well are considered during pumping of waste. Specific actions of operator on each condition are described.

EFFECT: higher reliability and trustworthiness.

1 ex

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