Associated petroleum gas composition application. Associated petroleum gas: composition

Associated petroleum gas

Associated petroleum gas (PNG) - a mixture of various gaseous hydrocarbons dissolved in oil; they are released during the extraction and distillation process (these are the so-called associated gases, mainly consist of propane and isomers of butane). Petroleum gases also include oil cracking gases, consisting of saturated and unsaturated (ethylene, acetylene) hydrocarbons. Petroleum gases are used as fuel and for the production of various chemicals. Propylene, butylenes, butadiene, etc. are obtained from petroleum gases by chemical processing, which are used in the production of plastics and rubbers.

Compound

Associated petroleum gas - a mixture of gases released from hydrocarbons of any phase state, consisting of methane, ethane, propane, butane and isobutane, containing high molecular weight liquids dissolved in it (from pentanes and higher in the growth of the homologous series) and various composition and phase state of impurities.

Approximate composition of APG

Receipt

APG is a valuable hydrocarbon component released from mined, transported and processed minerals containing hydrocarbons at all stages of the investment life cycle until the sale of finished products to the end consumer. Thus, a feature of the origin of associated petroleum gas is that it is released at any stage from exploration and production to final sale, from oil, gas, (other sources are omitted) and in the process of their processing from any incomplete product state to any of the numerous final products.

A specific feature of APG is usually an insignificant flow rate of the resulting gas, from 100 to 5000 nm³/hour. The content of hydrocarbons СЗ + can vary in the range from 100 to 600 g/m³. At the same time, the composition and amount of APG is not a constant value. Both seasonal and one-time fluctuations are possible (normal value change up to 15%).

The gas from the first separation stage is usually sent directly to the gas processing plant. Significant difficulties arise when trying to use a gas with a pressure of less than 5 bar. Until recently, such gas in the vast majority of cases was simply flared, however, now, due to changes in the state policy in the field of APG utilization and a number of other factors, the situation is changing significantly. In accordance with Decree of the Government of the Russian Federation of January 8, 2009 No. 7 “On Measures to Stimulate the Reduction of Atmospheric Air Pollution by Products of Associated Petroleum Gas Combustion at Flaring Plants”, a target indicator for associated petroleum gas flaring was set at no more than 5 percent of the amount of associated petroleum gas produced oil gas. Currently, the volumes of produced, utilized and flared APG cannot be estimated due to the absence of gas metering stations at many fields. But according to rough estimates, it is about 25 billion m³.

Ways of disposal

The main ways of APG utilization are processing at the GPP, power generation, combustion for own needs, injection back into the reservoir for the stimulation of oil recovery (maintaining reservoir pressure), injection into production wells - the use of "gas lift".

APG utilization technology

Gas flare in the West Siberian taiga in the early 1980s

The main problem in the utilization of associated gas is the high content of heavy hydrocarbons. To date, there are several technologies that improve the quality of APG by removing a significant portion of heavy hydrocarbons. One of them is the preparation of APG using membrane plants. When using membranes, the methane number of the gas is significantly increased, the net calorific value (LHV), thermal equivalent and dew point temperature (for both hydrocarbons and water) are reduced.

Membrane hydrocarbon plants can significantly reduce the concentration of hydrogen sulfide and carbon dioxide in the gas flow, which allows them to be used for gas purification from acidic components.

Design

Scheme of distribution of gas flows in the membrane module

By its design, the hydrocarbon membrane is a cylindrical block with permeate outlets, product gas and APG inlet. Inside the block is a tubular structure of a selective material that only allows certain types of molecules to pass through. The general flow diagram inside the cartridge is shown in the figure.

Principle of operation

The installation configuration in each specific case is determined specifically, since the initial composition of APG can vary greatly.

Installation diagram in basic configuration:

Pressure scheme for APG treatment

Vacuum scheme of APG preparation

• Pre-separator for cleaning from coarse impurities, large condensed moisture and oil,
• input receiver,
• Compressor,
• Refrigerator for aftercooling gas to a temperature of +10 to +20 °C,

• Fine gas filter to remove oil and paraffin compounds,
• Hydrocarbon Membrane Block,
• instrumentation,
• Control system including flow analysis,
• Condensate disposal system (from separators),
• permeate recovery system,
• Container delivery.

The container must be manufactured in accordance with the requirements of fire and explosion safety in the oil and gas industry.

There are two APG treatment schemes: pressure and vacuum.

The basis of associated petroleum gas is a mixture of light hydrocarbons, including methane, ethane, propane, butane, isobutane and other hydrocarbons that are dissolved in oil under pressure (Fig. 1). APG is released when pressure is reduced during oil recovery or during separation, similar to the process of carbon dioxide release when opening a bottle of champagne. As the name implies, associated petroleum gas is produced along with oil and, in fact, is a by-product of oil production. The volume and composition of APG depends on the production area and the specific properties of the field. In the process of extraction and separation of one ton of oil, from 25 to 800 m3 of associated gas can be obtained.

Flaring of associated petroleum gas in field flares is the least rational way to use it. With this approach, APG becomes, in fact, a waste product of the oil production process. Flaring can be justified under certain conditions, however, as world experience shows, an effective state policy makes it possible to achieve a level of APG flaring in the amount of several percent of the total volume of its production in the country.

Currently, there are two most common ways to use associated petroleum gas, alternative to flaring. Firstly, this is the injection of APG into oil-bearing formations to increase oil recovery or to possibly save it as a resource for the future. The second option is the use of associated gas as a fuel for power generation (Scheme 1) and the needs of the enterprise at oil production sites, as well as for generating electricity and transferring it to the general power grid.

At the same time, the option of using APG for power generation is also a way of burning it, only a little more rational, since in this case it is possible to obtain a beneficial effect and somewhat reduce the impact on the environment. Unlike natural gas, which has a methane content in the range of 92-98%, associated petroleum gas contains less methane, but often has a significant proportion of other hydrocarbon components, which can reach more than half of the total volume. APG may also contain non-hydrocarbon components - carbon dioxide, nitrogen, hydrogen sulfide, and others. As a result, associated petroleum gas by itself is not a sufficiently efficient fuel.

The most rational option is the processing of APG - its use as a feedstock for gas and petrochemistry - which makes it possible to obtain valuable products. As a result of several stages of associated petroleum gas processing, materials such as polyethylene, polypropylene, synthetic rubbers, polystyrene, polyvinyl chloride and others can be obtained. These materials, in turn, serve as the basis for a wide range of goods, without which the modern life of a person and the economy is unthinkable, including: shoes, clothing, containers and packaging, dishes, equipment, windows, all kinds of rubber products, cultural and household goods. applications, pipes and pipeline parts, materials for medicine and science, etc. It should be noted that APG processing also makes it possible to isolate dry stripped gas, which is an analogue of natural gas, which can already be used as a more efficient fuel than APG.

The indicator of the level of recovered associated gas used for gas and petrochemistry is a characteristic of the innovative development of the oil and gas and petrochemical industry, of how efficiently hydrocarbon resources are used in the country's economy. The rational use of APG requires the availability of an appropriate infrastructure, effective state regulation, an assessment system, sanctions and incentives for market participants. Therefore, the share of APG used for gas and petrochemistry can also characterize the level of the country's economic development.

Achieving a 95-98% level of utilization of associated petroleum gas recoverable on a national scale and a high degree of its processing to obtain valuable products, including gas and petrochemicals, are one of the important directions for the development of the oil and gas and petrochemical industry in the world. This trend is typical for developed countries rich in hydrocarbon raw materials, such as Norway, the USA and Canada. It is also characteristic of a number of countries with economies in transition, such as Kazakhstan, as well as developing countries, such as Nigeria. It should be noted that Saudi Arabia, the world's leader in oil production, is becoming one of the leaders in the world's gas and petrochemistry.

Currently, Russia occupies the "honorable" first place in the world in terms of APG flaring. In 2013, this level, according to official data, was about 15.7 billion m3. At the same time, according to unofficial data, the volume of associated petroleum gas flaring in our country can be much higher - at least 35 billion m3. At the same time, even based on official statistics, Russia is significantly ahead of other countries in terms of APG flaring. According to official data, the level of APG use by methods other than flaring in our country in 2013 averaged 76.2%. Of these, 44.5% went for processing at gas processing plants.

Demands to reduce the level of APG flaring and increase the share of its processing as a valuable hydrocarbon feedstock have been put forward by the leadership of our country over the past few years. Currently, there is a Decree of the Government of the Russian Federation No. 1148 dated 08.11.2012, according to which oil companies are required to pay high fines for excess combustion - more than 5% level.

It is important to note that the accuracy of official statistics regarding the level of recycling raises serious doubts. According to experts, a significantly smaller share of the extracted APG is processed - about 30%. And far from all of it is used to obtain gas and petrochemical products, a significant part is processed to produce electricity. Thus, the real share of the effective use of APG - as a feedstock for gas and petrochemistry - can be no more than 20% of the total volume of APG produced.

Thus, even on the basis of official data, considering only the volumes of APG flaring, we can conclude that more than 12 million tons of valuable petrochemical raw materials are lost annually, which could be obtained by processing associated petroleum gas. This raw material could be used to produce important products and goods for the domestic economy, it could become the basis for the development of new industries, the creation of new jobs, including for the purpose of replacing imported products. According to the World Bank estimates, the additional income of the Russian economy from qualified APG processing could amount to more than $7 billion annually, and according to the Ministry of Natural Resources and Ecology, our economy loses $13 billion every year.

At the same time, if we take into account the volumes of associated gas flaring in the oil fields for our own needs and power generation, the possibility of obtaining raw materials and, accordingly, additional benefits for the economy of our country can be twice as high.

The reasons for the irrational use of associated gas in our country are associated with a number of factors. Often, oil production sites are located far from the infrastructure for collecting, transporting and processing petroleum gas. Limited access to the main gas pipeline system. The lack of local consumers of APG processing products, the lack of cost-effective solutions for rational use - all this leads to the fact that the easiest way out for oil companies is often the flaring of associated gas in the fields: in flares or for power generation and household needs. It should be noted that the prerequisites for the irrational use of associated petroleum gas were formed at the initial stages of the development of the oil industry, back in the Soviet period.

Currently, insufficient attention is paid to assessing the economic losses of the state from irrational use - the burning of associated petroleum gas in the fields. However, APG flaring causes significant damage not only to the economy of oil-producing countries, but also to the environment. Environmental damage is most often cumulative and leads to long-term and often irreversible consequences. In order for the assessments of environmental damage and economic losses not to be averaged and one-sided, and for the motivation to solve the problem to be meaningful, it is necessary to take into account the scale of our country and the interests of all parties.

Associated petroleum gas (APG), as the name implies, is a by-product of oil production. Oil lies in the ground along with gas, and it is technically practically impossible to ensure the production of an exclusively liquid phase of hydrocarbon raw materials, leaving the gas inside the reservoir.

At this stage, it is gas that is perceived as an associated raw material, since world oil prices determine the greater value of the liquid phase. Unlike gas fields, where all production and technical characteristics of production are aimed at extracting exclusively the gaseous phase (with an insignificant admixture of gas condensate), oil fields are not equipped in such a way as to effectively conduct the process of production and utilization of associated gas.

Further in this chapter, the technical and economic aspects of APG production will be considered in more detail, and based on the conclusions obtained, parameters will be selected for which an econometric model will be built.

General characteristics of associated petroleum gas

Description of the technical aspects of hydrocarbon production begins with a description of the conditions of their occurrence.

Oil itself is formed from the organic remains of dead organisms that settle on the sea and river bottom. Over time, water and silt protected the substance from decomposition, and as new layers accumulated, pressure on the underlying layers increased, which, together with temperature and chemical conditions, caused the formation of oil and natural gas.

Oil and gas go together. Under conditions of high pressure, these substances accumulate in the pores of the so-called parent rocks, and gradually, undergoing a process of continuous transformation, rise up with microcapillary forces. But as you go up, a trap can form - when a denser reservoir covers the reservoir along which hydrocarbon migrates, and thus accumulation occurs. At the moment when a sufficient amount of hydrocarbons has accumulated, the process of displacement of initially salty water, heavier than oil, begins to take place. Further, the oil itself is separated from the lighter gas, but part of the dissolved gas remains in the liquid fraction. It is the separated water and gas that serve as tools for pushing oil outward, forming water or gas pressure regimes.

Based on the conditions, the depth of occurrence and the contour of the area of ​​occurrence, the developer selects the number of wells to maximize production.

The main modern type of drilling used is rotary drilling. In this case, drilling is accompanied by a continuous rise of drill cuttings - fragments of the formation, separated by a drill bit, to the outside. At the same time, to improve drilling conditions, a drilling fluid is used, often consisting of a mixture of chemical reagents. [Gray Forest, 2001]

The composition of associated petroleum gas will vary from field to field, depending on the entire geological history of the formation of these deposits (source rock, physical and chemical conditions, etc.). On average, the proportion of methane content in such a gas is 70% (for comparison, natural gas contains up to 99% of methane in its composition). A large amount of impurities creates, on the one hand, difficulties for gas transportation through the gas transmission system (GTS), on the other hand, the presence of such extremely important components as ethane, propane, butane, isobutane, etc. makes associated gas an extremely desirable raw material for petrochemical production . The oil fields of Western Siberia are characterized by the following indicators of hydrocarbon content in associated gas [Popular petrochemistry, 2011]:

• Methane 60-70%
• Ethane 5-13%
• Propane 10-17%
• Butane 8-9%

TU 0271-016-00148300-2005 "Associated petroleum gas to be delivered to consumers" defines the following categories of APG (according to the content of C 3 ++ components, g/m 3):

• "Skinny" - less than 100
• "Medium" - 101-200
• "Bold" - 201-350
• Extra fat - more than 351

The following figure [Filippov, 2011] shows the main activities carried out with associated petroleum gas and the effects achieved by these activities.

Figure 1 - The main activities carried out with APG and their effects, source: http://www.avfinfo.ru/page/engineering-002

During oil production and further stepwise separation, the released gas has a different composition - the very first gas is released with a high content of methane fraction, at the next stages of separation, gas is released with an increasing content of hydrocarbons of a higher order. The factors influencing the release of associated gas are temperature and pressure.

A gas chromatograph is used to determine the associated gas content. When determining the composition of associated gas, it is also important to pay attention to the presence of non-hydrocarbon components - for example, the presence of hydrogen sulfide in the APG composition can adversely affect the possibility of gas transportation, since corrosion processes can occur in the pipeline.

Figure 2 - Scheme of oil treatment and APG accounting, source: Skolkovo Energy Center

Figure 2 schematically depicts the process of stage-by-stage refinement of oil with the release of associated gas. As can be seen from the figure, associated gas is, for the most part, a by-product of the primary separation of hydrocarbons produced from an oil well. The problem of associated gas metering is the need to install automatic metering devices at several stages of separation, and later on deliveries for utilization (GPP, boiler houses, etc.).

The main installations used at production sites [Filippov, 2009]:

• Booster pumping stations (DNS)
• Oil separation units (USN)
• Oil treatment plants (UPN)
• Central oil treatment facilities (CPP)

The number of stages depends on the physicochemical properties of the associated gas, in particular, on factors such as gas content and gas factor. Often the gas from the first separation stage is used in furnaces to generate heat and preheat the entire mass of oil in order to increase the gas yield in the subsequent separation stages. For driving mechanisms, electricity is used, which is also generated in the field, or main power networks are used. Gas-piston power plants (GPES), gas turbine (GTS) and diesel generators (DGU) are mainly used. Gas facilities operate on gas of the first stage of separation, diesel station operates on imported liquid fuel. The specific type of power generation is selected based on the needs and characteristics of each individual project. The GTPP can in some cases generate excess electricity for neighboring oil production facilities, and in some cases the rest can be sold on the wholesale electricity market. With the cogeneration type of energy production, the installations simultaneously produce heat and electricity.

Flare lines are a mandatory attribute of any field. Even if they are not used, they are necessary to burn excess gas in an emergency.

From the point of view of the economics of oil production, investment processes in the field of associated gas utilization are quite inertial, and are primarily focused not on market conditions in the short term, but on the totality of all economic and institutional factors on a fairly long-term horizon.

The economic aspects of hydrocarbon production have their own specifics. The peculiarity of oil production is:

• Long-term nature of key investment decisions
• Significant investment lags
• Large initial investment
• Irreversibility of the initial investment
• Natural decline in production over time

In order to evaluate the effectiveness of any project, a common business valuation model is the NPV estimate.

NPV (Net Present Value) - the assessment is based on the fact that all future estimated income of the company will be summed up and reduced to the present value of these incomes. The same amount of money today and tomorrow differs by the discount rate (i). This is due to the fact that in the period of time t=0 the money we have has a certain value. While in the time period t=1 inflation will be spread to these funds, there will be all sorts of risks and negative impacts. All this makes future money “cheaper” than current money.

The average life of an oil production project can be about 30 years, followed by a long shutdown of production, sometimes stretching for decades, which is associated with the level of oil prices and the payback of operating costs. Moreover, oil production reaches its peak in the first five years of production, and then, due to the natural decline in production, it gradually fades.

In the early years, the company makes large initial investments. But the production itself begins only a few years after the start of capital investments. Each company seeks to minimize the investment lag in order to reach the payback of the project as soon as possible.

A typical project profitability schedule is provided in Figure 3:

Figure 3 - NPV scheme for a typical oil production project

This figure shows the NPV of the project. The maximum negative value is the MCO indicator (maximum cash outlay), which is a reflection of how large investments the project requires. The intersection of the graph of the line of accumulated cash flows with the time axis in years is the payback time point of the project. The NPV accumulation rate is declining due to both the declining production rate and the time discount rate.

In addition to capital investments, annual production requires operating costs. An increase in operating costs, which may be the annual technical costs associated with environmental risks, reduces the NPV of the project and increases the payback period of the project.

Thus, additional costs for accounting, collection and disposal of associated petroleum gas can be justified from the point of view of the project only if these costs will increase the NPV of the project. Otherwise, there will be a decrease in the attractiveness of the project and, as a result, either a decrease in the number of projects being implemented, or the volumes of oil and gas production within one project will be adjusted.

Conventionally, all associated gas utilization projects can be divided into three groups:

• 1. The recycling project itself is profitable (taking into account all economic and institutional factors), and companies will not need additional incentives to implement.
• 2. The disposal project has a negative NPV, while the cumulative NPV from the entire oil production project is positive. It is on this group that all incentive measures can be concentrated. The general principle would be to create conditions (with benefits and penalties) under which it would be beneficial for companies to undertake recycling projects rather than pay penalties. And so that the total costs of the project do not exceed the total NPV.
• 3. Utilization projects have a negative NPV, and if they are implemented, the overall oil production project of this field also becomes unprofitable. In this case, incentive measures will either not lead to a reduction in emissions (the company will pay fines up to their cumulative cost equal to the NPV of the project), or the field will be mothballed and the license will be surrendered.

According to the Skolkovo Energy Center, the investment cycle in the implementation of APG utilization projects is more than 3 years.

Investments, according to the Ministry of Natural Resources, should amount to about 300 billion rubles by 2014 to achieve the target level. Based on the logic of the administration of projects of the second type, the rates of payments for pollution should be such that the potential cost of all payments would be more than 300 billion rubles, and the opportunity cost would be equal to the total investment.

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APG characteristic

Passingoilgas(PNG) is a natural hydrocarbon gas dissolved in oil or located in the “caps” of oil and gas condensate fields.

In contrast to the well-known natural gas, associated petroleum gas contains, in addition to methane and ethane, a large proportion of propanes, butanes and vapors of heavier hydrocarbons. Many associated gases, depending on the field, also contain non-hydrocarbon components: hydrogen sulfide and mercaptans, carbon dioxide, nitrogen, helium and argon.

When opening oil reservoirs, the gas of oil "caps" usually begins to flow first. Subsequently, the main part of the produced associated gas is gases dissolved in oil. The gas of gas "caps", or free gas, is "lighter" in composition (with a lower content of heavy hydrocarbon gases) in contrast to the gas dissolved in oil. Thus, the initial stages of field development are usually characterized by large annual production of associated petroleum gas with a larger proportion of methane in its composition. With long-term operation of the field, the debit of associated petroleum gas is reduced and a large proportion of gas falls on heavy components.

Passing oil gas is important raw materials For energy And chemical industry. APG has a high calorific value, which ranges from 9,000 to 15,000 Kcal/m3, but its use in power generation is hampered by the instability of the composition and the presence of a large amount of impurities, which requires additional costs for gas purification (“drying”). In the chemical industry, methane and ethane contained in APG are used for the production of plastics and rubber, while heavier elements serve as raw materials for the production of aromatic hydrocarbons, high-octane fuel additives and liquefied hydrocarbon gases, in particular, technical liquefied propane-butane (SPBT).

PNG in numbers

In Russia, according to official data, about 55 billion m3 of associated petroleum gas is extracted annually. Of these, about 20-25 billion m3 is burned in the fields and only about 15-20 billion m3 is used in the chemical industry. Most of the APG flared comes from new and hard-to-reach fields in Western and Eastern Siberia.

An important indicator for each oil field is the GOR of oil - the amount of associated petroleum gas per ton of oil produced. For each field, this indicator is individual and depends on the nature of the field, the nature of its operation and the duration of development, and can range from 1-2 m3 to several thousand m3 per ton.

Solving the problem of associated gas utilization is not only a matter of ecology and resource saving, it is also a potential national project worth $10-$15 billion. Associated petroleum gas is the most valuable fuel, energy and chemical raw material. Only the utilization of APG volumes, the processing of which is economically viable under the current market conditions, would make it possible to annually produce up to 5-6 million tons of liquid hydrocarbons, 3-4 billion cubic meters. ethane, 15-20 billion cubic meters dry gas or 60 - 70 thousand GWh of electricity. The possible cumulative effect will be up to $10 billion/year in domestic market prices, or almost 1% of the GDP of the Russian Federation.

In the Republic of Kazakhstan, the problem of APG utilization is no less acute. Currently, according to official data, out of 9 billion cubic meters. Only two-thirds of the APG produced annually in the country is utilized. The volume of flared gas reaches 3 billion cubic meters. in year. More than a quarter of the oil producing enterprises operating in the country burn more than 90% of the produced APG. Associated petroleum gas accounts for almost half of all gas produced in the country, and the growth rate of APG production is currently outpacing the growth rate of natural gas production.

APG utilization problem

The problem of utilization of associated petroleum gas was inherited by Russia from the Soviet times, when the emphasis in development was often placed on extensive methods of development. In the development of the oil-bearing provinces, the growth in the production of crude oil, the main source of income for the national budget, was at the forefront. The calculation was made on giant deposits, large-scale production and cost minimization. The processing of associated petroleum gas, on the one hand, was in the background due to the need to make significant capital investments in relatively less profitable projects, on the other hand, branched gas gathering systems were created in the largest oil provinces and giant GPPs were built for raw materials from nearby fields. We are currently observing the consequences of such megalomania.

The associated gas utilization scheme traditionally adopted in Russia since Soviet times involves the construction of large gas processing plants together with an extensive network of gas pipelines to collect and deliver associated gas. The implementation of traditional recycling schemes requires significant capital expenditures and time, and, as experience shows, it is almost always several years behind the development of deposits. The use of these technologies is economically efficient only at large production facilities (billions of cubic meters of source gas) and economically unjustified at medium and small deposits.

Another disadvantage of these schemes is the inability, for technical and transport reasons, to utilize the associated gas of the end separation stages due to its enrichment with heavy hydrocarbons - such gas cannot be pumped through pipelines and is usually flared. Therefore, even at the fields equipped with gas pipelines, associated gas from the end stages of separation continues to be burned.

The main losses of petroleum gas are formed mainly due to small, small and medium-sized remote fields, the share of which in our country continues to grow rapidly. The organization of gas collection from such fields, as it was shown above, according to the schemes proposed for the construction of large gas processing plants, is a very capital-intensive and inefficient measure.

Even in the regions where gas processing plants are located, and there is an extensive gas gathering network, gas processing enterprises are loaded by 40-50%, and around them dozens of old ones are burning and new torches are being lit. This is due to the current regulations in the industry and the lack of attention to the problem, both on the part of oilmen and gas processors.

In Soviet times, the development of gas collection infrastructure and the supply of APG to gas processing plants were carried out within the framework of a planned system and financed in accordance with a unified field development program. After the collapse of the Union and the formation of independent oil companies, the infrastructure for collecting and delivering APG to the plants remained in the hands of gas processors, and gas sources, of course, were controlled by oil workers. A buyer's monopoly situation arose, when oil companies, in fact, had no alternatives for the utilization of associated petroleum gas, except for its delivery into a pipe for transportation to the GPP. Moreover, the government has legally set the prices for delivery of associated gas to gas processing plants at a deliberately low level. On the one hand, this allowed gas processing plants to survive and even feel good in the turbulent 90s, on the other hand, it deprived oil companies of an incentive to invest in the construction of gas gathering infrastructure at new fields and supply associated gas to existing enterprises. As a result, Russia now has simultaneously idle gas processing facilities and dozens of flares of air-heating raw materials.

At present, the Government of the Russian Federation, in accordance with the approved Action Plan for the development of industry and technology for 2006-2007. a Decree is being developed to include in license agreements with subsoil users mandatory requirements for the construction of production facilities for the processing of associated petroleum gas generated during oil production. Consideration and adoption of the resolution will take place in the second quarter of 2007.

Obviously, the implementation of the provisions of this document will entail the need for subsoil users to attract significant financial resources to work out the issues of flare gas utilization and the construction of relevant facilities with the necessary infrastructure. At the same time, the required capital investments in the gas processing production complexes being created in most cases exceed the cost of the oil infrastructure facilities existing at the field.

The need for such significant additional investments in a non-core and less profitable part of the business for oil companies, in our opinion, will inevitably lead to a reduction in the investment activities of subsoil users aimed at finding, developing, developing new fields and intensifying the production of the main and most profitable product - oil, or may lead to to failure to comply with the requirements of license agreements with all the ensuing consequences. An alternative solution to the situation with flare gas utilization, in our opinion, is the involvement of specialized management service companies that are able to quickly and efficiently implement such projects without attracting financial resources from subsoil users.

gas petroleum gas processing hydrocarbon

Environmental aspects

Burningpassingoilgas is a serious environmental problem both for the oil-producing regions themselves and for the global environment.

Every year in Russia and Kazakhstan, as a result of the combustion of associated petroleum gases, more than a million tons of pollutants, including carbon dioxide, sulfur dioxide and soot particles, enter the atmosphere. Emissions resulting from the combustion of associated petroleum gases account for 30% of all emissions into the atmosphere in Western Siberia, 2% of emissions from stationary sources in Russia and up to 10% of the total atmospheric emissions of the Republic of Kazakhstan.

It is also necessary to take into account the negative impact of thermal pollution, the source of which is oil flares. Russia's Western Siberia is one of the few sparsely populated regions of the world whose lights can be seen from space at night, along with the night illumination of major cities in Europe, Asia and America.

At the same time, the problem of APG utilization is seen as especially topical against the background of Russia's ratification of the Kyoto Protocol. Attracting funds from European carbon funds for flare extinguishing projects would make it possible to finance up to 50% of the required capital costs and significantly increase the economic attractiveness of this area for private investors. By the end of 2006, the volume of carbon investments attracted by Chinese companies under the Kyoto Protocol exceeded $6 billion, despite the fact that such countries as China, Singapore or Brazil did not undertake obligations to reduce emissions. The fact is that only for them there is an opportunity to sell reduced emissions under the so-called "clean development mechanism", when the reduction of potential rather than real emissions is estimated. Russia's lag in matters of legislative registration of mechanisms for registration and transfer of carbon quotas will cost domestic companies billions of dollars of lost investments.

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OIL AND GAS, THEIR COMPOSITION AND PHYSICAL PROPERTIES

OIL

Oil is a flammable, oily liquid, predominantly dark in color, with a specific odor. According to the chemical composition, oil is mainly a mixture of various hydrocarbons contained in it in a wide variety of combinations and determining its physical and chemical properties.

The following groups of hydrocarbons are found in oils: 1) methane (paraffinic) with the general formula C i H 2i + 2; 2) naphthenic with the general formula С„Н 2П; 3) aromatic with a general formula

spn 2l -in- /

Hydrocarbons of the methane series are the most common in natural conditions. Hydrocarbons of this series - methane CH 4, ethane C 2 H in, propane C 3 H 8 and butane C 4 Nu - at atmospheric pressure and normal temperature are in a gaseous state. They are part of petroleum gases. With increasing pressure and temperature, these light hydrocarbons can partially or completely become liquid.

Pentane C 8 H 12, \ hexane C in H 14 and heptane C 7 H 1b under the same conditions are in an unstable state: they easily pass from the gaseous state to the liquid and vice versa.

Hydrocarbons from C 8 H 18 to C 17 H star are liquid substances.

Hydrocarbons, in the molecules of which there are more than 17 carbon atoms, are solids. These are paraffins and ceresins contained in certain quantities in all oils.

The physical properties of oils and petroleum gases, as well as their qualitative characteristics, depend on the predominance of individual hydrocarbons or their various groups in them. Oils with a predominance of complex hydrocarbons (heavy oils) contain a smaller amount of gasoline and oil fractions. Content in oil

B, M-ANT B

a large number of resinous and paraffinic compounds makes it viscous and inactive, which requires special measures to extract it to the surface and subsequent transportation.

In addition, oils are subdivided according to the main quality indicators - the content of light gasoline, kerosene and oil fractions.

The fractional composition of oils is determined by laboratory distillation, which is based on the fact that each hydrocarbon included in its composition has its own specific boiling point.

Light hydrocarbons have low boiling points. For example, pentane (C B H1a) has a boiling point of 36 ° C, and hexane (C 6 H1 4) has a boiling point of 69 ° C. Heavy hydrocarbons have higher boiling points and reach 300 ° C and above. Therefore, when oil is heated, its lighter fractions first boil away and evaporate, and as the temperature rises, heavier hydrocarbons begin to boil and evaporate.

If vapors of oil heated to a certain temperature are collected and cooled, then these vapors will again turn into a liquid, which is a group of hydrocarbons that boil out of oil in a given temperature range. Thus, depending on the temperature of oil heating, the lightest fractions - gasoline fractions - evaporate from it first, then the heavier ones - kerosene, then solar, etc.

The percentage of individual fractions in the oil that boil away in certain temperature intervals characterizes the fractional composition of the oil.

Usually, under laboratory conditions, distillation of oil is carried out in the temperature ranges up to 100, 150, 200, 250, 300, and 350°C.

The simplest oil refining is based on the same principle as the described laboratory distillation. This is a direct distillation of oil with the release of gasoline, kerosene and solar fractions from it under atmospheric pressure and heating to 300-350 ° C.

In the USSR, there are oils of various chemical compositions and properties. Even oils from the same field can vary greatly. However, the oils of each region of the USSR also have their own specific features. For example, the oils of the Ural-Volga region usually contain a significant amount of resins, paraffin and sulfur compounds. The oils of the Emba region are characterized by a relatively low sulfur content.

The oils of the Baku region have the greatest variety of composition and physical properties. Here, along with colorless oils in the upper horizons of the Surakhani field, consisting practically of gasoline and kerosene fractions alone, there are oils that do not contain gasoline fractions. In this area there are oils that do not contain resinous substances, as well as highly resinous ones. Many Azerbaijani oils contain naphthenic acids. Most oils do not contain paraffins. According to the sulfur content, all Baku oils are classified as low-sulphurous.

One of the main indicators of the commercial quality of oil / is its density. The density of oil at a standard temperature of 20°C and atmospheric pressure ranges from 700 (gas condensate) to 980 and even 1000 kg/m 3 .

In field practice, crude oil density is used to roughly judge its quality. Light oils with a density of up to 880 kg/m 3 are the most valuable; they tend to contain more gasoline and oil fractions.

The density of oils is usually measured with special hydrometers. The hydrometer is a glass tube with an expanded bottom part, in which a mercury thermometer is placed. Due to the significant weight of mercury, the hydrometer assumes a vertical position when immersed in oil. In the upper narrow part, the hydrometer has a scale for measuring density, and in the lower part, a temperature scale.

To determine the density of oil, a hydrometer is lowered into a vessel with this oil and the value of its density is measured along the upper edge of the formed meniscus.

In order to bring the obtained oil density measurement at a given temperature to standard conditions, i.e. to a temperature of 20 ° C, it is necessary to introduce a temperature correction, which is taken into account by the following formula:

p2o = P* + b(<-20), (1)

where p 20 is the desired density at 20 ° C; p/ - density at measurement temperature I; A- coefficient of volumetric expansion of oil, the value of which is taken from special tables; she