home Interpreter Measures to control the inactive well stock. Cannot be repaired

Measures to control the inactive well stock. Cannot be repaired

1) By appointment

1. Production wells - make up the largest part of the fund. Designed for the extraction of oil, gas and associated components

2. Injection wells - designed to inject special agents into the reservoir in order to ensure efficient development of the deposit

3. Special wells - designed to conduct various kinds of research in order to study the parameters and condition of deposits in their preparation for development and in the development process \

3.1. Estimated - used to assess oil saturation and other reservoir parameters for the purpose of conducting geophysical surveys.

3.2. Control wells - designed to control the processes occurring in the reservoirs during the development of oil and gas deposits

4. Auxiliary wells

4.1. Water intake - designed to take water in order to inject it into productive formations

4.2. Absorption wells - used for the disposal of associated water, as well as other commercial water in the event that they cannot be used for waterflooding formations

2) By commissioning time

1. Old wells - wells credited to the fund before the beginning of the reporting period

2. New wells - credited to the fund during the reporting period

3) As of the reporting date. When classifying wells on this basis, as a rule, the operating well stock is considered. Operational fund - the main part of the fund, including operating and idle production wells, as well as wells being developed or awaiting development after drilling for the production of products from them, as well as other wells

1. Active well stock - includes wells that produced in the last month of the reporting period, including:

1.1. Wells giving production at the end last day reporting period.

1.2. Wells that in the last month were producing even in a small amount but have been shut down this month and are awaiting repairs.

2. Idle fund - wells that were previously operated for oil and gas but did not produce during the last month of the reporting period, including:

2.1. Retired from operating in the reporting year, i.e. stopped during the current year or in the previous month reporting period Last year.

2.2. Wells retired from operating in previous years (stopped before December 1 last year)

3. Wells being developed or awaiting development after drilling

4. Other wells

4.1. Mothballed wells - wells that cannot be used for any purpose for a certain period of time and for which a conservation permit has been issued for certain period. There is no depreciation during this period. After the end of the conservation period, the well is liquidated or transferred to the corresponding part of the fund

4.2. Wells awaiting abandonment - wells where abandonment works are being carried out, they have been cemented, but documents on abandonment have not been received due to the lack of land reclamation.

4.3. Abandoned wells - wells whose liquidation is formalized in in due course and liquidation works already done

When analyzing the operating stock of wells in time, the following indicators are used

1) Well stock utilization factor

K and \u003d T f eff / T to eff

T f eff - actual operating time

T to eff - calendar operating time of the operating fund

To calculate the calendar time, it is necessary to multiply the well stock by the calendar duration in hours (365*24= 8660)

Calendar time for stopped wells within the framework of the current fund is not calculated. \

2) Well operation factor

K e \u003d T f eff / T to df

T to df - calendar hours of operation of the operating well stock

Fe = 120 wells

F - Active = 115 wells

T f ef= 926808 hours

Ki \u003d 926808 / (365 * 24 * 120) \u003d 0.28

Ke \u003d 926808 / (365 * 24 * 115) \u003d 0.92

III. Calculation production program for enterprises of the NG industry

When compiling a production program for oil (gas) production, the following indicators are used

1) Well stock

2) Average daily flow rate of wells (one well or a group of wells) - the average amount of oil produced per day of continuous operation of the well, which is determined by the ratio of the total volume of oil produced for a certain period of time to the indicator of the well stock for the same period

3) Well operation factor

When calculating the volume of oil or gas production, the well stock is classified by the time of commissioning

1. The calculation of oil or gas production volumes can be expressed as the sum of production volumes from old and new wells

D n \u003d D n st + D n new

D n new - production from new wells

D n st - oil production from old wells

2. The volume of oil production from old wells is calculated by the formula

D n st \u003d F st * q st * n * K e * K meas

F st - stock of old wells

q st - average daily debit of one old well

n- duration of the calendar period (number of days

K e - well operation factor

K meas - coefficient of change in oil production due to natural debit decline

3. Volume of oil production from new wells

D n new \u003d F new * q new * D

F new– stock of new wells

q new– average daily debit of one new well

D– number of days of operation of one new well

The stock of new wells is calculated from the wells put into operation in the reporting period from production and exploration drilling, and also includes completion of wells after drilling for previous years

F new \u003d F new eb + F new rb + F new osv

F new eb - stock of wells commissioned from production drilling

F new rb - stock of wells commissioned from exploratory drilling

F new osv - wells developed after drilling

The stock of wells commissioned from development and exploration drilling can be calculated based on the total volume of drilling operations and the average depth of the well

F new eb \u003d B e / G fe

F new RB = B r /G fr

B e; B r– volume of production and exploration drilling for oil and gas

G fe; G fr– average depth of wells operated for oil and gas

The average number of days of operation of one new well is calculated

D \u003d (n / 2) * K e new

K e new– new well operation factor

n- the number of days of a certain calendar period

IV. Calculation of the associated gas production program

Associated gas is an integral part of the produced fluid during field operation

When calculating the production program for the production of associated gas, the GOR values are used as the basis

The gas factor reflects the concentration of associated gas in the produced fluid.

AT modern conditions management within technological systems in oil and gas production, utilization (burning) of associated gas is practically excluded. Associated gas is collected in special tanks and can be sent through the gas pipeline system:

1) Satisfy the needs of the consumer (implementation to the side)

2) Use of associated gas for infield purposes (heating)

Associated gas production volumes can be calculated using the formula

D pg \u003d R g * G (1-K g)

R g - liquid (oil) corresponding to associated gas resources

G- gas factor reflecting the concentration of associated gas in the produced fluid

K g - coefficient of associated gas utilization for infield purposes

Organization of production in the field of current and workover of wells

I. The concept of current workover of wells (TRS). Drawing up a production program.

TRS is understood as a complex of technological and technical measures aimed at restoring the productivity of the well, when exposed to the bottomhole formation zone and downhole equipment.

TRS includes the following types of work:

1. Changing the pump and its parts during the operation of the ECM

2. Elimination of a break or unscrewing of the sucker rods during the operation of the SHM.

3. Flushing the pump.

4. Change of tubing and compressor pipes (MKT) and rods, elimination of leaks in lifting pipes.

5. Changing the liquid immersion of the riser string

6. Cleaning of lifting pipes from paraffin and other deposits

7. Checking the starting devices, lowering or raising the TCN

8. Launching or replacement of the flaker with simultaneous separate operation of the reservoir

9. Processing of the bottomhole formation zone and other geological and technical measures related to the lifting and lowering of underground equipment and aimed at improving the technological mode of operation to increase the production rate of wells.

There are the following types of TRS:

1. Planned preventive TRS - is carried out for the purpose of preventive inspection, identification and elimination of individual violations in the operation of the well that have not yet declared themselves.

2. Recovery TRS - carried out in order to eliminate the failure of the well due to the imperfection of the technology and the low reliability of the equipment used.

These types of repairs are also called emergency. In modern economic conditions, with the desire of oil companies to minimize the cost of operation, scheduled preventive repairs are losing their relevance and are practically not carried out.

Among the indicators of enterprises providing services for TRS are:

1. Number of TRS teams

2. The calendar time of work of the TRS brigades is determined by multiplying the number of brigades by the calendar duration of the corresponding period.

3. The coefficient of productive time of the work of the TRS teams is determined by the ratio of the actual time of the work of the TRS team to the calendar time.

CPV=Tf trs/Tk trs

Tf trs - actual work time of the TRS team

Tk trs - calendar working hours of the TRS brigade

4. Well operation factor.

Each operating well has to be shut in for TRS, which leads to interruptions in the operation of the well, i.e. there is an occurrence of current downtime in the operation of the well. The duration of these downtimes is taken into account by the well operation factor.

Ke=Totr/Tk

Totr - well operation time.

Tk - well operating time.

5. The overhaul period (MCI) is the average time between two successive current repairs for the reporting period.

MRP=Totr/R

R - number of TRS repairs

TRS has a relatively short duration (about 72 hours on average) and includes the following operations:

1. Transportation operations for the delivery of equipment for TRS to the well pad. Within the framework of the overall time balance of the TRS, these operations take a period of time from 40-50%.

2. Preparatory operations. Due to the fact that the current repair is associated with depressurization of the well at this stage, it is necessary to exclude cases of possible well flowing at the beginning or at the end of work. This can be eliminated by killing the well (injecting a fluid with a certain density into the formation and well, which ensures the creation of a certain pressure in the wellbore that exceeds the formation pressure) and the use of various devices (cut-off devices that block the wellbore when the tubing is pulled up).

3. Tripping operations (SPO) - occupy a significant share in the total duration of the TRS. Technological process SPO consists in alternately screwing or unraveling tubing, which act as a means of equipment suspension, a channel for supplying process fluids, tools, for fishing, cleaning and other types of work.

4. Operations to clean up the well, replace equipment for the elimination of minor accidents.

5. Final operations - involve dismantling the equipment and preparing it for transportation.

366 days, because 2012 leap year

Ke \u003d ((366 * 24) -247) / 366 * 24 \u003d 0.97(0.3 spent on TRS)

MCI \u003d ((366 * 24) -247) / 3 \u003d 2845.7

II. The concept of well workover (WOC). Drawing up production programs.

cattle is a set of works to restore well performance and enhance oil recovery. The well workover includes work related to the elimination of complex accidents, work to transfer a well from one operation site to another, as well as work to limit or eliminate water inflow, sidetracking (SBS). In accordance with this, the workover is characterized by greater labor intensity and duration of repairs (compared to TRS).

KRS includes the following types of work:

1. Recovery specifications casing strings, cement sheath and perforation interval.

2. Restoration of the working capacity of a well lost as a result of an accident.

3. Impact on the productive formation by physical and chemical methods (hydraulic fracturing (HF), hydrochloric acid treatment (HAT), etc.).

4. Sidetracking, drilling of horizontal sections in the reservoir.

5. Transfer of a well from one part of the stock to another (change of destination).

6. Liquidation of the well.

Within the framework of the CRC, the following indicators are distinguished:

1. Rollover volumes of cattle. In connection with the fact that workover works are quite long in time, repairs can be transferred from one reporting period to another, while creating significant volumes of work in progress.

25.12 10.02 20.05

01.01 01.02 01.03

Let the repair start time be 12/25/2011, and the repair end be 02/10/2012. Accordingly, when analyzing this repair in the reporting year 2012, the actual time of the repair duration (from 12/25/11 - 02/10/12) will exceed the workover calendar time (from 01/01/12 - 02/10/12) in the reporting period. This difference is a carryover volume and is calculated using the following formula.

O= Tp rem-Tk well

Tp rem - repair duration time

Tk well– calendar time of KRS

2. Number of well workovers completed. This indicator due to the presence of WIP (work in progress) during workover. In this regard, there may be wells with unfinished workover. In this case, the number of wells may not be an integer, i.e. for an individual well, carry-over volumes for the next reporting period (outgoing WIP) may occur.

S= (T pr well -O)/T pr well

TPR well- productive time of workover for the well.

Organization of production at oil and gas processing enterprises.

At oil and gas processing enterprises, the production program is the basis for planning sales volumes in value and natural units.

Manufacturing program- this is a comprehensive plan for the production and sale of products, which characterizes the volume, range, quality and timing of production in accordance with market requirements.

The basic basis of the production program are contracts with customers.

When developing a production program, it is necessary:

1. Justification for the use of production capacity, as well as material, labor and financial resources.

2. Systematic updating of the nomenclature and range of products and improving their quality.

3. A continuous increase in output, if there is a capable demand for it.

When updating the range of manufactured products, it is necessary to analyze the profitability of individual types of products. In the event that the profitability of the production of certain types of products is negative, then these types of products should be sequestered (removed) from the production program.

The production program is determined in terms of value and in kind, which makes it possible to agree on output volumes specific types products in accordance with the needs of the market and the production capabilities of the enterprise.

When compiling the production program of oil and gas processing enterprises, as a rule, the following indicators are calculated:

1. Marketable products (TP)- is the volume of output of finished products in value terms, to be sold.

The composition of marketable products may also include semi-financials intended for sale to the side

TP \u003d GPosn + GPvsp

GP main, GPvsp- finished products to be sold by the main and auxiliary industries.

2. Gross output (GDP)- this is the cost of all manufactured products and work performed, taking into account the balance of work in progress.

VP \u003d TP + (NZPk-NZPn)

NZPk, NZPn- the volume of work in progress at the end and beginning of the reporting period.

3. Sold products(RP)- this is the volume of sales in value terms, taking into account the change in the balance of finished products in warehouses.

RP=TP+(GPn-GPc)

GPN, GPC - volumes of finished products shipped, but not paid by the buyer at the beginning and at the end of the reporting period (accounts receivable).

Name	Refinery tons	GPN tn	TP	refinery	GPK
Gasoline AI 98
AI 95
AI 92
DT
TOTAL

TP = 6000 thousand rubles

VP \u003d 6000 + (1370-1000) \u003d 6370 thousand rubles

RP = 6000+(1800-1050)=6750 thousand rubles

Organization of energy supply of the enterprise.

The main purpose of the energy management of the enterprise is an uninterrupted supply of production with all types of energy in compliance with safety regulations, as well as the fulfillment of quality requirements and energy savings. As part of oil industry the main types of energy are: electrical energy; thermal and chemical energy of solid, liquid and gaseous fuels; thermal energy steam and hot water; mechanical energy. The choice of types of energy and energy resources is determined by the stage production process and industry affiliation enterprises.

The choice of the most economical energy resources is carried out by comparing the consumption rates of technological fuel and energy at various stages of the production process. Consequently, the energy resources consumed by the enterprise can be purchased from outside or produced in an economic way (on their own).

The rational organization of the energy economy to a certain extent depends on the correct planning, regulation and accounting of energy consumption. Determining the needs of an enterprise in energy resources and accounting for their consumption are based on the compilation of energy and fuel balances. The balance method makes it possible to calculate the need of an enterprise for various types of energy and fuel based on the volume of production at the enterprise and progressive consumption rates, as well as to determine the most rational sources of energy from or own production at the enterprise.

Energy balances are classified according to the following criteria:

1. By appointment: promising, current, reporting.

2. By type of energy carrier: private (according to certain types energy carrier), general (according to the sum of all types of fuel).

3. By the nature of the intended use of energy: main, auxiliary, servicing.

When compiling the fuel and energy balance, the need for various types energy and fuel, but only after that, sources of supply are selected. The optimal situation occurs when the volume of demand coincides with the sources of supply.

When the production capacity and the nature of the production process change, the fuel and energy balance is adjusted.

When planning the demand for energy resources for an oil company, the following indicators can be used:

1. The need for electrical energy, for technological needs.

Fri=Dn*Hr

day - oil production

Hp - consumption rate of electricity per ton

2. The need for motor energy.

Pd \u003d Nch * Zp * p

LF - hourly rate of oil consumption by a piece of equipment.

n- number of pieces of equipment

3. The need for fuel for technological needs.

P heat \u003d Urt * A

URt – specific consumption reference fuel per unit of work

BUT- amount of useful work

Organization of transport of oil and oil products

In the framework of world practice, the largest specific gravity in the structure of transportation of oil and oil products is occupied by sea and pipeline transport. However, when supplying individual divisions of the enterprise with petroleum products, the largest share falls on road transport.

When compiling the production program of an enterprise transporting oil products, the following should be taken into account:

1. Planned range and volumes of deliveries by groups of petroleum products.

2. Cargo flows within the enterprise between the points of loading and unloading of oil products.

3. The need for vehicles for the transportation of petroleum products.

4. The volume of loading and unloading operations of petroleum products, broken down by manual and mechanized

When planning the volumes of oil pumping through pipeline transport, the average percentage of ballast of a specific range of oil through the pipeline is allocated. Accordingly, allocate:

1. Pumping volume, net

2. Oil pumping volume, gross - which is calculated based on the net pumping volume and the average percentage of ballast

Qb \u003d Qn + ((Qn * B) / 100), where

Qn– volume of oil pumped NET

B– average percentage of ballast

When planning the production of petroleum products within the enterprise (not within the field level), economic and mathematical methods and models can be used. The solution of this problem involves the definition of a system of restrictions (volumes of goods transported from the supplier to the consumer) and an optimality criterion (for example, Minimization of transportation costs, then the function of the problem is as follows)

F=С11*Х11+Сmn*Xmn min

Cmn - the cost of transporting one ton of oil product to the consumer

Xmn - the volume of transported goods

For example: Need to define best option delivery of fuels and lubricants to drilling enterprises (UBR). Initial data:

number of RBR (m)=4

number of fuel bases (n)=3

The amount of fuel and lubricants available at the base

Volume of consumption of fuels and lubricants by UBR:

Table 1 provides information on the cost of transportation from the base to the UBR

In accordance with table 2, the total cost of transportation will be

2500*2+500*4+2000*1+3000*2+1000*1+2000*3=22000

wells represent the main component of the development system deposits, because they serve:

channels for lifting hydrocarbons and associated components from the bowels,

for information about deposits,

for reservoir drainage control.

Well fund at the field (operational facility) is divided into groups according to different characteristics -

- by appointment,

- by order of drilling,

- by way of operation,

- as of the reporting date,

- by commissioning time etc. -

Quantitative and qualitative changes in the well stock over time for facilities and fields at the end of each quarter are reflected in special reporting documents of the production and geological service, on the basis of which the planning and economic unit draws up a report on the operation of wells of an oil and gas producing enterprise as a whole.

The following is a brief description of well stock with its division into groups according to the main features.

wells operating facility (deposit, enterprise as a whole) according to its purpose are divided into the following main groups:

- mining,

- injection,

- special,

- auxiliary .

Production wells - designed for the extraction of oil, gas and associated components . For most production facilities, they make up the largest part of the well stock

injection wells intended for injecting various agents into reservoirs in order to ensure efficient development of deposits. Depending on the injected agent (water, steam, gas, etc.), injection wells are called water-driven, steam-driven, gas-driven and others. When introducing the process of in-situ combustion, injection wells simultaneously perform the functions of incendiary ones. The injection of air into them is preceded by the initiation of combustion in the bottomhole formation zone.

Special wells intended to conduct various kinds of research in order to study the parameters and condition of deposits in their preparation for development and in the process of development. This group of wells is divided into two subgroups:

Estimated

control wells.

Appraisal wells are used to assess oil and gas saturation and other reservoir parameters . They are drilled using special technology on different stages development and development of the field with the selection of cores from productive strata and the conduct of a rational complex of geophysical surveys to assess the initial, current and residual oil and gas saturation.

control wells designed to control the processes occurring in the reservoirs during the development of oil and gas deposits . This subgroup of wells includes:

- piezometric and

- observation wells.

Piezometric wells serve to monitor changes in them reservoir pressure by recording the liquid level in the wellbore, directly measuring reservoir pressure with a downhole gauge or measuring wellhead pressure . Piezometric wells are usually located behind the oil-bearing contour, i.e., in the aquifer; according to the data on the behavior of reservoir pressure in them, a characteristic of the aquifer region is compiled. AT last years in the oil industry, wells stopped within the reservoir to monitor changes in reservoir pressure are also referred to as piezometric.

observation wells intended to monitor the nature of the displacement of oil from the reservoirs - for the movement of WOC, GOC, GWC, contact of oil with agents injected into the reservoir, for changes in the oil and gas saturation of reservoirs. These wells are drilled within the deposit. AT gas industry observation wells are also used for accurate measurements of reservoir pressure. The design of wells is chosen depending on the tasks and possible research methods. So, in oil fields, a design with a non-perforated production string is widely used, which makes it possible to apply neutron methods for studying the oil and gas saturation of reservoirs with high efficiency.

Along with special wells to study the processes occurring in the reservoirs, they are widely used control and operational wells. Possibilities of including such wells in the network special wells are especially wide in the development of multilayer deposits. For use as control and production wells, production and injection wells are selected, in which only a part of the productive formations of the section is perforated. However, each well fulfills the role control and for non-perforated formations in and production or injection -for perforated. When developing gas fields to control and operational also include wells, in which periods of operation alternate with long stops to conduct research on the object under development, typical of observation wells.

The fund of special wells is partially created by

their targeted drilling,

wells that have already completed their previously assigned tasks.

Yes, in number piezometric they transfer exploration wells that are outside the deposit, as well as production wells that are flooded as a result of the displacement of oil or gas from the reservoir by water. Estimated wells and a significant part observant drill on purpose. It is also possible to transfer special wells from one subgroup to another. For example, after fixing by neutron methods the fact of complete watering of the formations in the observation well, in the latter, in order to verify the results obtained, the studied formations are perforated and tested for inflow. After confirming the water cut data, the well can be used as a piezometric well.

To the number auxiliary wells in the field include:

intake and

absorption wells .

Water intake -these are wells designed to withdraw water from a water reservoir in order to inject it into productive strata and use it for other needs during field development .

Absorbent (discharge) wells are used, if necessary, for the disposal of associated and other commercial waters in deep aquifers, if these waters cannot be included in the waterflooding system .

As auxiliary, as well as special wells are used, purposefully drilled or transferred from other groups.

Wells with different drilling sequence

The first stage of wells on oil deposits and gas are exploratory wells, which, upon completion of exploration, are transferred mainly to production and partially to injection.

Small oil deposits can be put into experimental (trial) operation for 1-2 years to obtain additional data necessary to justify the system and development indicators. At this stage, it is allowed to drill a small number of production wells in different parts of the deposit, which will subsequently be included in the grid of production and production wells. injection wells. Such wells are called advanced production wells . The operation of exploratory and advanced wells, the development of two or three wells for water injection, allow us to clarify ideas about the reservoir regime, productivity and injectivity of wells, the stability of reservoirs against destruction, the nature of well watering, etc.

With a large area of the oil-bearing object, when the pilot operation of the deposit as a whole is practically impossible and impractical due to the large scale of work on the development of the territory, the pilot operation of the most representative section of the deposit is carried out. In the selected area, advanced production and injection wells are drilled and operated according to a grid that is usually used in development in similar geological conditions. Thus, a fragment of the future system for developing an oil production facility as a whole is created. Advanced wells are drilled on the basis of pilot or pilot production projects.

Subsequent drilling is carried out in accordance with technological scheme and then - with the development project. the design document for development provides for the main and reserve well stock. First of all Buryats core stock wells , i.e., wells located on a uniform or uniformly variable grid within the established boundaries of the area for the placement of project wells. Further in poorly developed areas Buryat reserve fund wells , as a result of which the placement of wells becomes uneven, corresponding to the nature of the heterogeneity of the production facility.

With a sharp meso- and macro-heterogeneity, turning into discontinuity of reservoir layers with a complex configuration of zones of their distribution over the area, as well as with the complexity of the structure of the object by numerous tectonic disturbances, continuous drilling of the area with the drilling of all planned wells in a row in the main fund can lead to a significant number of unproductive wells , which fell into the zones of the absence of reservoirs or into the aquifer areas of the layers in tectonic blocks. To prevent this, under these conditions, drilling of wells of the main stock is carried out according to the principle from “known to unknown”. At the same time, ahead of the main front of drilling operations, moving in a certain direction, selectively (with the omission of several fund points) a separate well is drilled and, based on the results obtained, the question of the advisability of drilling adjacent wells is decided. If there is a productive formation in this well, drilling rigs are also transferred to the neighboring design well-points, in the absence of a formation, drilling of neighboring design well-points is canceled. With this drilling procedure, the number of unproductive wells is reduced to a minimum. In a multi-layer field, "dry" wells are transferred to other production facilities. If there is one object at the field, they are liquidated, in accordance with the requirements of Gosgortekhnadzor, without lowering production strings.

Drilling a gas field carried out in a slightly different manner. Exploration wells are the first stage of producing wells. For small objects, their number is sometimes sufficient to ensure the established maximum level of gas production. According to the average and large deposits after exploratory drilling, the first stage of production wells is required to reach the maximum level of production. Then, during the second stage of development, additional wells are drilled to maintain the achieved maximum production level, which is necessary due to the drop in production rate and the shutdown of previously drilled flooded wells.

Accounting for changes in the well stock

The well stock of each operating production facility, field and enterprise as a whole is in constant motion. The total number of producing wells changes: usually at the 1st and 2nd stages of development it gradually increases, at the 3rd and 4th stages it decreases. The number of injection wells increases as the waterflooding system develops. Wells can move from one group to another. So, when introducing in-loop waterflooding, for the first time, part of the injection wells can be used as production wells. When cutting deposits with rows of injection wells, it is practiced to develop injection wells at the first stage for injection through one, and intermediate injection wells are temporarily used as production wells. Forced oil production from the latter contributes to the movement of water entering the reservoir along the cutting line. After watering, intermediate wells are also developed for water injection, i.e. they are transferred to the injection group. In order to gradually develop the waterflooding system to improve the impact on areas of the deposit that are not sufficiently involved in the development, it is practiced to transfer part of the watered production wells to injection wells.

The condition of the wells is changing. Basically, they should be in operation, but they may also be under repair or idle for various reasons.

To register the movement of the well stock at the end of each quarter (year) for the operational facility and the field as a whole, a report "Fund of wells" is compiled (Table 3). The report reflects the entire stock of wells listed at the production facility (field, oil and gas producing enterprise) at the end of the quarter (year). The report at the end of the fourth quarter characterizes the fund at the end of the reporting year. Reports are compiled separately for oil and gas wells.

In the well stock, the report highlights the operating well stock and other groups of wells.

Operating fund -the main part of the fund, including operating and idle production wells, as well as wells being developed or awaiting development after drilling for the production of products from them .

Table 3. Form of the report "Fund of wells"

	Fund Composition	Number wells
	Operating fund
	Giving oil (gas)
	Stopped in the last month of the reporting quarter from among those who gave production in this month -

	Total operating (1+2)
	Retired from acting in the reporting year -
	Those who retired from acting in previous years -
	including those under renovation

	Total inactive (5+6)

	Developed and awaiting development after drilling
	Including those in development work -
	Total operating well stock (4+8+9)
	Other groups of wells
	Discharge
	Including the current
	Special (control evaluation)
	Water intake and giving iodine-bromine and industrial water
	Absorbent for wastewater discharge and others -
	in conservation -
	Pending Liquidation -
	Liquidated after exploitation -
	Liquidated after drilling

Active wells include wells that produced in the last month of the reporting period, including:

wells producing oil (gas), t. giving production at the end of the last day of the reporting quarter (including wells that are filled with liquid during periodic operation);

wells, which even produced in the last month of the quarter. in small numbers, but stopped this month and under repair or downtime for any reason.

To dormant , include wells that were previously operated for oil (gas), but did not produce during the last month of the reporting period , including:

retired from the operating wells in the reporting year, i.e. stopped in the current year and in December of the last year (the latter, as of January 1 of the reporting year, were in the stock of operating wells);

retired from operating in previous years, t. stopped before December 1 of the previous year.

To wells, being developed or awaiting development after drilling, include wells accepted after drilling for subsequent operation for oil (gas), as well as wells transferred for this purpose from among injection, special, mothballed, etc., if they have never produced production before.

Other groups of wells indicated in the report correspond to the groups of wells shown in this chapter that are not intended and not used for oil or gas production. At the same time, the groups of injection, special, auxiliary (water intake, absorption) include all wells: operating, retired inactive in the reporting and previous years, being developed and awaiting development. In the group of injection wells, operating wells are separately distinguished, which are determined according to the same principle as operating production wells (i.e., they are in operation at the end of the last day of the reporting quarter), with the difference that their action is associated with the injection of water or other working agent.

Other groups of wells also include wells that are in conservation, awaiting abandonment, abandoned after operation and abandoned after drilling.

in conservation -these are wells that cannot be used for any purpose for a certain period of time and for which, in connection with this, a conservation permit has been issued for a certain period. This group includes all mothballed wells, regardless of their purpose and reasons for mothballing. After the end of the conservation period, the well, if it is not subject to liquidation, is transferred to the appropriate part of the fund.

Pending Liquidation -these are wells where liquidation work is being carried out, or wells, documents for the liquidation of which have been sent to the relevant authorities.

liquidated -these are wells, the liquidation of which has been formalized in accordance with the established procedure and the liquidation work on which has already been completed . Abandoned after operation - wells that, after completion of operation, could not be used for other purposes: abandoned after drilling - wells unsuitable for use for various reasons: stopped drilling for technical or geological reasons, fulfilled their geological purpose, unproductive, etc.

The dormant fund (BF) consists of wells that did not produce in the last month of the reporting period. Wells under development and awaiting development after drilling include wells that were accepted into the balance sheet of mining enterprises after completion of their construction and did not produce in the last month of the reporting period.

BF includes wells that have not been operating for more than one calendar month. Such wells may be shut down in the current year or rendered inoperable in previous years.

The BF includes wells that did not produce (were not under injection) in the last month of the accounting period. In the dormant fund, wells stopped in the current year and before the beginning of the year are separately taken into account.

The presence of a large BF is explained by the delay in piping and connection of new wells.

The well goes into inactivity on the 1st day of the next month if it has not worked for a single day in the current month.

The reasons for stopping and transferring wells from the existing one to the BF are: 1. preparation for transfer to other categories: pressure maintenance, piezometer, conservation, liquidation; 2. failure or absence of the necessary downhole pumping equipment (DPE); 3. drop of equipment on the face; 4. detection of EC violations - displacements, collapses, leak intervals, etc.; 5. detection of behind-the-casing circulation and cross-flows; 6. unprofitability of further exploitation due to low yield or high water cut; 7. lack of industrial fluid inflow from the reservoir or lack of injectivity; 8. conducting geological and technical measures; 9. waiting for completion of geological and technical operations at adjacent wells; 10. regulation of withdrawals, or regulation of injection; 11. exploration of wells; 12. the presence of annular pressure above the allowable values; 13. gas shows; 14. lack of circulation; 15. lack of ground infrastructure; 16. seasonal stops: on winter period, for the period of floods, etc.; 17. other, including force majeure circumstances.

In order to reduce the inactive fund, the following measures are taken, in accordance with the above main reasons for disposal: - putting the well into operation without setting up the PKRS team after completion of the survey, completion of geological and technical operations on neighboring wells, construction, scheduled preventive maintenance of surface equipment , rebinding of collectors and other ground facilities. This item also includes launches after seasonal floods, elimination of emergencies and their consequences, etc.; – start of the well after the change of GNO; – launch of the well after carrying out geological and technical operations on it; – transfer of the well to another category after carrying out the relevant geological and technical operations, studies and registration of the necessary documentation. With a detailed consideration of the last group of activities related to the withdrawal of wells from the operating stock, and the least expensive, at first glance, from an economic and technological point of view, the following features appear that must be taken into account when working with BF.

When designing and choosing a rational development system oil fields it is necessary to take into account the emergency abandonment of wells. For objective and subjective reasons, low rates of extraction of recoverable oil reserves are designed within the already drilled and operated part of oil fields, but they do not take into account the limited durability of wells and the chaotic nature of their emergency disposal over the area of oil fields. Based on the well-known oil production equations, an algorithm for taking into account such a retirement when choosing a rational development system is proposed and the results of using the developed software product are presented.

Emergency abandonment of wells, rational development system, decrease in durability, relative oil production rate, recovery rate, recoverable reserves, average well operation time, recoverable oil reserves, backup wells. When designing and choosing a rational system for the development of oil fields, it is necessary to take into account the emergency abandonment of wells. For one reason or another, objective and subjective reasons, low rates of extraction of recoverable oil reserves are designed within the already drilled and operated part of oil fields, but at the same time they do not take into account the actual limited life of wells - their limited durability and the chaotic nature of emergency disposal of wells over the area of oil fields. Another reason for a sharp decrease in the longevity (from 30 to 10–20 years) of wells operating in highly productive oil reservoirs may be the use of a too dense grid, which leads to huge excess productivity and for many years ensures planned oil production by a small part of the drilled wells. Accordingly, the rest, a significant part of the wells are not used and not enough attention is paid to their current and major repairs, and as a result, their premature emergency disposal occurs.

Causes of non-hermetic EC:

1. water inflow along the productive horizon; 2. annular circulation due to the destruction of the cement stone behind the casing; 3. violation of the tightness of the production string (EC) or well elements (cement bridges, blast packers, etc.)..

To make big repair of well. Where is it necessary to put comma?

Specialists of oil-and-gas companies answered questions put by the magazine editors on acute and bad problem of wells shutdown in Russia.

Numerous publications in printed and electronic media, discussions at conferences speak about the relevance of the problems associated with the workover of wells.

Due to the depletion of existing fields and the inevitable, in the near future, decline in oil production, the problem of an excessively large stock of idle wells will attract more and more attention. The return to production of idle wells is of great importance for obtaining additional oil, which means additional revenues to the federal and local budgets, creating new jobs, revitalizing the economic life of individual areas, placing orders for domestic industry etc.

Indeed, the situation with the fund oil wells for December 2009 looks depressing (table).

In practice, it turns out that almost every sixth well in the country is not working. And in TNK-BP, almost every third. The situation is best in Surgutneftegaz. The three departments created for enhanced oil recovery and well workover are doing their job: the percentage of idle wells is minimal here.

Oil well fund December 2009 (number)

One gets the impression that a large number of idle wells are not very worried about the management of the industry and oil companies. Among the reasons for this attitude, we can assume the following: possible increases in production are not so large as to be of interest to large oil companies; considerable costs for cattle are required; there are big risks associated with the fact that the costs will not pay off; large companies pay more attention to improving the methods of enhanced oil recovery (EOR) and increasing the oil recovery factor (ORF) in the producing well stock.

However, deposits are gradually flooded, new ones, like the West Siberian region, do not appear, relocation to remote uninhabited, undeveloped regions requires large financial investments, so life will increasingly push for a major overhaul of the stock of idle wells. Perhaps this will also be facilitated by oil prices on the world market, innovative technologies in geophysics, geonavigation, the emergence of new machinery and equipment to reduce the cost of well workover; perhaps a small and medium business for which work with this fund will be profitable.

We decided to find out the opinion of experts on this issue.

Questions "BiN"

What, in your opinion, should be done to reduce the number of idle wells in the country?
In your opinion, will small and medium-sized businesses be able to help reduce the stock of inactive wells? What are the conditions for these firms to access idle wells: free transfer, auction sale, with some share of the state, oil companies or without it? What could be the legal, land, economic procedures for this process?
What is the economy of cattle? How much more profitable is it to repair old wells than to drill new wells?
What percentage of workover work is done by foreign contractors? How efficient and economical are they?
What is the ratio of price and quality of domestic and imported equipment for cattle?
What percentage of non-performing wells is irretrievably lost, that is, investments will certainly not pay off? How to deal with them in this case: conserve, eliminate?
What types of cattle are preferred under the same mining and geological and hydrodynamic conditions? Which of them are the most costly and most effective?

MONITORING WILL DETERMINE THE FATE OF ISLAND WELLS

V.B. OBIDNOV
Ph.D., Deputy CEO for the production of OJSC NPO Burenie
[email protected]

IT IS IMPOSSIBLE TO BE INDIFFERENT COLONIZERS IN YOUR COUNTRY

F. AGZAMOV
Doctor of Technical Sciences, Professor of the Department of Drilling Ufa State Oil University
[email protected]

I do not consider myself an expert on the problem of well workover, but I would like to express some considerations. They may not fit into traditional concepts, so consider this an outsider's perspective.

THE BUSINESS OF KRS CAN END BEFORE IT STARTED

S.L. SIMONYANTS
Doctor of Technical Sciences, Academician of the Russian Academy of Natural Sciences, Professor of the Department of Drilling Oil and Gas Wells of the Russian State University of Oil and Gas. THEM. Gubkin
[email protected]

To reduce the number of idle wells, it is necessary to increase the volume of application of technologies for drilling new (side) holes. These works are successfully carried out by small and medium service enterprises. They need to create all the conditions for development, including tax incentives, cheap loans, simplified equipment leasing.
Idle wells should be transferred to small and medium-sized enterprises in a concession with preferential taxation. Conditions for access to objects should be the most simplified. It is also necessary to be interested service companies in investments in new technology. For example, it is possible to link the transfer of wells to a concession with the condition of the obligatory use of new domestic well workover technologies on them.
I have not thoroughly investigated this issue, but, in my opinion, the cost of a sidetrack is on average 2 times less than drilling a new well. I think that the economic efficiency of workover will strongly depend on the selling price of hydrocarbons obtained from the repaired well. And this price is likely to be determined by large oil companies having "pipe access". Therefore, if the issue of fair pricing for small and medium-sized firms is not resolved, the KRS business may end before it starts.
I do not know for sure. I believe that foreign contractors must be economical and efficient, otherwise why are they here?
The value for money is about the same. Taking into account the specifics of the repair work on the well, I believe that preference will be given to cheaper, albeit lower quality technological equipment.
Don't know.
I can not say exactly.

THE PERCENTAGE OF INACTIVE WELLS SHOULD NOT EXCEED THE DESIGN PERCENTAGE

A.P. FEDOSEEV
Chief technical department OOO Gazprom Podzemremont Urengoy
[email protected]

The authors: Kofanova Diana Marsovna, Vlasov Artem Gennadievich
Position: students
Educational institution: Tyumen Industrial University
Locality: Tyumen
Material name: Research Article
Subject:"Reducing the inactive well stock at the Priobskoye field"
Publication date: 29.09.2018
Chapter: higher education

The article describes the current status of a dormant mining and

injection funds of the Priobskoye field. Causes highlighted

shutdowns and transition of wells to an inactive fund. Analyzed

hydraulic fracturing method as the main method of production stimulation at Priobskoye

field.

The Priobskoye field is characterized by low well flow rates.

The main problems of field development were low

productivity of production wells, low natural (without fracturing

formations with injected water) injectivity of injection wells, as well as

poor redistribution of pressure across deposits during the implementation of the reservoir pressure maintenance

(due to the weak hydrodynamic connection of individual sections of the reservoirs).

A separate problem of field development should be singled out

operation of the AS12 formation. Due to low flow rates, many wells of this

formation must be stopped, which may lead to conservation at

indefinite period of significant oil reserves. One of the directions

solution to this problem in the AC12 formation is the implementation

measures to intensify oil production. From Methods

intensification of oil production by the impact on the bottomhole zone

wells are the most widespread:

Hydraulic fracturing;

acid treatments;

Physical and chemical treatments with various reagents;

Thermophysical and thermochemical treatments;

Pulse-impact, vibroacoustic and acoustic impact.

Hydraulic fracturing (HF) is one of the most effective

methods for intensifying oil production from low-permeability reservoirs and

increase in the production of oil reserves. Hydraulic fracturing is widely used as

in domestic and foreign practice of oil production. Significant

Hydraulic fracturing experience has already been accumulated on Priobskoye field. Analysis

hydraulic fracturing performed at the field indicates high efficiency

for a field of this type of production stimulation, despite

significant rate of production decline after hydraulic fracturing. hydraulic fracturing in

case with the Priobskoye field is not only a method

intensification of production, but also increase in oil recovery. First, hydraulic fracturing

allows you to connect non-drained oil reserves in intermittent

deposit collectors. Secondly, this species impact allows

extract additional volume of oil from the low-permeability layer AC12

for a reasonable time of operation of the field. Thus, hydraulic fracturing

should be considered the main way to intensify production at

Priobskoye field.

The well goes idle on the 1st of the following month,

if she has not worked a single day in the current month. Causes

shutdown and transition of wells from the operating stock to the inactive one

are:

1. preparation for transfer to other categories: PPD, piezometer, conservation,

liquidation;

2. failure or lack of necessary downhole pumping

equipment (SNE);

3. drop of equipment on the face;

4. detection of EC violations - displacements, crumples, intervals

leaks, etc.;

5. detection of behind-the-casing circulation and cross-flows;

6. unprofitability of further operation due to low yield, or

high water cut of products;

7. lack of industrial fluid inflow from the reservoir or the absence

injectivity;

8. conducting geological and technical measures;

9. waiting for completion of geological and technical operations at adjacent wells;

10. regulation of withdrawals, or regulation of injection;

11. exploration of wells;

12. the presence of annular pressure above the allowable values;

13. gas shows;

14. lack of circulation;

15. lack of ground infrastructure;

16. seasonal stops: for the winter period, for the period of floods, etc.;

17. other, including force majeure circumstances.

The Priobsky license area has the shape of an irregular

polygon, with an area of about 3353.45 sq. km. In immediate

close to the Priobskoye field there are large, located

field in operation: Prirazlomnoye (in the southeast), Salymskoye

(20 km to the east) and Pravdinskoye (57 km to the southeast). central part

the site is located in the floodplain of the river. Obi. The territory of the deposit is conditionally

It is subdivided into two zones: Right-bank and Left-bank. Border

between them runs along the main channel of the river. Ob.

Currently, the field is being developed according to the "Technological

scheme for the development of the Priobskoye field, 2001” approved by the Central Committee

Ministry of Fuel and Energy (Minutes No. 2769 dated November 15, 2001). By reserves

the field belongs to the large ones, and according to the geological structure -

extremely difficult to master. Distinguishing Features

Place of Birth:

Large area of oil-bearing;

Multilayer;

Multi-stage design and development of the development system and

field development;

The status of the territory of the special procedure for subsoil use.

Commercial oil-bearing capacity established in Neocomian deposits

(horizons AC7, AC8, AC9, AC10, AC11 and AC12). In the industrial

three horizons are involved in the development: AC10, AC11 and AC12, where

96.9% of proven reserves, with 54.9% concentrated in the AC12 horizon

of them. At the Priobskoye field, as of January 1, 2010, the fund

wells since the beginning of development is 1167 wells, including

producing 836, injection 331.

The field is multilayer. Operational

the objects are layers AS10, layer AS11, layer AS12. Field

characterized by a high rate of commissioning of new wells. Largest part

fund for this moment has a water cut of 9.5 - 25.1% (water cut in

in general for the field - 22.1%).

Cumulative oil production as of January 1, 2010 for the AC12 formation was

11210 thousand tons, the fund of production wells in the reservoir amounted to 571 wells out of

of which 496 wells are operating, the operating stock of injection

wells - 210, of which 172 wells are operating. For the AC11 formation from the beginning

development, 43,633 thousand tons of oil were selected.

As of 01/01/2010, the stock of production wells amounted to 610,

including: operating - 523, stock of injection wells - 219, incl.

operating - 206. Since the beginning of development, 11778 have been selected from the AS10

thousand tons of oil. As of 01.01.2010, the stock of production wells

totaled 482, including: operating - 423, injection fund

wells - 176, including operating - 157.

Hydraulic fracturing begins with determining the dependence

well injectivity on fluid injection pressure. For this

through one pumping unit at the first or second speed of its

fracturing fluid is pumped into the well until stabilization

wellhead pressure (usually 10-15 min). Measure fluid flow and

pressure. Then the injection rate is increased, the flow rate is again measured and

pressure, etc. a formation is considered to be fractured if

injectivity coefficient (the ratio of fluid flow to pressure) at

pumping liquid at the maximum flow rate increases by at least 3

– 4 times in comparison with the injectivity coefficient at the minimum

download mode. If the fracturing is not fixed, then the process is repeated

using high viscosity fluid. After establishing the fact

fracturing with the purpose further development cracks and easier entry

increased viscosity. Then the fluid is pumped with sand with a volume

speed not lower than the one at which the formation fracture was recorded.

Displacement fluid is pumped directly behind the sand-liquid

mixture without reducing the injection rate. After completion of punching

sand-liquid mixture into the crack, the well is closed and left in

rest until stabilization (recovery) of pressure on the mouth. Then from

wells remove the packer, wash it to the bottom and master.

Significant increase in well productivity after hydraulic fracturing

occurs due to a complex of factors, such as an increase in the effective

well radius, involvement in the development of the entire oil-saturated

formation thickness, deep penetration into the formation, which will allow to attach

for operation the maximum number of productive interlayers and

remote, hydrodynamically isolated reservoir objects that are not

produced without hydraulic fracturing.

At the Priobskoye field, it is necessary to carry out work on

hydraulic fracturing of the AC12 formation. These works will involve

exploitation of the remaining oil reserves, which would not have remained without hydraulic fracturing

retrieved. This will allow not only to achieve oil production, but also

significantly increase it. As a result, get additional