RU2571542C2 - Method of dynamic estimation of compliance with specification of oil reservoir, and increasing of production and oil recovery using asymmetric analysis of operation indices - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: invention relates to designing of the oil reservoir, and its recovery control. Information is gathered using the unique comprehensive methods of acquisition and analysis of system of indices and information under address mode using weighting in relation to the exact reservoir and producer needs. The reservoir rating is generated using the asymmetric analysis of the indices system and further use for the measures plan forming. Architecture of production (for example, number, location and method of construction of the oil and injection wells) is further constructed according to the measures plan. Continuous monitoring of the reservoir operation indices can be performed and used to confirm the target indices of oil production and recovery and/or assurance of activation of start-up or emergency circuits for the production equipment replacement.

EFFECT: more accurate estimation of the actual conditions in the existing reservoir, development and implementation of the rational plan of measures to increase short-term work yields and long-term oil recovery of the reservoir.

26 cl, 35 dwg, 5 ex, 24 tbl

Description

BACKGROUND OF THE INVENTION

1. FIELD OF THE INVENTION

The invention relates to the field of oil production, and more particularly to the field of designing an oil reservoir for managing it and its return.

2. RELEVANT TECHNOLOGY

Oil is an essential source of fuel, and the blood of a modern economy. The economic outlook for oil exploration and production is enormous. Due to a variety of technical and geological obstacles, in general, it is not possible to extract all the oil contained in the reservoir.

Prior to 1965, conventional oil recovery factors for the oil reservoir were approximately 25%. This coefficient shows the share of oil in the reservoir, which can be economically justified and / or advisable to extract. The remaining 75% remain essentially uninvolved due to technological and / or economic barriers. Since that time, with the development of technology and an increase in economic incentives due to higher commodity oil prices, the average oil recovery coefficient has increased to about 35%. Although this represents a significant increase in average total production, it also means that about 65% of the oil found in a common reservoir remains unrecovered for economic and / or technical reasons.

Given the high cost of exploration, the ever-decreasing chances of finding new oil reservoirs and the increasing cost of oil as a commodity, there are currently tremendous economic opportunities to significantly increase both the short and long term operation of the oil reservoir. The fact that most of the oil in a conventional reservoir remains non-recoverable, despite the high economic benefits of increasing recovery, means that currently there are no technologically and / or economically predictable ways to increase production.

Although there may actually be technology to increase current production and / or increase overall long-term recovery for the oil reservoir, difficulties in implementing a reasonable long-term plan to maximize current returns, extend the life of this reservoir, and increase total recovery arise from the inability to accurately assess technical condition and decrease in efficiency collector. For example, some or all of the reservoir’s producing wells may show declining production rates, which may lead to the conclusion that the reservoir is depleted. At the same time, the reservoir may, in fact, contain a much larger volume of recoverable oil, but may have low productivity simply because of the imperfect location and / or management of existing wells and the inability to determine the location of drilling new wells. The inability to properly diagnose inefficiencies and failures and the inability to implement a reasonable production plan can result in reduced short-term productivity and long-term oil recovery.

In general, operators of production equipment and facilities usually focus on preventative maintenance of oil wells and may even implement the latest technological developments to maximize well production. At the same time, they do not understand the general picture of the technical condition and long life of the reservoir, which can be serviced by several wells. Wells are difficult and expensive to drill and operate. After commissioning a given number of wells, it may turn out that it is not economically feasible to drill additional wells to increase reservoir production (i.e., marginal costs may exceed marginal benefits). In addition, there may be no clear reason for the closure of production wells, although the implementation of this may actually increase short-term production and improve long-term oil recovery. Knowledge of the timing and reasons for closing or replacing production wells and / or the proper construction of new wells is often lacking even among the most experienced field operators and well operators. Failure to implement proper management of existing wells and / or to locate and build new wells may increase capital costs while reducing production and oil recovery.

The main obstacle to maximizing reservoir production and oil recovery is the inability to collect, reasonably analyze, and correctly understand relevant data. Diagnosis of the technical condition of the oil reservoir is not straightforward and is more like decoding the state of human health, but on the site deep underground or the seabed. In addition, the accumulation and analysis of the collected data can take years, while the data can change dynamically, creating difficulties, if not completely exclude the possibility of formulating and implementing an economically and / or technically sound production plan. The result is remaining low short-term productivity and low long-term oil recovery.

SUMMARY OF THE INVENTION

The present invention seeks to overcome the existing technical, economic and institutional obstacles that reduce the production and oil recovery of the oil reservoir by more accurately assessing the actual conditions in the existing reservoir and implementing a reasonable plan of measures to increase short-term production rates and long-term oil recovery of the reservoir. The above is done by collecting information using unique methods of collecting a set of indicators and information and analyzing the collected information in the address mode using proper weight processing of data in the context of a specific collector and manufacturer’s targets.

All hydrocarbon assets carry an individual “DNA” reflecting their underground and terrestrial attributes. However, conventional methods do not provide useful tools for a proper understanding of the unique features and requirements of each particular oil reservoir. The invented method creates a tool for the development and application of production methods that optimize for the specific conditions of each individual oil reservoir. The success of the method in reaching optimal solutions is based on the ability to filter out non-critical parameters and identify specific reasons for the decrease in the performance of the collector. The method contributes to the gradual increase in both production and reserves, exceeding levels obtained using standard industrial methods.

The method integrates a wide range of information using a specific scorecard. Some are known, others are unique to the method of the invention. The indicator system includes both leading and lagging indicators of oil reservoir productivity. Although manufacturers generally focus on lagging indicators, such as reduced production and / or increased water cut, the present invention makes it important to use leading indicators that are more predictable for future decreases in production or other problems before they occur. The above ensures the formation and implementation of an action plan before the deterioration of the technical condition of the collector goes too far. An analogue is a comparison of preventive treatment and medical care. In the latter case, they are looking for a medicine for a sick patient, and in the first case, the patient's disease is prevented. Delayed indicators can, however, be a good tool to ensure individual responsibility.

Relevant information on the conditions of the collector is collected more widely and comprehensively in comparison with conventional methods. The invention implements the use of an intensely focused, rigid method of collecting information to obtain and comprehensively analyze all available information that may be relevant to the conditions of the collector. All known sources of relevant information can be identified during the period of intensive collection of information.

The invention analyzes the information collected and accurately evaluates the conditions of a given collector using proper weight processing of various types of data. The process of weighting data of various types with giving them an increased or decreased value is called an "asymmetric estimation". There is a certain system of indicators, in general, leading indicators that are more useful than others (for example, lagging indicators) in a realistic assessment of the present and future conditions of the oil reservoir. In addition, the way in which some indicators are multiplied by weights may depend on the particular collector in question and / or the specific targets facing the manufacturer.

The action plan is formed on the basis of proper collection, analysis of data and assignment of weighting factors for a particular collector. The action plan may require moderate or significant changes in the way oil is extracted from the reservoir. In any case, since the action plan is based on an accurate assessment of the short-term, medium-term and long-term conditions of the reservoir and is adapted to the specific conditions of the reservoir and / or the requirements of the producer, the action plan has an increased chance of success and results in the form of improved short-term, medium-term and long-term production and profit compared to the possibilities of using conventional methods.

An action plan is being implemented to increase short-term production and / or long-term oil recovery (for example, proven reserves). An action plan may include one or more of the following: (1) modification and / or treatment to enhance the inflow of one or more existing wells, (2) construction of new wells, (3) injection of fluids under pressure and / or gas into more a reasonable and planned regime, and (4) shutting down or reducing production in one or more existing wells. In general, it is preferable (1) to maximize the contact between the wellbore and the reservoir, (2) to reduce gas factors and / or water cut and / or displacement pressures among adjacent and / or similarly located and / or similarly designed wells, and (3) optimization extraction rates to more closely match pore displacement factors and accumulation locations in the wellbore.

When operating reservoir wells are operating in an optimized manner, short-term production increases and long-term production is maximized.

Finally, it is possible to monitor the oil reservoir to ensure compliance with the design and production goals, such as those established by the asymmetric reservoir conformity assessment (RCAA ™). It is possible to create alarming levels or settings of the starting circuits, upon transition of which when the set maximum is exceeded or falls below the set minimum, the system reacts. The response may be a notification to the manager or other interested party, or it may be an automatic adjustment of some production parameters.

Patentable methods of the invention with an asymmetric assessment of compliance with the technical requirements of the reservoir can be used to increase short-term, medium-term and long-term productivity and oil recovery by about 5-40%. In some embodiments, the methods of the invention should allow economically and technically sound recovery in a reservoir of known volume, in some cases up to about 80-85%. This result is unexpected and not predictable given the enormous undiscovered economic potential that currently exists, but which cannot be used to increase production even for most reservoirs of known volume, taking into account today's knowledge of the operation of the oil reservoir and oil recovery.

BRIEF DESCRIPTION OF THE DRAWINGS

To further clarify the foregoing and other advantages and features of the present invention, the following is a description of embodiments of the invention with the accompanying drawings. These drawings show only typical embodiments of the invention, not limiting its scope. The invention is described below with additional details and specifics using the accompanying drawings, which show the following.

1A and 1B show two halves of a block diagram of an example of a comprehensive implementation plan for one method for dynamically assessing compliance with technical requirements of an oil reservoir and increasing production and oil recovery using asymmetric performance analysis.

Figure 2 shows an example of a graph of the difference between production and oil recovery of the reservoir before and after the implementation of the methods of the invention.

3A-3D illustrates an example of dashboards in a computer-generated control and monitoring station where monitoring and analysis of data from existing production wells of an oil reservoir is carried out.

Figure 4 schematically shows an example of computer architecture that can be used to collect, analyze and / or display data collected from an oil reservoir.

5A-5F are graphs of various leading indicators used to evaluate and / or increase compliance with reservoir specifications.

6A-6I show graphs of various lagging indicators used to evaluate and / or increase compliance with reservoir specifications.

Figures 7A-7C show graphs of various unit development indicators used to evaluate and / or increase compliance with reservoir technical requirements.

On figa-8C shows graphs of various indicators of the workload used to assess and / or increase compliance with the technical requirements of the collector.

On Figa-9B shows graphs of various indicators of the business plan used to assess and / or increase compliance with the technical requirements of the collector.

FIGS. 10A-10C show graphs of various oversized targets used to evaluate and / or increase compliance with reservoir specifications.

11 shows an example of a maximum reservoir contact well (MRC) used to increase the productivity of one existing production oil well.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

DETAILED DESCRIPTION OF THE INVENTION

I. INTRODUCTION

The present invention is aimed at creating a comprehensive method for increasing the current production and final return of oil from the reservoir. This method may be referred to as an asymmetric reservoir conformance assessment (or RCAA ™). RCAA ™ involves several closely related steps in a method or modules that are used together and sequentially. They are: (I) analysis and diagnosis of specific and unique features of the reservoir (ie its “DNA”) using an address system of indicators, (II) development of an action plan to maximize current production and total oil recovery, (III) implementation of the plan measures to increase current production and total oil recovery, and (IV) monitor or track the performance of the oil reservoir using an address system of indicators and make adjustments to production parameters, as necessary, to support I desired productivity and recovery.

Each of the method modules is based on a thorough knowledge of the acquisition methods, which include direct measurements of physical parameters, studying the geology and other unique conditions and aspects of the reservoir and, where applicable, taking into account the type, number, location and productivity of any working wells, or wells, otherwise associated with the reservoir (e.g., operating production wells, plugged wells, and parametric wells), analysis of current conditions or condition of the reservoir using asymmetric weights second data processing systems of various indicators, and predicting future mining, oil, and other variables in a comprehensive understanding of the specific DNA collector in conjunction with an asymmetric weight processing and data analysis. In some embodiments, the information collected may relate to measurements and data generated by other methods.

II. COLLECTION OF INFORMATION AND SYSTEM OF INDICATORS

A. Overview

In general, asymmetric reservoir conformity assessment (RCAA ™) is an assessment method that guides both phases of the planning and implementation of oil production. All hydrocarbon reserves carry an individual "DNA", which is a reflection of their underground and ground features. RCAA ™ is a tool for the development and application of production methods that are optimally designed according to the detailed descriptions of individual hydrocarbon reservoirs. Its main value is to facilitate the implementation of an increase in reserves and production exceeding levels obtained using standard industrial techniques. At the same time, in turn, it is possible to reduce long-term capital costs and operating costs.

According to one embodiment, the implementation of asymmetric conformity assessment of the technical requirements of the collector (RCAA ™) is carried out in six interrelated and interdependent areas: I) Knowledge systems; Ii) Research Q6; Iii) Meetings for in-depth understanding; IV) Diagnostics of the quality factor; V) gap analysis; and VI) Action Plan. The information collected in these areas is integrated using modern means of knowledge exchange, which includes accessible systems in the network and professional communities. An integrated block diagram with conceptual and temporal relationships in six directions is shown in FIGS. 1A and 1B (i.e., two halves of the same block diagram). Although the overall business model includes both technical and non-technical means of collecting relevant information, the method cannot be implemented without the use of physical processes and devices for collecting key information. In addition, the implementation of the action plan includes computerized monitoring of well operations. And improved reservoir performance is obtained as a result of the physical transformation of the reservoir itself.

Physical methods using data acquisition techniques include, for example, 1) core sampling for producing rock samples in a well (both conventional and special core sampling), 2) sampling of fluid, oil, water and gas in a well , 3) measuring the initial pressure by a reusable formation tester or the like. devices, and 4) determination of fluid saturation from borehole logs (for both cased and uncased boreholes). In addition, after implementing the action plan and increasing production and / or oil recovery from the reservoir, the reservoir transforms from a less productive to a more productive fixed asset. Figure 2 shows how the method of the invention physically transforms an oil reservoir and / or production system with an increase in current production and overall long-term oil recovery.

Monitoring collector performance indicators before, during, and / or after implementing an action plan includes the use of a computerized system (ie, part of a “control and monitoring post”) that receives, analyzes and displays relevant data (for example, between one or more computers connected by a network and / or interconnected via the Internet). Examples of a system of indicators that can be monitored include 1) pressure and fluid saturation of the reservoir and their changes using logging devices, 2) flow rate of the well and its reduction using logging devices, profile of fluid inflow in production and discharge flow wells using logging devices, and flow rates for oil, gas and water for the influx of production and discharge flow. A relevant scorecard can be displayed on the Internet. Systems with network access can exchange such data. FIGS. 3A-3D illustrate an example of “dashboards” that can be used to graphically display some scorecards (for example, leading and lagging) compiled from an on-line sampling of existing production wells. Dashboards can create a high-speed visual diagnostic tool to evaluate past and future performance.

B. Computerized information collection and analysis

Figure 4 shows an example of a computer system 400 that monitors reservoir performance, analyzes reservoir performance information, displays a dashboard scorecard, and, if necessary, creates computer-controlled modifications to maintain optimal performance of an oil well. The monitoring system 400 includes a data-collecting main computer system 402 consisting of one or more computers located close to the collector, with communication channels with collector sensors 404.

Computer system 402 may comprise a plurality of computers connected to a network (for example, each of which is capable of analyzing a portion of common data generated by sensors and received from sensors 404). The collector sensors 404 are generally installed in existing production oil wells and may include both surface and underground sensors. Sensors 404 may also be installed in injection wells, parametric wells, etc. The data collected by sensors 404 can be used to generate performance indicators (e.g., leading and lagging production and oil recovery indicators). The computer system 402 may therefore include a programmable data analysis module 406 for generating a scorecard based on data received from sensors. A user interface 408 provides user experience. A data or system memory 410 can be used to long-term store sensor data and / or metrics.

According to one embodiment, computer system 402 may provide at least one manual and / or automatic adjustment of production 412 using manifold production units 414 (e.g., operating oil production wells, water injection wells, gas injection wells, heat injectors, and the like). ., and their auxiliary components). Corrections may include, for example, changes in the volume, pressure, temperature, trajectory of the wellbore (for example, by closing or opening sidetracks). User interface 408 allows manual adjustments to 412 production. Computer system 402 may, in addition, include alarm levels or trigger setpoints that, when certain conditions are met, provide automatic production adjustments 412.

Monitoring system 400 may also include one or more remote computers 420 that provide a user, group of users, or several parties with access to information generated by main computer system 402. For example, each remote computer 420 may include a dashboard display module 422 , which converts and displays dashboards (for example, as shown in FIGS. 3A-3D), a scorecard, or other information related to reservoir mining. Each remote computer 420 may also include a user interface 424 that enables the user to make production adjustments 412 using the reservoir mining units 414. Each remote computer 420 may also include a data storage device (not shown).

Individual computer systems in the monitoring system 400 (for example, the main computer system 402 and remote computers 420) may be connected to a network 430 such as a local area network ("LAN"), wide area network ("WAN"), or even the Internet. Different components can receive and transmit data from each other, as well as other components connected to the network. Network computer systems and the computers themselves constitute the "computer system" for the present invention.

Networks that communicate between computer systems and other electronic devices can use any of a wide range of (potentially interoperable) protocols, including, but not limited to, the IEEE 802 wireless protocol module, radio frequency identification ("RFID") protocols, ultrasound protocols, infrared protocols, cellular communication protocols, one-way and two-way wireless paging protocols, global positioning system ("GPS") protocols, wired and wireless protocols wireless broadband, ultra wide bandwidth communication protocols, ring-type protocols, etc. Accordingly, computer systems and other devices can create blocks of transmitted data and exchange blocks of transmitted data (for example, Internet protocol (“IP”) datagrams and other upper layer protocols using IP datagrams, such as transmission control protocol (“TCP”) data, Remote Desktop Protocol ("RDP"), Hypertext Transfer Protocol ("HTTP"), Simple Mail Protocol ("SMTP"), Simple Object Access Protocol ("SOAP"), etc.) on the network.

Computer systems and electronic devices may be configured to use protocols based on the functionality of the respective computer systems and electronic devices. Components in the architecture can be configured to convert between different protocols for compatible communications. Computer systems and electronic devices can be configured with multiple protocols and using different protocols to implement different functionality. For example, an oil well sensor 404 can transmit data using a wired connection, infrared, or other wireless protocol to a receiver (not shown) connected via a computer interface, which can then route data through a high-speed Ethernet option to the main computer system 402 for data processing . Similarly, manifold mining units 414 may be connected to a host computer system 402 and / or remote computers 420 via a wired connection or a wireless protocol.

C. Nomenclature and definitions

In an asymmetric assessment of compliance with the technical requirements of the collector, many collector performance indicators are used, including both leading and lagging indicators that can provide information regarding the collector's DNA. In addition to the assessment, indicators of joint development, indicators of workload, indicators of a business plan and over-planned goals are used. These indicators and the indicator system, in general, use specialized terminology and variables, which can be difficult for a layman to understand. The following nomenclature and definitions are given to clarify and improve understanding of the disclosed system of indicators and their relationship to reservoir properties.

In _About - Volumetric coefficient of the oil reservoir. The volume in the conditions of the collector, divided by the volume in standard conditions, is dimensionless.

B _W - Volumetric coefficient of the water reservoir. The volume in the conditions of the collector, divided by the volume in standard conditions, is dimensionless.

C - The rate of decline in oil production, year ^-1

E _A - Area displacement coverage factor. Collector area in contact with the pumped fluid divided by the total area, dimensionless

E _D - The coefficient of microscopic displacement of oil. Volume of displaced oil divided by the total volume of oil in the reservoir, dimensionless

E _I - Coverage coefficient for power displacement. Collector power in contact with pumped fluid, divided by total productive power, dimensionless

E _R - Oil recovery coefficient or oil recovery coefficient. Estimated recoverable fraction of the initial hydrocarbon volume in the reservoir, dimensionless

E _RM - Oil recovery factor of mobile oil (MORE). Estimated recoverable proportion of initial oil reserves in the reservoir, dimensionless

E _RT - Theoretical Maximum Oil Recovery Factor (TMRF). The maximum proportion of initial oil reserves in the reservoir that can be extracted using a specific displacement method is dimensionless

E _V - Coverage ratio by volume or volumetric coverage. Collector volume in contact with the pumped fluid, divided by the total volume, dimensionless

E _W - Water cut coefficient. The resulting fraction of the volume of mobile oil initially in the reservoir, divided by the current water cut of the product, is dimensionless

EUR - Estimated total production. The sum of the confirmed and accumulated production at a particular point in time, stb (oil barrel, 159 l)

EUR - Depletion rate Annual production, expressed as a share of EUR, is dimensionless.

G _p - Total volume of gas produced, scf (cubic foot, 28l)

ΔG _p - The increment of the produced gas for a specific period of time scf (cubic foot, 28l)

II - - Pickup index. Intensity Discharge divided by an overpressure above the pressure in the reservoir, stb / psi (bbl (159 L) / lb / in ² (6.9 kPa)

II _M Median pickup index. Median II for all wells completed in a particular reservoir, stb / psi (barrel (159 L) / lb / in ² (6.9 KPa)

I _VI - The ideal index of vertical throttle response. II vertical completion of full penetration without skin effect, stb / psi (barrel (159 L) / psi ² (6.9 KPa)

II _DM - Dimensionless throttle response index. II _M, divided into median II _VI for a specific reservoir, dimensionless

KPI - Key Performance Indicators

MER - The most efficient production rate. The intensity of the selection in the reservoir, above which a significant decrease in EUR, stb / d (oil barrel (159 l) / day) should occur

L - Distance, feet (305 mm)

N - Initial oil reserves in the reservoir (OIIP), stb (oil barrel, 159 L)

N _M - Mobile Initial Oil Reserves in the Reservoir (MOIIP). Mobile oil volume in primary and secondary production (excluding EOR), stb (oil barrel, 159 L)

N _P - Cumulative produced oil, stb (oil barrel, 159 L)

N _PDe - Dimensionless amount of accumulated oil. It is expressed as the proportion of the forecast total return, dimensionless

N _PDm - Dimensionless amount of accumulated oil. It is expressed as the proportion of mobile initial oil reserves in the reservoir, dimensionless

N _PDo - The dimensionless amount of accumulated oil. It is expressed as the proportion of initial oil reserves in the reservoir, dimensionless

ΔΝ _Ρ - The increment of oil for a specific period of time, stb (oil barrel, 159 l)

p _c - Pressure at the outer boundary, psi (psi ² (6.9 KPa)

P _wf - Bottom hole flowing pressure, psi (lb / ⁱⁿ² (6.9 kPa)

Δp _dd - Depression on the reservoir. The pressure at the external boundary minus the dynamic pressure on the surface of the formation downhole, psi (lb / ⁱⁿ² (6.9 kPa)

Δp _dd - (M) Median depression on the reservoir. The average value of pressure drawdown for all applicable wells that have passed in a particular reservoir completions, psi (lb / ⁱⁿ² (6.9 kPa)

Δp _{dd (IV) - The} ideal vertical depression on the reservoir. Depression on the hypothetical vertical reservoir completions without full penetration of the skin effect, psi (lb / ⁱⁿ² (6.9 kPa)

Δp _{dd (DM)} - The dimensionless amount of median depression per formation. Median depression per reservoir, divided by the average ideal vertical depression per reservoir for a particular reservoir, dimensionless

PI - Productivity Index. Total working flow rate divided by the depression in the reservoir, bpd / psi (bbl (159 l) / day / lb / in ² (6.9 kPa)

PI _M - Median Productivity Index. The average PI value for all wells completed in a particular reservoir, bpd / psi (barrel (159 L) / day / psi ² (6.9 KPa)

PIIV - Ideal Vertical Productivity Index. PI hypothetical vertical completion of full penetration without skin effect, bpd / psi (barrel (159 L) / day / lb / in ² (6.9 KPa)

PIDM - Dimensionless Median Productivity Index. PI _M divided by median PI _IV for a specific collector, dimensionless

PV - Pore volume, stb (oil barrel, 159 L)

1P * - Confirmed reserves. Estimated volumes of hydrocarbons, indicated by geological and technical data with satisfactory certainty, that may become recoverable in future years from known reservoirs under existing economic and working conditions, stb (oil barrel, 159 l)

IP - Depletion Rate Annual production, expressed as the proportion of proven reserves, dimensionless

q _g - Gas production rate, mcfpd (million ft ³ (28 thousand m ³ ) / day)

q _o - Oil production rate, stbpd (oil barrel (159 L) / day)

q _w - Water withdrawal rate, stbpd (oil barrel (159 L) / day)

R - Gas factor, gas to oil ratio in production (GF), scf / stb (ft ³ (28 L) / oil barrel (159 L)

R _s - Gas factor for dissolved gas (gas solubility in oil), scf / stb (ft ³ (28 L) / oil barrel (159 L)

S _or - Residual oil saturation, fraction of pore volume

S _w - Water saturation, fraction of pore volume

VRR - Selection Compensation Factor. The injection volume divided by the obtained production volume for a specific time period. Defined both in surface conditions and in reservoir conditions, dimensionless

WC - Water cut. The volume of water divided by the volume of liquid for a specific period of time is dimensionless

W _i - The total volume of water used in the injection, stb (oil barrel, 159 l)

ΔW _i - The increment in the volume of injected water for a specific period of time, stb (oil barrel, 159 l)

W _p - Total water withdrawal, stb (oil barrel, 159 L)

AW _P - increment in water withdrawal for a specific period of time, stb (oil barrel, 159 l)

Equations

The methodologies and definitions used in the asymmetric assessment of compliance with the technical requirements of the collector are generally consistent with industry standards and technologies. The key standard for determining proved reserves is the United States Securities and Exchange Commission Regulation S-X (17 CFR 210.4-10-1 1/88). For probable and possible reserves and contingent reserves, the reference standard is the Petroleum Reserves and Resources Classification, Definitions and Guidelines of Society of Petroleum Engineers (SPE), American Associatuon of Oil Geologists (AAPG), World Oil Congress (WPB) and Society of Oil Evaluation Engineers (SPEE) (2006).

D. Collector Performance

The reservoir performance indicators used in the asymmetric reservoir compliance assessment (RCAA ™) are generally classified as leading indicators, lagging indicators, integrated development indicators, workload indicators, business plan indicators, and over-planned goals. In general, leading indicators are better for predicting future productivity and / or oil recovery than lagging indicators. Delayed indicators can, at the same time, provide an accurate accounting tool. Both types of indicators can be used to identify gaps between reality and the ideal case and to help improve production and oil recovery.

For each scorecard, unless otherwise expressly agreed, the conditions relating to specific units or other aspects are as follows:

Conditions

• Time interval: year

• Scale: Collector

• Pressure / temperature conditions: on the surface

• Units: English

1. Leading indicators

The following are examples of leading indicators that can be used in an asymmetric assessment of compliance with reservoir technical requirements.

. На Фиг.5А показана столбчатая диаграмма с примером сравнения по годам индекса истощенных скважин. Диаграмма также включает в себя линию, показывающую градиент истощенных скважин.The first leading indicator is the Depleted Wells Index. The related leading indicator is the Depleted Wells Gradient. The depleted well index is determined by dividing the number of depleted wells by the sum of both depleted and active production wells. The ratio is therefore dimensionless. The gradient of depleted wells is the normalized annual rate of change of the index of depleted wells:

. FIG. 5A shows a bar graph with an example of a year-by-year comparison of the index of depleted wells. The chart also includes a line showing the gradient of depleted wells.

. Градиент газового фактора является скоростью изменения соотношения газ/нефть:

. На Фиг.5B показана столбчатая диаграмма с примером сравнения по годам соотношения газ/нефть. Диаграмма также включает в себя линию, показывающую градиент газового фактора.The second leading indicator is the Gas Factor (GF). A related leading indicator is the “Gas factor gradient”, the gas factor is the gas / oil ratio in production:

. The gradient of the gas factor is the rate of change of the gas / oil ratio:

. FIG. 5B shows a bar graph with an example of a year-by-year comparison of the gas / oil ratio. The chart also includes a line showing the gradient of the gas factor.

. На Фиг.5C показана столбчатая диаграмма примера сравнения по годам изменения давления в коллекторе.The third leading indicator is “Manifold Pressure Change”. The pressure change in the reservoir is a volumetric change in the weighted average pressure in the reservoir:

. Fig. 5C is a bar graph of an example of a comparison of years of pressure change in the reservoir.

. Градиент темпа падения добычи нефти является годовым изменением в темпе падения добычи нефти, или

. На Фиг.5D показана столбчатая диаграмма с примером сравнения по годам темпа падения добычи нефти. Диаграмма также включает в себя линию, показывающую градиент темпа падения добычи нефти.The fourth leading indicator is the "Rate of decline in oil production." A related leading indicator is the "Gradient in the rate of decline in oil production." The rate of decline in oil production is a normalized change in annual oil production:

. The gradient in the rate of decline in oil production is the annual change in the rate of decline in oil production, or

. On fig.5D shows a bar graph with an example of a comparison over the years of the rate of decline in oil production. The chart also includes a line showing the gradient of the rate of decline in oil production.

и является безразмерным. Градиент коэффициента заводнения является нормализованной годовой скоростью изменения коэффициента заводнения:

.The fifth leading indicator is Waterflood Ratio. A related leading indicator is the Waterflood Gradient Gradient. The water flooding coefficient is determined as

and is dimensionless. The waterflood gradient is the normalized annual rate of change of the waterflood coefficient:

.

Fig. 5E is a bar graph with an example of a year-by-year comparison of the water flooding rate. The chart also includes a line showing the gradient of the waterflood coefficient.

. Градиент обводненности является нормализованной годовой скоростью изменения обводненности, или

. На Фиг.5F показана столбчатая диаграмма примера сравнения по годам обводненности. Диаграмма также включает в себя линию, показывающую градиент обводненности.The sixth leading indicator is Water Cut. A related leading indicator is the Water Cut Gradient. Water cut is the ratio of the volume of water to the volume of liquid during production and therefore is dimensionless:

. The water cut gradient is the normalized annual rate of change of water cut, or

. FIG. 5F shows a bar graph of an example of a comparison by year of water cut. The chart also includes a line showing the water cut gradient.

2. Delayed indicators

The following are examples of lagging indicators that can be used in asymmetric conformity assessment of manifold technical requirements. The first lagging indicator is the Average Production Liquid Fluid Rate, which includes both Oil Production Rate and Water Production Rate. Oil production rate is the rate of oil production, related to the number of wells: (q ₀ ) = ΔΝ _Ρ / 365 / number of active production wells, bpd (oil barrel, 159 l). Water flow rate is the rate of water withdrawal, related to the number of wells: (q _w ) = ΔW _P / 365 / Number of active production wells, bpd (oil barrel, 159 l). FIG. 6A shows a bar graph of an example of a comparison of years of oil production and water production.

The second lagging indicator is the Rate of Depletion. The first type of rate of depletion is the "Rate of depletion of the forecast total return (EUR)", which is ΔΝ _Ρ / EUR, and is dimensionless. The second type of depletion rate is the "Depletion Rate of Proven Stocks (1P)" and is also dimensionless: The depletion rate of 1P = ΔΝ _Ρ / 1P. FIG. 6B shows a bar graph of an example of a year-by-year rate of depletion of the projected total return (EUR) and rate of depletion of 1P.

The third lagging indicator is the "Exhaustion Status". The first type of depletion state is the “Forecasted Total _{Return Impairment State} ” and is dimensionless: (N _PDm ) = N _p / EUR. The second type of depletion state is the “Depletion State of Mobile Initial Oil Reserves in the Reservoir (OIIP)” and is also dimensionless: (N _PDm ) = N _p / N _M. The third type of depletion state is simply the OIIP depletion state. FIG. 6C is a bar graph of an example of a year-by-year comparison of the forecast state of exhaustion of total returns, state of depletion of rolling OIIP and state of depletion of OIIP.

The fourth lagging indicator is “Dimensionless Depression into the Formation”, dimensionless depression into the reservoir is determined by dividing the median depression into the reservoir by the median ideal vertical depression into the reservoir, and is dimensionless: (ΔP _{dd (DM)} = ΔP _dd / ΔP _{dd (IV)} ) _M . 6D shows a bar graph of an example of a comparison of years of dimensionless depression per formation.

The fifth lagging indicator is the Dimensionless Productivity Index. The dimensionless productivity index is obtained by dividing the median productivity index (PI) by the median ideal vertical productivity index: (PI / PI _IV ) _M. FIG. 6E shows a bar graph of a comparison example over years of the dimensionless productivity index.

The sixth lagging indicator is the “Dimensionless Injection Index”. The dimensionless pickup index is obtained by dividing the median pickup index (II) by the median ideal vertical pickup index: (II) _DM = (II / II _IV ) _M. FIG. 6F shows a bar graph of an example of a comparison over years of a dimensionless pickup index.

The seventh lagging indicator is "Gas flow rate". Gas production is the rate of gas production: (q _g ) = AG _p / 365, in mmsfcd million feet ³ (28 thousand m ³ / day). FIG. 6G shows a bar graph of an example of a comparison of years of gas production.

The eighth lagging indicator is Liquid Flow Rate. The first type of fluid flow rate is the "Maximum Effective Sampling Rate", (MER), thousand barrels / d (159 m ³ / d), and is the productivity of the selection from the reservoir above which a significant decrease in the estimated total return should occur. The second type of fluid flow rate is the “Oil production rate”, which is the rate of oil production: (q _g ) = ΔΝ _Ρ / 365, thousand barrels per day (159 m ³ / d). The third type of fluid flow rate is “Water flow rate”, which is the rate of water withdrawal: (q _w ) = ΔW _p / 365, thousand barrels per day (159 m ³ / d). FIG. 6H is a bar graph of an example of a comparison of the years of MER, oil rate, and water rate.

The ninth lagging indicator is the Pressure Gradient. The pressure gradient is the median pressure drop over distance, for example, the result of dividing the pressure drop between the production well and the injection well by the distance, or Δp / L, lb / in ² / ft.

The tenth lagging indicator is the Gradient Productivity Index. The gradient of the productivity index is a change in the median productivity index as a result of reservoir compression: I - (PI _M1 / PI _MO ), barrel / day / lb / in ² .

The eleventh lagging indicator is Debit Constraints. Restrictions on flow rate represent the sum of potential flow rates at the wellhead minus the amount of limited flow rates, thousand barrels / d (159 m ³ / d). Variations include dimensionless flow restrictions that are obtained by dividing the current restrictions by MSC, dimensionless.

The twelfth lagging indicator is the Oil Recovery Factor. The first type of oil recovery factor is the "Oil Recovery Factor": (ER) = EUR / N, dimensionless. The second type of oil recovery factor is the Mobile Oil Recovery Factor: (ERM) = EUR / NM, dimensionless. The third type of oil recovery factor is the theoretical maximum oil recovery coefficient: (E _RT ) = N _M / N, dimensionless.

The thirteenth lagging indicator is the "transmission index". The transmission index is the product of permeability by the cross-sectional area divided by the distance: kA / L, md-ft (millidar-foot).

The fourteenth lagging indicator is the Selection Compensation Ratio (VRR). The first type of selection compensation coefficient is “Surface selection compensation coefficient”, that is, VRR under pressure and surface temperature: ΔW _i / (ΔΝ _Ρ + ΔW _P ), dimensionless. The second type of sampling compensation coefficient is the "Collector sampling compensation coefficient", that is, VRR under reservoir pressure and temperature conditions: (ΔW _i × B _w ) / ((ΔΝ _Ρ × B ₀ ) + (ΔW _P × B _w )), dimensionless . FIG. 6I shows a bar graph of an example of a year-by-year comparison of the surface takeoff compensation coefficient and the reservoir takeoff compensation coefficient.

3. Specific development indicators

The first specific indicator of development is the "Cost Ratio". The first type of cost factor is the “cost factor for drilling”, which is the average annual initial rate of oil production divided by the cost of drilling and completion, bpd / $ (barrels (159 L) / day / USD). The second type of cost factor is the Overhaul Cost Ratio, which is the average annual initial rate of oil production divided by the cost of the overhaul, bpd / $ (barrels (159 L) / day / USD). Fig. 7A shows a bar graph of an example of a year-by-year comparison of the cost of drilling and the cost-of-repair ratio.

The second specific development indicator is the "coefficient of efficiency" (or the coefficient of efficiency of the rig). The first type of efficiency coefficient is the “drilling efficiency coefficient”, which is the average annual initial rate of oil production divided by the number of days required for drilling and completion, bpd (barrels (159 L) / d) / days of drilling rig operation. The second type of efficiency factor is the “Overhaul Efficiency Coefficient”, which is the average annual initial oil production rate divided by the number of days required for a well overhaul, bpd (barrels (159 L) / d) / days of the rig operation. FIG. 7B shows a bar graph of an example of a year-by-year comparison of the drilling efficiency coefficient and the overhaul efficiency coefficient.

The third specific development indicator is “Median Collector Contact”. The first type of median reservoir contact includes production wells that measure the median contact with production wells in feet (305 mm). The first type of median reservoir contact includes injection wells that measure the median contact of injection wells with the reservoir in feet (305 mm). FIG. 7C shows a bar graph of an example of a comparison of the years of the median contact of the reservoir of both production wells and injection wells.

4. Workload metrics

The first indicator of workload is training. The first type is the documentation or the number of documents sent to third parties for presentation and / or publication, counted over the year. The second type is the training days or the number of such days spent inside the company or at third-party training courses, divided by the total number of professional staff calculated for the year. The third type is training courses within the company, or the number of such courses within the company, calculated for the year. The fourth type is third-party courses, or the number of such courses, calculated over the year. On figa shows a bar graph of an example of a comparison of the years of various types of training.

The second indicator of workload is research. The first type is short-term, or ongoing research (excluding modeling) lasting less than twelve months, the calculated number for the year. The second type is long-term or ongoing research (with the exception of modeling) lasting more than twelve months, the calculated number for the year. The third type is simulation, or ongoing research in the form of numerical simulation, a calculated number for the year. The fourth type is special testing, or ongoing laboratory / field testing of new methods / technologies, the calculated number for the year. FIG. 8B shows a bar graph of an example of a year comparison of different types of studies.

A third indicator of the workload is the Well Fund. The first type of well stock is “new wells”, that is, the estimated number of new wells completed per year. The second type of well stock is "active (horizontal / sidetracks / inclined bends)", which gives the average number of active non-vertical production wells operating in a year, the calculated number for the year. The third type of well stock is the “total number of active”, which is the average annual number of active production wells calculated per year. FIG. 8C shows a bar graph of an example of a comparison of the years of well stock for each position, new wells, active (horizontal / sidetracks / deviated bends), and the total number of active ones.

5. The system of indicators of the business plan

The first indicator of a business plan is "fluid production rates." The first type of fluid production rate is the "oil production rate", that is, the forecast oil production rate for the five-year business planning cycle, thousand barrels / d (159 m ³ / d). The second type of fluid flow rate is the "rate of water withdrawal", that is, the predicted rate of water withdrawal for a five-year business planning cycle, thousand barrels / d (159 m ³ / d). The third type of fluid flow rate is “water cut”, that is, the forecast water cut for a five-year business planning cycle, thousand barrels per day (159 m ³ / d). On Figa shows a bar graph of an example of a comparison of the years of the rate of production of fluids for each of the following positions: the rate of oil production, the rate of water withdrawal, and water cut.

The first indicator of the business plan is "requirements for drilling production wells." The first item of requirements for drilling production wells is “new wells”, or the total number of production wells required to meet the predicted oil production rate, calculated for the year. The second position of the requirements for drilling production wells is “sidetracks”, or the total number of sidetracks from existing production wells to ensure the predicted rate of oil production, calculated for the year. FIG. 9B shows a bar graph of an example of a year-by-year comparison of drilling requirements for production wells, both new wells and sidetracks.

6. Superplanned goals

The first position of superplanned goals are “components”. The first position of the components of superplanned goals is "statistical": performance indicators over the past five years are taken into account in the long-term planning. The second position is "predictive": a five-year forecast of a business plan that takes into account the existing speed of implementation of new technologies and best practices. The third position is the “goal”: a five-year forecast taking into account 10% acceleration in the implementation of new technologies and best practices.

The second position of the superplanned goals is "the cost of development of production." The development development cost is the result of dividing the cost of drilling and completion by the total cost, $ / bpd (US $ / bbl (159 L) / d). Fig. 10A shows a bar graph of an example of year-by-year comparisons and projections of production development costs, in particular statistics, forecast and target.

The third position of the superplanned targets is the “Compensation Compensation Ratio” (VRR). One view is surface VRR, that is, VRR in surface conditions: ΔW _i / (ΔΝ _Ρ + ΔW _P ), dimensionless. FIG. 10B shows a bar graph of an example of year-by-year comparisons and forecasts of the coefficient of surface selection compensation, in particular statistics, forecast and target.

The fourth position of the superplanned goals is “Water cut”. Water cut is the ratio of the produced volume of water to the volume of liquid: ΔW _P / (ΔΝ _Ρ + ΔW _P ), dimensionless. Fig. 10C shows a bar graph of an example of year-by-year comparisons and water cut forecasts, in particular statistics, forecast and target.

7. Integrative scorecard

In asymmetric manifold conformity assessment, (RCAA ™) integrates a wide array of information; at the same time, the success of the assessment in obtaining optimal solutions is based on the possibility of filtering out non-critical parameters and revealing the fundamental areas of the collector with low performance. This is achieved thanks to a system of indicators called the "integrative system of indicators", the Integrative system of indicators (also called a "special system of indicators") includes:

1) Reservoir Development Management Rating, (RMRTM);

2) Production Profitability Index, (PGI ^ТМ ); and

3) Oil Recovery Reduction Indicator, (RDI ^TM ).

The integrative scorecard provides a numerical assessment of the critical parameters of the collector's work, which, in turn, becomes the basis of a continuous check for planning and implementing optimal solutions. As an example, a reservoir that receives a low RDI ^TM rating due to the fact that its project oil recovery is mismanaged. Specific case: a reservoir that is depleted without maintaining pressure or using secondary mining methods should have a low RDI ^TM quantity. Corrective action should take into account secondary production (e.g. flooding). The integrative scorecard should quickly indicate this direction. As a result, the correct application of an asymmetric reservoir conformity assessment (RCAA ™) should result in enhanced oil recovery and production rates, ensuring excellent capital utilization.

but. Reservoir Development Management Rating (RMRTM)

RMR ^TM is a structured approach to assessing the quality of reservoir development used in hydrocarbon production from a specific reservoir. The approach includes the use and analysis of a unique system of indicators, indices and results of quality measurements related to the physical condition of the reservoir, the location and operation of the wells (for example, production wells and injection wells), and the management of reservoir development (i.e. long-term planned production management and oil recovery). A detailed description of RMR ^{TM is} given in US Provisional Application No. 61 / 154,503, registered February 23, 2009. Under the name "METHOD OF ASSESSING THE QUALITY OF RESERVOIR MANAGEMENT", is incorporated herein by reference.

To implement RMR ^{TM, a} field is evaluated and reviewed (numerically evaluated) in six categories using a letter rating system (A, B, C and D). [Cm. table 2 below]. The literal assessment assigned to reservoir management provides a quick measurement tool for deciding on the possibility of increasing oil production and reserves.

The six categories and their definitions are as follows:

Reservoir Development Management Scheme: Technical calculations of reserves recovery and sampling rate (i.e. development project) according to best-in-class reservoir development management practices.

Increasing the value of stocks: Perform a development project revision to ensure maximum recovery of stocks (i.e. full cycle development project).

Field development and operation plan: Evaluation of the current calculation of extraction and development project to meet the required performance indicators.

Inspection and monitoring of the reservoir: creating a comprehensive plan for measuring and evaluating critical reservoir parameters to ensure the most efficient oil recovery and optimal reservoir performance.

Application of technology: use of the most appropriate technology available.

Management of the use of knowledge: Bringing to the right level of compliance with the technical requirements of company employees to achieve positive results.

Six categories can be rated according to the following criteria:

Reservoir management scheme

Is there a reservoir management scheme? Does the design include reservoir management principles? Are principles applied correctly?

Inventory value increase

Have stock component definitions been verified? Are the risks of obtaining and increasing stocks identified? Are emergency response plans prepared?

Field development and operation plan.

Are the goals set by the plan achieved?

Collector Inspection and Monitoring

Are survey programs working satisfactorily (do they track the required parameters appropriately)?

Technology application

Are acceptable technologies implemented to achieve the objectives of the oil recovery scheme? What is the willingness to consider and apply modern alternative technologies?

Knowledge Management

Are there ready-made systems for receiving, correlating, and transmitting information critical to the fulfillment of a mission?

ABBREVIATION DEFINITIONS FOR THE MANAGEMENT DEVELOPMENT MANAGEMENT RATING INDICATOR SYSTEM, (RMRTM)

The following is a list of acronym definitions used for the scorecard used for RMRTM:

CTI: Completion Technology Index

DEI: Displacement Efficiency Index

DM1: Depression Management Index

DPRI: Displacement Method Risk Index

DR: Risk of crowding out

DTI: Drilling Technology Index

EUR: Estimated Total Production

FDI: Field Depletion Index

FPDI: Field Productivity Index

GC: Geological Complexity

GMI: Gas Management Index

KMI: Knowledge Management Index

OVI: OIIP Confirmation Index (initial reservoir oil reserve) / GIIP (initial reservoir gas reserve)

PI: Mining Index

PMI: Pressure Management Index

PPAI: Production Plan Implementation Index

PSI: Production Shelf Feasibility Index

RDI: Impact Reduction Indicator

RDTI: Index for Optimizing Dynamic Collector Interpretation Technology

RMF: Risk Management Factor

RMI: Risk Reduction Index (RMI)

RVI: Stock Confirmation Index

SEI: Water Coverage Index

SPDI: Survey Plan Design Index

SPII: Survey Implementation Index

STI: Modeling Technology Index

VAG: gain value

VAR: Risk Amount

WMI: Water Management Index

WRDI: Well Production / Depression Index

QUANTITATIVE EVALUATION

Quantification is given using the following weights:

Categories Weight coefficient, % Reservoir management scheme 25 Inventory value increase 25 Field development and operation plan twenty Collector survey 10 Technology application fifteen Knowledge Management 5 TOTAL one hundred%

The above weights are used to generate the reservoir management management rating matrix (RMRTM), which identifies subcategories of the scorecard used to assess compliance with reservoir engineering specifications in various categories. The indicator system, in turn, is used to generate quantitative indicators. The reservoir management rating matrix (RMRTM) is shown below in Table 1.

Table 1 Reservoir Development Management Rating Matrix, (RMRTM) Category Reservoir Development Management Scheme (25%) Increased inventory value (25%) Field Development and Operation Plan (20%) Collector Survey (10%) Application of technology (15%) Subcategories Selection technical solution Confirmation of OIIP (initial reservoir oil reserves) / GIIP (initial reservoir gas reserves) Execution of the production plan Comprehensive Plan Technical Solution Drilling technology Pace of depletion birthplace Waterflood Field productivity implementation of a comprehensive plan Completion technology Well production / depression per formation Extrusion Efficiency Pressure management Simulation technology The risk of crowding out Stock Confirmation Gas management Dynamic Collector Interpretation Technology Mine shelf feasibility Risk reduction Water management Depression Management KNOWLEDGE MANAGEMENT (5%)

Scale of evaluation points for the development of reservoir management under RMR ^TM shown in Table 2 below.

table 2 Quantification assessment quality requirements rating corresponding points in computational analysis BUT **** 86-100 AT *** 76-85 FROM ** 61-75 D * 60 or less

Reservoir management scheme

The reservoir management scheme has a weighted value of 25% of the total reservoir development management rating (RMRTM). Important positions are: 1) whether there is a reservoir development management scheme, 2) whether the reservoir management principles are included in the scheme, and 3) the principles are applied correctly. As shown in Table 1 above, the reservoir management scheme includes five subcategories of equal weight relative to each other.

Subcategories (equal weight):

1. Selection Scheme

2. The rate of depletion of the field

3. Well production / depression per formation

4. The risk of crowding out

5. Feasibility of the mining shelf

The definition of each of the above subcategories related to the reservoir management scheme should be described in more detail.

Selection scheme

An indicator for the selection scheme is the Return On Demand (RDI ^TM ) indicator. A more detailed description of RDI ^{TM is} given in US Provisional Application Number 61 / 101,008, registered September 29, 2008 under the name "ASSESSING PETROLEUM RESERVOIR RESERVES AND POTENTIAL FOR INCREASE", incorporated herein by reference. RDI ^{TM is} set or determined as follows:

RDI ^TM = RE / IRE * 100

where RE is the design oil recovery factor for the current selection method

IRE (Perfect RE) = E _A * E _I * E _D = 1 * 1 * E _D = E _D

where E _A = the proportion of the area of the pore volume with the possibility of flooding, covered by the displacing fluid, the ideal case involves a coverage of 100%.

E _I = fraction of pore volume with the possibility of flooding by reservoir thickness, covered by displacing fluid, the ideal case involves a coverage of 100%.

E _D = fraction of moving oil (S _O -S _OR ) / S _O

Depletion Rate

An indicator for the rate of field depletion is the field depletion index (FDI). The field depletion index is set or determined as follows:

FDI = (annual production / EUR) * RMF * 100

where EUR = Estimated total production, oil barrels (159 L)

RMF = Risk Management Factor (defined in the following tables)

Table 3 Geological Complexity (GC) Variable Power Result Petrophysical variability High = 0 Medium = 1 Low = 2 0-2 stratification High = 0 Medium = 1 Low = 2 0-2 Disjunctive Disorder High = 0 Medium = 1 Low = 2 0-2 Shift High = 0 Medium = 1 Low = 2 0-2 Total 0-8

Table 4 Risk Management Factor Definition (RMFD) Variable Quantitative indicator Result Geological complexity GC / 8 * 20 0-20 Gas cap (1-gas fraction HC volume) * 20 0-20 Fluid composition Homogeneous = 20 Complex = 0 0-20 Mobility coefficient -15 * Log (M) +10 0-20 Total 0-80

* mobility coefficient

Table 5 Risk Management Factor (RMF) Risk assessment RMFD Result Low 60-80 one Average 40-60 1,5 Tall 0-40 2

Table 6 Field Depletion Index (FDI) FDI% Quantitative indicator <2 85 2-5 95 6-10 75 > 10 60

Well production / Depression on the reservoir

The indicator for well production / depression per formation is the well production / depression per formation index (WRDI), which can be determined according to the factors listed in Table 7.

Table 7 Well Production / Depression Index (WRDI) Critical issues Quantitative indicator Have analogues been used to develop guidelines for reservoir depression and production rates of individual wells? 0-30 Have empirical calculations been used to develop guidelines for reservoir depression and production rates of individual wells? 0-30 Have model studies been used to develop guidelines for reservoir depression and production rates of individual wells? 0-40 WRDI 0-100

The risk of crowding out

An indicator for the Extrusion Method Risk is the Extrusion Method Risk Index (DPRI), which is set or defined below. (Condition: IF the risk of losses in the extraction of 2P reserves is not determined, THEN we assign "60" to this subcategory and proceed to the next subcategory).

DPRI * DR * Q * 100

where DP = Risk of crowding out = (2P-V _A R _current ) / 2P

2P - Confirmed + Probable Reserves, oil barrels (159 L)

V _A R _current = 2P reserves at risk with the existing production mechanism, oil barrels (159 L)

Q = Quality of analysis measures the quality of 2P and VAR analysis (see table 8)

Table 8 Analysis quality analysis Q fine 0.9-1.0 above the average 0.8-0.9 average 0.6-0.8 unsatisfactory <0.6

Mine shelf feasibility

An indicator for the feasibility of the production shelf is the production shelf feasibility index (PSI), which is set or determined below and shown in Table 9. (Condition: IF the field development project does not provide for the maintenance of a constant production shelf, then assign “60” to this subcategory and go to next subcategory).

PSI =% EUR at the beginning of the decline in production * RMF

Where

the entry of the production decline process = the point at which no additional measures (for example, drilling new wells or overhauls) can stop the natural decline with the current displacement method.

RMF (See Field Depletion Rate for a value).

Table 9 Production Shelf Feasibility Index (PSI) % EUR at the beginning of the decline in production * RMF Quantitative indicator > 50 95 40-50 85 30-40 75 <30 60

Inventory value increase

The increase in the value of reserves has a weighted value of 25% of the total reservoir management management rating (RMRTM), important positions are 1) whether the definition of reserves components has been approved, 2) if the risks of obtaining and increasing the value of reserves have been identified, and 3) an emergency response plan has been prepared. As indicated in Table 1 above, the increase in inventory value includes five subcategories, with an equal weighted value relative to each other.

Subcategories (equal weighted values) are as follows:

1. Confirmation of OIIP (initial reservoir oil) / GIIP (initial reservoir gas)

2. Waterflood coverage

3. Efficiency of crowding out

4. Stock confirmation

5. Risk reduction

The definition of each of the above subcategories associated with the increase in the value of stocks is described in more detail below.

Confirmation of OIIP (initial reservoir oil reserves) / GIIP (initial reservoir gas reserves)

An indicator for OIIP / GIIP confirmation is the OIIP / GIIP Confirmation Index (OVI). OVI is determined according to the following criteria listed in Table 10.

Table 10 OVI Definition Critical question Result Range What is the geological complexity? GC / 8 * 20 0-20 What is the quality of the geological / petrophysical model? No = 0
Excellent = 20 0-20 What is the quality of research to evaluate the critical parameters of logs? No = 0
Excellent = 20 0-20 What is the quality of research / programs to confirm the profitability of the productive stratum, contouring of the field, S _wc , etc. No = 0
Excellent = 20 0-20 What is the quality of a comprehensive study of OIIP / GIIP, including petrophysical, geological and geophysical data No = 0
Excellent = 20 0-20 Ovi 0-100

Where

Geological Complexity (GC) Variable Power Result Petrophysical variability High = 0 Medium = 1 Low = 2 0-2 stratification High = 0 Medium = 1 Low = 2 0-2 Disjunctive Disorder High = 0 Medium = 1 Low = 2 0-2 Shift High = 0 Medium = 1 Low = 2 0-2 Total 0-8

Waterflood Efficiency

An indicator for waterflood coverage performance is the Waterflood Coverage Index (SEI). The waterflood coverage index is set or determined as follows (Condition: IF the collector is depleted or is undergoing compression, then “NO DATA” is assigned to this subcategory and proceeds to the next subcategory):

Water Coverage Index (SEI) = E _A * E _I * 100

Where E _A = fraction of the area of the pore volume with the possibility of flooding, covered by the displacing fluid according to the current plan,

Ei = fraction of pore volume with the possibility of flooding by reservoir power, covered by displacing fluid according to the current plan.

Extrusion Efficiency

An indicator for displacement efficiency is the displacement efficiency index (DEI). The displacement efficiency index is set or determined as shown in Table 11. (Condition: IF the collector is exhausted or experiencing compression, then “NO DATA” is assigned to this subcategory and proceeds to the next subcategory).

Table 11 Displacement Efficiency Index (DEI) Critical issues Quantitative indicator What is the quality of laboratory experiments to confirm displacement efficiency (E _D )? No = 0
Excellent = 30 What is the quality of field pilot work to confirm displacement efficiency (E _D )? No = 0
Excellent = 30 What is the quality of the analysis of laboratory experiments and field work to confirm displacement efficiency (E _D )? No = 0
Excellent = 40 Dei 0-100

Stock Confirmation

An indicator for confirming stocks is the stock confirmation index (RVI). The inventory confirmation index is set or determined as shown in Table 12.

Table 12 Definition of RVI Critical issues Result Quantitative indicator What is the quality of field and laboratory data on the rationale for 2P reserves No = 0
Excellent = 20 0-20 What is the quality of the field data of performance indicators to justify 2P reserves No = 0
Excellent = 30 0-30 What is the value of VAR (i.e. risk of losses) in connection with certain reserves of 2P No = 0
Excellent = 20 0-20 What is the value of VAG (i.e. the possibility of increasing prices) in connection with certain reserves of 2P No = 0
Excellent = 10 0-10 What is the quality of comprehensive research of laboratory data, petrophysics and geology and IOR / EOR justification of 2P reserves No = 0
Excellent = 20 0-20 RVI 0-100

Where:

VAR = 2P reserves at risk created by the existing production mechanism,

VAG = 2P reserves increase volume that can be extracted as a result of applying an enhanced reservoir management scheme.

Risk reduction

An indicator for Risk Reduction is the Risk Reduction Index (RMI). The risk reduction index is set or determined as shown in Table 13.

Table 13 Risk Reduction Index (RMI) Critical issues Quantitative indicator How correctly are key collector uncertainties identified and classified (0-10) * 3 How correctly are leading indicators or indicators identified by the results generating pessimism (0-10) * 1.5 How well prepared are plans to address the pessimistic deficiencies (0-10) * 1.5 How correctly identified are leading indicators or indicators for optimistic results (0-10) * 1.5 How well prepared are plans for using optimistic results (0-10) * 1.5 How well is learning and best practices reflected in technical solutions. (0-10) * 1.0 Rmi 0-100

Figure 1 shows in a graph how the total reservoir oil reserves can be increased while reducing risks resulting from the implementation of RMRTM.

Development and Operations Plan

The development and operation plan has a weighted value of 20% of the total reservoir development management rating (RMRTM). An important question is whether the required project objectives are being achieved and whether the operational goals are being achieved. As shown in Table 1 above, the development and operation plan includes six subcategories, with an equal weighted value relative to each other.

Subcategories (with equal weighted values):

1. Implementation of the production plan

2. Field productivity

3. Pressure management

4. Gas department

5. Water Management

6. Management of well production / depression per formation

The definition of each of the above subcategories related to the development and operation plan is described in more detail below.

Execution of the production plan

An indicator for fulfilling a production plan is the Production Plan Implementation Index (PPAI). The performance index for the production plan is set or determined by the following method, additionally shown in Table 14.

PPAI = Variation _{1 year} + Variation _{5 years}

Where

Variation _year = | (ΔNp _fact -ΔNp _plan ) / ΔNp _plan | * 100, for periods of 1 year and 5 years.

Table 14 Production Plan Implementation Index (PPAI) PPAI% Quantitative indicator <10 95 11-20 85 21-30 75 > 30 60

Field productivity

An indicator of field productivity is the Field Productivity Decrease Index (FPDI). The field productivity reduction index is set or determined as follows.

FPDI = (Σ J _fact / Σ J _plan ) * 100, Maximum = 100

Where

J = Production Index (PI)

J _plan = achievable field production index under current technology and current economic conditions.

Pressure management

An indicator for Pressure Management is the Pressure Management Index (PMI). The pressure control index is set or determined as follows (Condition: IF the collector is in the initial transition period, THEN we assign "NO DATA" to this subcategory and proceed to the next subcategory):

PMI = (Manifold pressure _fact / Manifold pressure _plan ) * 100, Maximum = 100

Gas management

An indicator for the Gas Administration is the Gas Management Index (GMI). The gas control index is set or determined as shown in Table 15. (Condition: IF there is no gas cap or gas injection, THEN assign "NO DATA" to this subcategory and proceed to the next subcategory).

Table 15 Gas Management Index (GMI) Critical issues Quantitative indicator What is the rate of change (ROC) of gas factor (GF) production? (1-ROC) * 30
Minimum = 0 What is the proportion of wells operated at or below the gas content of reservoir oil? Share * 30 What is the proportion of wells closed due to high GF? (1-10 * share) * 40 GMI 0-100

Where:

Change rate (ROB) = (GOR _end -GOR _start ) / GOR _start

Water management

An indicator for the Water Authority is the Water Management Index (WMI). The water management index is set or determined as follows.

WMI = (1-ROC _fact ) * 100, Maximum = 100, Minimum = 0

Where:

ROC = (WC _end -WC _start ) / WC _start

WC _end = measured average water cut at the end of the year

C _start = measured average water cut at the beginning of the year

Well production / depression control

An indicator for controlling well production / depression per formation (or managing depression per formation) is the Depression Control Index (DMI). The Depression Depression Management Index is set or determined as shown in Table 16.

Table 16 Depression Management Index (DMI) Critical issues Quantitative indicator % of wells operating with reservoir depression with flow rates within 10% of the design limit 0-100 Dmi 0-100

Collector survey

The collector survey category has a weighted value of 10% of the total reservoir development management rating (RMRTM). An important issue is the adequacy of the survey program (tracking the right parameters in the right way at the right time). K is shown in Table 1 above, the reservoir survey includes two subcategories with equal weighted values relative to each other

Subcategories (with equal weighted value):

1. Development of a comprehensive plan

2. Implementation of a comprehensive plan

The definition of each of the above subcategories related to the survey of the reservoir is described in more detail below.

Integrated Plan Development

An indicator for developing a comprehensive plan is the Survey Plan Development Index (SPDI). The survey design development index is set or determined as shown in Table 17.

Table 17 Survey Design Index (SPDI) Critical issues Quantitative
indicator Is there a documented comprehensive survey plan? Yes = 100
No = 0 Are physical processes in the reservoir at all levels considered in the design of the plan? Yes = 100
No = 0 Are the facilities and organizations considered in the development of the plan? Yes = 100
No = 0 Has a cost-effectiveness analysis been performed as part of the development of a survey plan to reduce and optimize the uncertainty of development and operation plans? Yes = 100
No = 0 Have key wells been identified for pressure and saturation measurements and has the frequency of measurements been determined? Yes = 100
No = 0 Is the plan defined the method (s) and frequency of measurements of production and injection rates? Yes = 100
No = 0 Is DOT and petrophysical measurements integrated in the plan (includes coring and special logging)? Yes = 100
No = 0 Does the test plan take into account and apply new survey technologies? Yes = 100
No = 0 SPDI (0-800) / 8

Implementation of a comprehensive plan

An indicator for implementing a comprehensive plan is the Survey Plan Implementation Index (SPII). The survey plan implementation index is set or determined as shown in Table 18.

Table 18 Survey Plan Implementation Index (SPII) Critical issues Quantitative indicator Is the comprehensive survey plan updated annually? Yes = 100
No = 0 Has the organization adopted the plan, including operations? Yes = 100
No = 0 What percentage of the wells foreseen by the plan are used? percent What percentage of coring and special logging is foreseen in the objectives of the plan before adoption? percent What percentage of the production and injection rates provided for in the plan is met? percent What percentage of data does the organization use effectively? percent SPII (0-600) / 6

Technology application

The Technology Application category has a weighted value of 15% of the total reservoir development management rating (RMRTM). Important questions are 1) whether the most appropriate technologies are being implemented to achieve the project selection goals and 2) how willing the collector owner or director is to accept modern or alternative suitable technologies. As shown in Table 1 above, the application technology category includes four subcategories with equal weighted values relative to each other.

Subcategories (with equal weighted value):

1. Drilling technology

2. Completion technology

3. Modeling technology

4. Optimization technology of dynamic interpretation of the reservoir

The definition of each of the above subcategories related to the application of the technology is described in more detail below.

Drilling technology

An indicator for drilling technology is the Drilling Technology Index (DTI).

The drilling technology index is set or determined as shown in Table 19.

Table 19 Drilling Technology Index (DTI) Critical issues Result Quantitative
indicator Have alternative drilling technologies been evaluated in the last 3 years? No = 0
Yes = 20 0-20 Have field trials of alternative drilling technologies been conducted in the last 3 years? No = 0
Yes = 40 0-40 Have alternative drilling technologies been deployed in the last 3 years? No = 0
Yes = 40 0-40 DTI 0-100

Completion technology

An indicator for Completion Technology is the Completion Technology Index (CTI). The completion technology index is set or determined as shown in Table 20.

Table 20 Completion Technology Index (CTI) Critical issues Result Quantitative indicator Have alternative completion technologies been evaluated in the last 3 years? No = 0
Yes = 20 0-20 Have field trials of alternative completion technologies been conducted in the last 3 years? No = 0
Yes = 40 0-40 Have alternative completion technologies been deployed in the last 3 years? No = 0
Yes = 40 0-40 Cti 0-100

Simulation technology

An indicator for modeling technology is the modeling technology index (STI). The modeling technology index is set or determined as shown in Table 21.

Table 21 Modeling Technology Index (STI) Critical issues Result Quantitative
indicator Have alternative modeling technologies been evaluated in the last 3 years? No = 0
Yes = 20 0-20 Has a field trial of alternative modeling technologies been conducted in the last 3 years? No = 0
Yes = 40 0-40 Have alternative modeling technologies been deployed in the last 3 years? No = 0
Yes = 40 0-40 STI 0-100

Optimization technology for dynamic interpretation of the reservoir

An indicator for an optimization technology for dynamic interpretation of a reservoir is an index for an optimization technology for dynamic interpretation of a reservoir (RDTI). The index for the reservoir dynamic interpretation optimization technology is set or determined as shown in Table 22.

Table 22 Index for Dynamic Collector Interpretation Optimization Technology (RDTI) Critical issues Result Quantitative
indicator Have alternative optimization technologies for dynamic reservoir interpretation been evaluated in the last 3 years? No = 0
Yes = 20 0-20 Has a field trial of alternative optimization technologies for dynamic reservoir interpretation been conducted in the last 3 years? No = 0
Yes = 40 0-40 Has a field trial of alternative optimization technologies for dynamic reservoir interpretation been conducted in the last 3 years? No = 0
Yes = 40 0-40 RDTI 0-100

Where

The optimization technology for dynamic interpretation of the reservoir includes technologies for reservoir evaluation and reservoir characterization, forecasting, survey and testing.

Knowledge Management

The knowledge management category has a weighted value of 5% of the total reservoir development management rating (RMRTM). Important questions are: 1) what are the organization’s obligations on knowledge sharing initiatives, 2) are the quality data complete, uniform and consistent, maintaining integrity and eliminating duplication, 3) does the owner or director have access to the virtual collaboration environment and how much does it use access to, and 4) whether the owner or director has access to daily, monthly, or annual reports important to your work.

An indicator for knowledge management is the Knowledge Management Index (KMI), which is determined or set, as shown in Table 23.

Table 23 Knowledge Management Index (KMI) Critical accounting Result Quantitative
indicator Awareness.
Knowledge of what and how to document and appropriate access to databases, etc. Data sources are accessible and easy to handle. (1-100)
* 0.20 0.2-20 Mode.
Technological processes are multifaceted, interactive, collaborative and computer-controlled. Data management plans are available and are being followed. Real-time data collection and availability. (1-100)
* 0.20 0.2-20 Output
Creation of databases, technical documents, lessons learned reports, best practice documentation, etc. Incomparable data sources integrate purposefully. Trends and deviations from the norm are identified and warned. (1-100)
* 0.30 0.3-20 results
Critical know-how is maintained and distributed throughout the company. KM acts on key indicators of the organization’s performance, such as reducing the time of technological cycles, improving the ratio of capital costs / operating costs and improving quality. (1-100)
* 0.30 0.3-20 Kmi 1-100

In whole or in part, the RMR ^TM method can be implemented using a conventional computer system comprising one or more processors, a non-volatile memory, a non-volatile memory or a memory system, and one or more data input / output devices. An example of a computer system 400 is discussed above and shown in FIG. 4.

According to one embodiment, to implement a reservoir development management rating (RMRTM), a method for assessing reservoir development quality in oil production from a reservoir includes: 1) establishing a scorecard for managing reservoir development for each of the following categories: a) reservoir development management scheme, b) increasing the cost of reserves, c) a plan for development and operation, d) reservoir inspection and monitoring, e) application of technology, and e) knowledge management; 2) weighted processing of data from a scorecard to manage reservoir development according to category; 3) obtaining data related to a system of indicators for managing reservoir development, at least some of the data being generated using at least one of the following: (I) measuring the physical properties of one or more existing production oil wells and / or reservoir wells , (II) the selection and analysis of one or more core samples from the reservoir, or (III) the establishment of the relationship between the data of one or more different types at positions (I) or (II); 4) generating a scorecard to manage reservoir development from data; and 5) determining a development management rating for an oil reservoir based on a scorecard for managing reservoir development, the reservoir development management rating relating to at least one of the following: production or withdrawal of oil from the reservoir.

b. ^TM production profitability index

Production Profitability Index ™ (PGI ^TM ) is a new leading indicator and indicator for quick assessment of potential for increasing the productivity of an exploited oil reservoir. A detailed description of PGI ^{TM is} given in US Provisional Application N61 / 101.024, registered September 28, 2008 under the name "ASSESSING PETROLEUM RESERVOIR PRODUCTION RATE THROUGH PRODUCTION GAIN INDEX", incorporated herein by reference.

The production profitability index for the oil reservoir is defined as:

A related index, the global productivity index (GPI ^TM ), defines how:

where ΣΔq _A = net actual increase in production, stbpd (standard barrel / day (159 l / d);

Σq _old = sum of current oil completions for existing production wells, stbpd (standard barrel / day (159 l / d);

ΣJ _new - the sum of the productivity indices of all production wells after the design deployment, stbpd (standard barrel / day (159 l / d) / day / psi ² (6.9 kPa);

ΣJ _old = the sum of the productivity indexes of all production wells prior to design deployment, (standard barrel / day (159 l / d) / day / lb / in ² (6.9 kPa); and

С _{Е -} Interference coefficient, an empirically derived coefficient taking into account losses in the cumulative increase in production due to interference of wells. Its formula is as follows:

The dimensionless production profitability index is based on the petroleum engineering concept d of the productivity index (J), which is a measurement of the well’s production capabilities. The index is defined as the stabilized well flow rate, measured under surface conditions, divided by the depression per wellbore. Depression on the reservoir is the difference between the static pressure at the bottom and the stabilized dynamic pressure at the bottom.

The Production Profitability Index (PGI) is a new way to quickly determine the total gain in oil production for a developed oil field (or reservoir) as a result of an increase in total well productivity. The means by which the total productivity of wells for a field can be increased include drilling additional existing production wells, treating existing wells to stimulate flow, and increasing contact with the reservoir of existing wells. PGI provides an opportunity for engineers, directors and investors to efficiently and quickly evaluate the oil production rate and the financial benefit based on field data for the implementation of certain types of investment projects. In general, PGI directly correlates with collector contact (i.e., the larger the increase in collector contact, the greater the predicted PGI).

According to one embodiment, an example of a method for determining a production increase index (RDI) includes: (1) determining or obtaining a net actual production increase, stbpd (standard barrel / day (159 l / d), (ΣΔq _A) , (2) determination or obtaining the sum of current oil production rates for existing production wells, stbpd (standard barrel / day (159 l / d), (Σq _old) , and (3) dividing the net actual increase in production by the sum of current oil production rates for existing production wells according to the following equation:

Alternatively, PGI can be determined by (1) determining or receiving interference ratio (C _E) for the collector, (2) identifying or obtaining global productivity index (GPI ^TM) which is a ratio of (a) the sum of all wells productivity indexes after the project deployments, (standard barrel / day (159 l / d) / day / lb / in ² (6.9 kPa), (ΣJ _new ) and (b) the sum of the productivity indexes of all production wells before design deployment, (standard barrel / day (159 l / d) / day / lb / in ² (6.9 kPa), (ΣJ _old), and multiplying the interference coefficient by the difference between the global productivity index (GPI ^TM ) and 1, according to the following equation:

As discussed above, the interference coefficient is determined according to the following equation:

c. ^TM return reduction indicator

Performance Reduction Indicator (RDI ^TM ) is a new leading indicator and indicator for quick assessment of potential for increasing withdrawal from the oil reservoir. As indicated above, RDI ^TM may form part of the development of the control reservoir analysis ranking (RMRTM). A more detailed description of RDI ^{TM is} disclosed in US Provisional Application Number 61 / 101,008, registered September 29, 2008, under the name "ASSESSING PETROLEUM RESERVOIR RESERVES AND POTENTIAL FOR INCREASE", incorporated herein by reference. RDI ^TM is determined from the ratio of rate of oil recovery reservoir (RE), or the recovery factor and its ideal recovery factor (IRE). The indicated is represented by the following formula

RDI = RE / IRE

The oil recovery factor (RE) for a given oil reservoir is defined as the product of three coefficients

RE = E _A * E _V * E _D

where E _A = areal displacement efficiency, which is a fraction of the area of the pore volume with the possibility of coverage during flooding by the displacing fluid;

E _V = displacement efficiency by reservoir power, which is a fraction of the power of the pore volume with the ability to cover the displacing fluid; and

E _D = pore displacement efficiency, which is the fraction of oil saturation at the beginning of injection, which is displaced by the displacing fluid in the flood zone.

Pore displacement efficiency (E _D ) can be calculated using the following formula:

E _D = 1- (S _or / (1-S _WC ))

wherein S _or defined as a residual oil, which can be measured on core plugs samples in the laboratory after waterflooding Ten pore volumes displacing fluid; and

S _WC is water saturation under initial reservoir conditions.

The determination of the ideal oil recovery coefficient (IRE) for the reservoir is based on the concept of the oil recovery coefficient (RE), which is traditional for oil production technology, which, as indicated above, can be defined as the ratio of the volume of oil produced to the volume of initial oil reserves in the reservoir (OIIP). The values or calculated values of E _A , E _V and E _D can be determined at the field when operating existing parametric wells or by drilling and logging in new wells at the reservoir coverage areas. At the same time, the experience of operating oil reservoirs with a long life cycle in the Middle East and East Texas indicates that the values of E _A and E _V can reach 100%, especially when using modern production technologies (for example, drilling, completion, reservoir evaluation, reservoir simulation, etc.). The ideal reservoir efficiency can be inferred from reservoir efficiency by assuming that both E _A and E _{V are} 100%. With the adoption of ideal volumetric coverage, the IRE equation is simplified, requiring only the definition of E _D. In other words, the ideal oil recovery factor for a given oil reservoir can be expressed by the equation

IRE = E _D.

Reservoir Efficiency Reduction Indicator (RDI ^TM ) values can be divided into five ranges or groups of numerical values of reservoir efficiency reduction ("RDS"), which can be used to assess and highlight degrees of lack of coverage and potential actions to adjust actual returns versus ideal reservoir returns . According to one example, the numerical values of the decrease in reservoir efficiency can be summarized in Table 24, shown below:

Table 24 RDI range Rds Act 100-90 BUT Possibility of improvement is small 90-80 B Limited improvement possible 80-60 C Possible improvement 60-40 D Significant improvement possible <40 F Requires a general audit

According to one embodiment, an example of a method for determining a return loss indicator (RDI ^TM ) and a corresponding reservoir efficiency reduction indicator (RDS) for an exploited field or reservoir includes: (1) determining or obtaining an area displacement efficiency (E _A ); (2) determining or obtaining displacement efficiency by formation thickness (E _V ); (3) determining or receiving pore displacement efficiency (E _D); (4) determination of oil recovery coefficient (RE) based on areal displacement efficiency (E _A ), displacement efficiency by reservoir thickness, and pore displacement efficiency; (5) determination of the ideal oil recovery coefficient (IRE), assuming that the area displacement efficiency (E _A ) and the displacement efficiency by reservoir thickness (E _V ) are 100% and setting IRE = E _D ; (6) determining a performance reduction indicator (RDI ^TM ) by determining the relationship between the oil recovery coefficient (RE) and the ideal oil recovery coefficient (IRE); and (7) assigning a quantitative indicator of collector efficiency reduction (RDS) based on a performance reduction indicator (RDI ^TM ). All or part of the above method can be implemented using a conventional computer system containing one or more processors, a volatile memory system, a non-volatile memory system or memory device, and one or more data input / output devices.

Very high return reduction indicators may indicate a highly efficient reservoir with successfully implemented techniques and long-term selection plans. On the other hand, very low quantitative indicators indicate significant opportunities for improvement, giving higher total returns and potential reserves. Quantitative indicators exceeding 100%, or which are incredibly close to 100%, may be evidence of fraud on the part of the owner of the collector.

8. Research Q6

At least part of the information that is used to assess compliance with the technical requirements of the collector is collected using Q6 studies. The following is an example of Q6 research questions that may be answered by the owner of the collector or director to assist in assessing compliance with the technical requirements of the collector.

How is reservoir management managed?

o at the organization level

o at the level of the method

o not established, or formal implementation

How is reservoir management evaluated?

o High

o Average

o Low

What are the specialties of members of the object group?

o field operation engineers

o production engineers

o drilling engineers

o drillers

o geologists

o petrophysicists

o technical specialists

o business development specialists

o other

How do you describe reservoir management guidelines?

o Documented and clearly defined

o Documented

o Not documented and not clearly defined

How do you describe best practices for reservoir management?

o Documented and clearly defined

o Documented

o Not documented and not clearly defined

How do you describe the flow chart / reservoir design project?

o Documented and clearly defined

o Documented

o Not documented and not clearly defined

How often is the performance evaluation carried out in the field?

o Once every six months

o annually

o As required

o Never

o Other

What is the current annual rate of decline in oil production?

o 0%

o 1-10%

o 11-20%

o> 20%

What is the state of the past five years, with the fulfillment of forecasts for the reservoir?

o exceeded

o satisfied

o underfulfilled

What is the main reason for the decline in oil production?

o Increased water cut

o Increased GF

o Pressure drop

o formation damage

o Surface restrictions

o Other

What is the main thing in the mechanism (mechanisms) of the collector operation mode?

o pressure reduction due to depletion

o displacement by dissolved gas

o expansion of the gas cap

o displacement by regional water

o plant water displacement

o Compression

o Other

If there is a gas cap, what is its nature?

o primary

o secondary

o reverse gas injection

What is the dominant force affecting current reservoir performance?

o gravity

o viscosity action

o capillary action

Is there a pressure maintenance program in place?

o water injection

o reverse gas injection

o nitrogen injection

o water and gas repression

o other

What is the injection pattern?

o peripheral

o five-point system

o nine-point system

o linear displacement

o other

In general, how do you describe the direction of crowding out?

o transverse

o bottom to top

o top to bottom

o other

What is the reservoir compensation coefficient for the year (discharge RB / production RB for the year)?

o <1

o 1-2

o> 2

What is the ratio of oil mobility to displacing water?

o ≤1

o> 1

How do you describe waterflood coverage by area?

o uniform

o with a predominance of local heterogeneities (for example, clusters of cracks)

o linguistic

What is the current area coverage factor for the displacement process beyond the flood front?

o> 90%

o 70-90%

o 50-70%

o <50%

o unknown

How do you describe the coverage by reservoir power by flooding?

o flat

o susceptible to language formation (e.g. water over oil)

o prone to water cone formation

What is the current power coverage rate of the displacement process beyond the flood front?

o> 90%

o 70-90%

o 50-70%

o <50%

o unknown

How do you describe the reservoir’s propensity for water / oil cones?

o High

o average

o low

How do you describe the reservoir’s propensity for gas / oil cones?

o High

o average

o low

How do you describe the water flooding rate?

o High

o Medium

o low

What methods are used to combat high water cut and gas factor in existing production wells?

o installation of the return union on the surface

o closing

o grouting

o sidetracking

o adjustment of the sliding sleeve

o other

o no

What percentage of production wells have problematic channel formation behind the pipe?

o 0%

o 1-5%

o 5-10%

o 10-20

o> 20%

What is the maximum effective production level (MER) for the reservoir (annual production / reserves)?

o <2%

o 2-5%

o> 5%

How are collector performance indicators evaluated?

o on indicators of key performance indicators (KPI)

o comparing with similar collectors

o comparing with simulation forecasts

o other

What problems arise in realizing production goals?

o drilling a sufficient number of wells

o increase compliance with technical requirements of facilities

o introduction of new technologies

o other

Over the past five years, how do you describe the overall performance of the collector?

o improved

o lowered

o invariable

Who performs reservoir performance modeling?

o on their own

o subcontractor

What is the dominant displacement force in the model?

o gravity

o viscosity action

o capillary action

What types of models (models) of collector performance indicators are used?

o finite difference

o flow lines

o material balance

o others

o no

What options are used for finite difference model (s)?

o oil residues

o composition

o thermal

o double porosity

o double permeability

What is the main option (s) for using the model (s)?

o development

o operation

o return

Who is involved in setting up the model according to development data?

o modeling engineer

o field operations engineer

o geologists

o other

What were the design parameters for the development of the field?

o depletion / working rate

o depression on the reservoir

o well grid density

o number of wells

o discharge circuit

o type of pumped fluid

o well completion geometry

o manifold pressure

o return

o other

How was risk and uncertainty taken into account in optimizing the oil production rate?

o deterministic sensitivity studies

o conducting statistical modeling studies using experimental design

o other

o Not taken into account

What aspects of model forecasts are consistent with performance data?

o oil, water and gas field production rates

o reservoir pressure at the field scale

o operating rates for oil, water and gas at the well scale (> 75% approval)

o pressure in the reservoir on a well scale

o pressure in the zone

o saturation in the zone

What stock accounting standard is used by the company?

o Post 2007 SPE et al.

o Pre 2007 SPE et al.

o U.S. Security Exchange Commission (US Securities Commission)

o internal

o other

How are company stocks valued?

o internal audit

o external audit of a third-party organization

o no

Who is responsible for the inventory report?

o oil production technology department

o intelligence department

o planning department

o other

What methods are used to reflect stocks on the balance sheet?

o deterministic

o probabilistic

How are stocks calculated?

o according to the production decline curve

o modeling

o material balance

o OIIP mapping (initial reservoir oil reserve) in combination with oil recovery factor

o by analogy

o other

How have P1 confirmed / reserves changed over the past five years?

o increased

o decreased

o remained unchanged

What problems need to be addressed to maintain targets for total returns?

o drilling a sufficient number of wells

o increase compliance with technical requirements of facilities

o introduction of new technologies

o other

What is the forecast area coverage at the end of the flood?

o> 90%

o 70-90%

o 50-70%

o <50%

o Unknown

What is the predicted power coverage at the end of the flood?

o> 90%

o 70-90%

o 50-70%

o <50%

o unknown

What logging measurements of residual oil saturation were carried out in reservoir areas with satisfactory waterflooding?

o indicator logging

o neutron logging

o nuclear magnetic logging

o double isotopic / lateral logging

o indicator substances

o other

What specialized core sampling programs have been used in determining residual oil saturation?

o selection with a sponge core receiver

o selection with a sealed core receiver

o side logging

How was the theoretical residual oil saturation for water determined?

o laboratory experiments

o field observations

o by analogy

To determine the relative permeability of water / oil, what types of laboratory experiments were the most reliable?

o flooding in equilibrium

o flooding in a nonequilibrium state

o centrifugation tests

How was the theoretical residual oil saturation of the gas determined?

o laboratory experiments

o field observations

o by analogy

To determine the relative permeability of gas / oil, what types of laboratory experiments were the most reliable?

o gas injection in equilibrium

o gas injection in a nonequilibrium state

o centrifugation tests

III. IMPLEMENTATION OF ASYMMETRIC ASSESSMENT OF COMPLIANCE WITH TECHNICAL REQUIREMENTS OF THE COLLECTOR, (RCAA ™)

A detailed description of RCAA ™ is available in the appendix to U.S. Application. Provisional Application N61 / 031,167, registered February 25, 2008, under the name "METHOD FOR DYNAMICALLY ASSESSING PETROLEUM RESERVOIR THROUGH ASYMMETRIC ANALYSIS OF PERFORMANCE METRICS", the description of which is incorporated herein in its entirety and included in the appendix (hereinafter referred to as the "RCAA document "). The RCAA document includes various sections, including an executive review and workbook of the client, SME (expert in this field). The executive review briefly describes the RCAA ™ and its purpose, and includes subsections related to the preamble, QRI® (total reservoir impact), reservoir management model, main focus areas, and gap analysis. The client’s workbook, SME, includes subsections related to Q6 research, knowledge systems, in-depth understanding tools, Q-factor diagnostics, gap analysis and action plan (see Figure 1). The various details of an asymmetric assessment of compliance with reservoir technical requirements interact with each other in a synergistic manner to maximize the possibility of a reasonable increase in reservoir productivity (i.e., production and reserves).

In addition to the direct measurements of the scorecard described in this document, examples of information collection methods may include knowledge systems, Q6 Research, and deep understanding tools to ensure that all relevant information is obtained. In many cases, relevant information can be collected in just 72 hours or in the long 180 days. Typically, it may take about 90 days to accumulate relevant information regarding the current state of the reservoir.

The examples of the knowledge complex use the collection of information related to a specific collector, including data on production and drilling, core and laboratory testing of DOT, testing of special analyzes, well construction, well design, geophysics, petrophysics, geology, selective and monitoring of field tests and collector data.

Continuous monitoring of some scorecards can be provided by "dashboards" that provide real-time display of various scorecards. The dashboard can provide instant monitoring of many dynamically changing variables at once. The panel may include start-up circuits or accident indication systems, such as highs or lows, which, when encountered, may require affirmative steps to change production behavior. This includes, for example, closing or opening valves in the wellbore, throttling or increasing the flow rate by correcting the operation of the impellers, turning on or changing the operation of the pumps to increase the flow rate, performing perforations in the pipes to start oil removal in some places in the wellbore and treatment of existing wells to stimulate the flow, for example by hydraulic fracturing or acid treatment of the formation to increase the volume of the rock, giving the flow of oil.

A. Conformity assessment of manifold specifications

According to one embodiment of a sequential asymmetric conformity assessment of reservoir technical requirements, (RCAA ™), a method has been developed for assessing compliance with technical requirements of an oil reservoir with respect to production and oil recovery to initiate the development of an action plan to increase production and / or oil recovery, comprising: 1) establishing a variety of performance indicators reservoir, which relate to the production and return of oil from the reservoir; 2) the multiplication by the weight coefficient of one or more indicators of the collector’s performance with the establishment of a higher weight than at least one other collector’s work indicator to perform asymmetric analysis of the collector’s performance; 3) obtaining data related to the performance of the reservoir, and the data is generated using at least one of the following: (I) measuring the physical properties of one or more existing production oil wells and / or injection wells, (II) selecting and analyzing one or several core samples from the reservoir, or (III) establishing the relationship between the data of one or more different types at positions (I) or (II); 4) the generation of indicators of the collector according to data; and 5) determining the rating of compliance with technical requirements for the oil reservoir based on an asymmetric analysis of the performance of the reservoir, moreover, the rating of compliance with technical requirements related to at least one of the following: production or withdrawal of oil from the reservoir.

According to one embodiment, data related to the performance of the collector is input into a computer, which then analyzes and displays the data in one or more forms, such as detailed sheets and tables (for example, shown in FIGS. 5-10). The displayed data can be used to assess compliance with reservoir technical requirements. In general, the worse the existing managed and operated collector, the more benefits you can get from implementing the asymmetric conformity assessment (RCAA ™) methodology.

The system of indicators that are most important in assessing compliance with the technical requirements of the collector includes the leading indicators described above. Examples of useful leading indicators include an index of depleted wells, an gradient of depleted wells, a gas factor, a gradient of a gas factor, a change in reservoir pressure, a rate of decline in oil production, a gradient in the rate of decline in oil production, a waterflood coefficient, a gradient of a waterflood coefficient, a rate of decline indicator or an index profitability mining.

Less useful, but certainly related to the volume used in the asymmetric reservoir conformity assessment (RCAA ™), are lagging indicators. Examples of useful lagging indicators include average production fluid flow rates, oil production rate, water production rate, depletion rate, estimated total return depletion rate, 1P confirmed reserves depletion rate, depletion state, forecasted total depletion depletion state, mobile initial depletion state oil reserves in the reservoir, dimensionless depression on the reservoir, dimensionless productivity index, dimensionless injectivity index, gas rate, fluid rate, maximum effective I selection rate, pressure gradient, productivity index gradient, production rate limits, dimensionless production rate limits, oil recovery coefficient, oil recovery coefficient, mobile oil recovery coefficient, theoretical maximum oil recovery coefficient, transmission index, selection compensation coefficient, surface extraction compensation coefficient, collector compensation factor.

Another useful scorecard for assessing compliance with the technical requirements of the oil reservoir includes unit development metrics, workload metrics, business plan metrics, and overplanned goals.

According to one embodiment, a scorecard may be selected and weightings may be assigned to it as described above in the section regarding the reservoir development management rating (RMRTM). In general, an asymmetric assessment of compliance with the technical requirements of the reservoir helps to understand the specific DNA or state of affairs in the reservoir, which provides a correct idea of the action plan to increase productivity and oil recovery to be developed. With additional information on the collector, another scorecard may become more or less important for analysis. Asymmetric Collector Specification Assessment (RCAA ™) provides data distillation. A complex picture is taken, which may not make sense and is distilled to obtain a very clear picture. The above helps to develop a more reasonable and successful action plan and provides a means of measurement for the implementation of the action plan. Asymmetric manifold conformity assessment (RCAA ™) constantly acts as a guiding mechanism in the organization.

According to one embodiment, the principles relating to the Six Sigma Quality Control System (6Σ) can be applied in aspects of the reservoir underground. The goal of 6Σ is to identify objects with deviations that are far from average, for example, existing production oil wells. In many cases, objects with deviations may simply be “black sheep” suitable for well closure. At the same time, objects with deviations may in some cases be the most productive oil wells of the reservoir. They may be close to ideal and serve as an example for other oil wells or provide information on favorable underground conditions in the vicinity of oil wells, which are objects with deviations. Objects with deviations can be identified, for example, using a measure of the productivity gradient to compare the productivity of oil wells throughout the reservoir.

According to one embodiment, a method for assessing compliance with the technical requirements of an oil reservoir includes determining a reservoir development management rating using asymmetric weighted data processing performance indicators that belong to the following categories: reservoir development management scheme, increasing the cost of reserves, development and operation plan, reservoir inspection, technology application and knowledge management. Performance indicators related to reservoir management design including oil recovery, field depletion rate, well flow rate / depression on the formation, risk of displacement method and feasibility of the production shelf. Performance measures related to increasing the value of reserves include OIIP (initial reservoir oil) / GIIP (initial reservoir gas) confirmation, waterflood coverage, displacement efficiency, stock confirmation, and risk reduction. Performance indicators related to the development and production plan include the implementation of the production plan, field productivity, pressure management, gas management, water management, and reservoir depression management. Performance indicators related to reservoir surveys include the development of an integrated plan and the implementation of an integrated plan. Performance indicators related to the application of the technology include drilling technology, completion technology, modeling technology and optimization technology for dynamic interpretation of the reservoir. Performance indicators related to knowledge management include a knowledge management index. According to one embodiment, the above performance indicators are weighted according to the following criteria for weighting data: reservoir management scheme ≈ increase in inventory value> development and operation plan> application of technology> reservoir survey> knowledge management.

Other major factors that may influence or determine compliance with reservoir specifications include, for example, factors related to the percentage of return on investment (PGI), such as the level of reservoir contact, formation damage during completion, and borehole diameter. Factors affecting the potential for formation damage include, for example, the type of rock, the speed of drilling, and the pressure balance during drilling (for example, repression can cause damage to the formation, which can cause release during depression). For example, the safe operation of drilling equipment may require 500 pounds (227 kg) of overload. However, a higher excess load can cause damage to the well by crushing the drilling fluid into the well. The indicated, in turn, may preclude obtaining a satisfactory well inflow. The remedy for the low productivity index, (PI) may be, for example, one or more of the following: acid treatment, acid treatment with hydraulic fracturing (i.e., cracking), high pressure hydraulic fracturing, and rinsing with water.

Other factors that may influence or determine compliance with reservoir specifications include, for example, factors related to the Production Increase Index (RDI), such as areal coverage, reservoir thickness coverage, displacement efficiency, pore mouth, and lithology. The above mainly helps in the analysis of the gap, with the help of which the difference between the specified indicators of production wells and the current production and oil recovery is estimated.

In addition, external factors can be influenced, the system of indicators of which is the most important. Factors include economic factors (that is, what is the owner’s horizon of the relationship between the dollars spent and the dollars received according to the plan for increasing returns using an asymmetric reservoir conformity assessment (RCAA ™). Another external factor includes risk factors. In general, risk factors can be reduced if the selection plan is developed appropriately.

B. Development of an action plan

The action plan according to the asymmetric reservoir conformity assessment (RCAA ™) is formulated on the basis of appropriately collected, analyzed and weighted data for a particular reservoir. The action plan is a comprehensive development plan with details regarding an agreed system of indicators and indicators of key performance indicators. Since the action plan is based on an accurate assessment of the short-term, medium-term and long-term conditions of the reservoir and is made suitable for the specific conditions of the reservoir and / or the requirements of the manufacturer, the action plan has a higher chance of success, the result of which is a short-term, medium-term and long-term increase in production and profit in comparison with the possibilities that are represented by the use of conventional methods.

In one embodiment, developing a plan for increasing productivity and / or return includes obtaining data from the diagnostic step described above and working with production wells to understand the benefits and limitations of one or more possible action plans. Using a reservoir management management rating (RMRTM), for example, should help develop a rating system that allows the manufacturer to correctly evaluate the required action plan. Meetings can be held to develop various action plans to determine the best work, taking into account the goals of the manufacturer.

In general, a compromise is made between long-term and short-term prospects or goals. For example, if the production well has a short-term perspective, which may occur if capital is limited (for example, according to the terms of the company, investors and / or lenders), the producer may have limited initial investments to improve compliance with the technical requirements of the reservoir, which should generally increase the initial return investment, but by reducing long-term production and total return. The increase in long-term production and oil recovery, created later, should, in general, be more expensive in the long run with this approach. On the contrary, a manufacturer with the ability to work in the long term can make higher initial investments in improving compliance with the technical requirements of the collector. At the same time, in general, the initial return on investment decreases, but long-term productivity and oil recovery increase, which results in a decrease in overall costs to maximize productivity and oil recovery.

According to one embodiment, a method for developing an action plan for increasing production and oil recovery from an oil reservoir comprises: 1) performing an asymmetric analysis of the oil reservoir to determine compliance with the technical requirements of the reservoir, wherein the asymmetric analysis is performed by multiplying one or more reservoir performance indicators by weight, making the weight more than at least one of the other collector performance indicators; 2) the establishment of at least one of the following: the required rate of depletion or the necessary rate of production and the total return for the oil reservoir; 3) the construction of an oil reservoir model that defines the location of oil in the reservoir, which includes at least one of the following: connectivity or lack of connectivity of oil in the reservoir, potential paths of oil flows as a result of oil extraction from the reservoir at natural flow rate and / or fluid pressure in the manifold and / or injection of auxiliary fluids into the manifold; and 4) development of an action plan, which includes the production architecture, relating to: I) existing oil production wells, i.e. their number, location, design and production data, II) the volume of injection of auxiliary fluids (for example, water and / or gas) to facilitate the displacement of oil into existing production wells, i.e. data on the use of one or more injection wells and the volume of auxiliary fluids injected through one or more injection wells important, and if necessary III) treatments to stimulate the inflow of one or more existing existing production wells to increase productivity (for example, to remove clogging and / or increase inflow through the rock).

According to one embodiment, performing an asymmetric analysis of the oil reservoir to determine compliance with the technical requirements of the reservoir includes determining a development management rating for the oil reservoir, wherein the reservoir development management rating is determined by asymmetric weight processing of performance data related to the following categories: reservoir development management scheme , increasing the value of stocks, a plan for the development and operation, survey collect Ora, the use of technology, and knowledge management. At least one of the following: performing an asymmetric analysis, establishing the required production rate and total return, building an oil reservoir model, or developing an action plan, is carried out using a computer system that has a processor and system memory and displays information on the oil reservoir.

According to one embodiment, the generation of the oil reservoir model is carried out at least partially by a computer system, the oil reservoir model comprising at least one of the following: a numerical model or a visual display device of some or all of the oil reservoir.

The method for developing an action plan may further comprise developing an architecture related to auxiliary fluids, including separating auxiliary fluids from oil recovered from the reservoir, and processing auxiliary fluids. For example, auxiliary fluid architecture includes at least one of the following: disposing, re-injection, or sale of auxiliary fluids.

As discussed above, setting the required production rate and total return for the oil reservoir, generally take into account the intentions of the manufacturer to invest in increased production and oil recovery from the reservoir. To maximize both production and long-term productivity, an action plan or architecture of production includes the development and construction of at least one well with maximum contact having many lateral, at least partially horizontal shafts. This type of well is called a “maximum reservoir contact hole” (MRC). An example MRC well is shown in FIG. 11 and includes several sidetracks 1100 including a plurality of spaced apart well sections 1102 extending generally horizontally through one or more collector layers 1104. Well sections 1102 may also be vertical for better drainage of oil found at various reservoir depths. In general, an MRC well is used to better drain oil in hydraulically unconnected cavities.

C. Implementation of the action plan

Another aspect of the asymmetric assessment of compliance with the technical requirements of the collector is the implementation of an action plan formed on the basis of appropriately collected and analyzed data with the assignment of weighting factors for a specific collector. According to one embodiment, an action plan is developed taking into account the reservoir development management rating (RMRTM) and to increase reservoir productivity and / or return.

According to one embodiment, a method for implementing an action plan for increasing production and oil recovery from an oil reservoir is created, comprising: 1) obtaining an action plan developed using asymmetric analysis of the oil reservoir to determine compliance with the technical requirements of the reservoir, moreover, the asymmetric analysis is performed by multiplying by the weight coefficient one or more collector performance indicators, making their weight greater than at least one of the other collector performance indicators a, and the action plan includes a production architecture regarding: I) new operating oil production wells, that is, their number, location, design data, II) auxiliary fluid injection volume to facilitate the displacement of oil in the reservoir into existing production wells, that is, data on the use of one or more injection wells and the volume of auxiliary fluids injected through one or more injection wells, and, if necessary, III) treatment and to intensify the influx of one or more existing existing production wells to increase productivity; 2) the placement of new existing production oil wells at the sites of the oil reservoir and the construction of new existing production oil wells in accordance with the action plan; and 3) the placement of injection wells at the oil reservoir sites in accordance with the action plan to facilitate the displacement of oil in the reservoir into new existing production oil wells and, if necessary, into long-existing oil wells of the oil reservoir.

According to one embodiment, when implementing the action plan, new oil production wells are constructed with one or more underground production control devices selected from the group consisting of: bottom-hole valves, bottom-hole feed devices, impellers, choke devices, borehole submersible pumps, separating devices for compaction or isolating sections of the oil reservoir and perforations in the downhole pipe to increase the contact area of the reservoir.

According to one embodiment, at least one of the operating production oil wells is constructed as a well with maximum contact with a reservoir having a plurality of lateral and at least partially horizontal shafts (see FIG. 11). New operating oil production wells can also be built including perforations in downhole pipes, with the number and direction of perforations made according to the action plan.

According to one embodiment, the implementation of the action plan further comprises changing the internal structure of one or more long-standing oil wells to increase the area of contact with the reservoir and, at the same time, increase the productivity of the wells.

The implementation of the action plan may also include the placement of injection wells and the determination of the volume of auxiliary fluids injected through the injection wells according to the action plan. The implementation of the action plan may further include the design and / or installation of equipment for separating auxiliary fluids from oil recovered from the reservoir and processing auxiliary fluids.

Implementation of the action plan may further include processing to enhance the inflow of one or more existing oil wells to increase productivity, for example, using at least one of the following: high pressure fracturing, acid fracturing, or acid flushing. In addition, or alternatively, the implementation of the action plan may include shutting down one or more long-standing oil wells for such a change in oil flow through the reservoir, in which more oil is drained from the reservoir than when these oil wells are not closed.

D. Tracking and performance

Another aspect of asymmetric reservoir conformity assessment (RCAA ™) is to monitor and track the performance of an oil reservoir, for example, after developing or improving an asymmetric reservoir conformity assessment. Once again, proper monitoring and tracking of reservoir performance can depend a lot on the proper collection, analysis, and weighting of collector related data. In general, leading indicators can better help predict future side effects and provide resolution or elimination of such effects than lagging indicators.

According to one embodiment, a computer-implemented method for monitoring and tracking reservoir performance relative to at least one of the following: production or recovery, comprising: 1) making or receiving measurements related to performance of oil wells in an oil reservoir and inputting measurements to a computer a system having a processor and system storage device; moreover, 2) the computer system relates measurements to performance indicators, at least some of which are leading indicators of performance indicators of an oil well; moreover, 3) a computer system compares at least some of the measurements and / or performance indicators related to the performance of an oil well with predetermined emergency levels or start-up circuits; and 4) when a measurement or indicator switches over the emergency level or the start-up circuit settings with a drop below the minimum or exceeding the maximum, the computer system performs at least one of the following: I) changes at least one parameter of the oil well’s production or II) notifies the director, owner and / or a third party about the transition of the emergency level or the setting of the starting circuit. The computer system may also display information related to at least one measurement and / or performance of an oil well, for example graphically and / or on analog indicators (for an example, see FIGS. 3A-3D).

According to one embodiment, the transition of the emergency level or setpoint of the start-up circuit may result in or require at least one of the following: increase or decrease in oil production by one or more oil wells of the reservoir. Alternatively or in addition, a transition of the emergency level or the start-up set point may result in or require at least one of the following: increase or decrease oil production by commissioning one or more new oil wells on the reservoir or stopping the operation of one or more oil wells wells.

According to one embodiment, the transition of the emergency level or the setpoint of the starting circuit may result in or require at least one of the following: increase or decrease the volume of injection of auxiliary fluid into the manifold. Alternatively or in addition, the transition of the emergency level or the start-up setpoint may require processing to stimulate the inflow of at least one oil well in order to increase well productivity.

IV. EXAMPLES

The following examples illustrate how an asymmetric reservoir compliance methodology (RCAA ™) methodology is used in the field to increase the productivity and / or return of an existing reservoir. None of the collectors described in the examples is located in the United States, and none of the measures to improve productivity and / or returns have been conducted in the United States. In addition, neither the RCAA ™ methodology nor the associated case studies are open.

Example 1

general information

The field in this example is operated with peripheral flooding. It has reached a state of exhaustion in which more than 70% of the reserves have already been mined. Modernization has begun to reduce the rate of drop in reservoir pressure and watering production at the field. An auxiliary task was to reduce the requirements for ESPs and related investment programs.

Geology

The field is mined from a carbonate reservoir 60+ meters thick, which consists of several shallowing cycles in the upward direction. The reservoir has an average porosity of more than 15% and a permeability of up to several Darcy. The upper half of the collector has a generally very high collector quality; the lower half contains numerous intercalations of high and low reservoir quality. The quality of the lower half of the reservoir is improved by the addition of permeability from cracks, which significantly increase the hydraulic conductivity of the rocks, as well as increase the risk of premature water breakthrough. The collector has more than 300 meters of structural closure and a weak initial head of circulating water, which is replaced by peripheral flooding.

Impact of asymmetric manifold conformity assessment (RCAA ™)

An analysis of the fracture and the knowledge system in the form of ranking wells was used to clarify the decrease in efficiency in previous development projects to provide directions for eliminating deficiencies. This collector underwent peripheral flooding with the task of the maximum possible circulation of water to maximize the total return. Having this task, the operator created production wells of the front row on the lower wing of the structure with high flow rates and water cut. As a result of this plan, production wells directed at the uprising of the reservoir suffered from low pressure, which led to a high depletion of the well stock and reduced the upstream potential of the oil potential. In fact, the operator tried to impose a viscosity-dominated selection model on a gravity-dominated system model. Solutions to this problem included the use of a unified water management plan for individual production wells, coupled using horizontal geometric patterns for new wells and overhauls.

In 1999, they predicted a decrease in the average well production rate of 10% per year and water cut in production, which should double over the next 7 years. With the deployment of an improved development project, average well production and water cut have stabilized instead over time. In addition, the oil potential increased to 128,000 Bbls / day (barrels / day 20352 m ³ / d), 69 depleted wells were restored and 60 ESPs were removed.

Example 2

general information

At the field of this example, they started production in 2006 with a working flow rate of 300,000 Bbls / day (barrels / day 47,700 m ³ / d) and the third increment of the development plan for the field with three increment stages took place. Peripheral flooding was carried out. Modernization began with the development of a new production increment due to concerns about premature water breakthrough, excessive development costs and the high rate of formation pressure drop in wells, all due to complex geology. This concern was based on experience gained during development and on performance after two previous increments.

Geology

The field is mined from a carbonate reservoir 60+ meters thick, which consists of several shallowing cycles in the upward direction. The reservoir has an average porosity of more than 15% and a permeability of up to 100 millidarsi. The upper half of the reservoir is generally of medium reservoir quality; the lower half contains numerous intercalations of medium and low reservoir quality. The quality of the lower half of the reservoir is improved by the addition of crack permeability, which greatly helps the extraction process. The collector has more than 250 meters of structural closure and a weak initial head of circulating water, which is replaced by peripheral flooding.

Impact of asymmetric manifold conformity assessment (RCAA ™)

Prior to the development of the third increment, the first increment was developed using vertical wells and the second increment using short horizontal ones. Horizontal wells improved compared to vertical ones, but both configurations suffered from relatively low productivity indices (PI), resulting in depletion of wells with lower water cuts. Usually, this required an increase in drilling volume and the number of ESPs to maintain the rate of production. To implement the lessons learned in the first and second increments and taking into account best practices, meetings of various departments were held and research was carried out. The meetings provided new physical models of the reservoir, which in turn gave recommendations on advanced technologies and methodologies for the effective use of these models. As a result, this activity led to the development and use of a high-tech well architecture, monitoring and management at the bottom, and innovative fields.

The field began to be successfully exploited 5 months ahead of schedule with reaching target targets (300,000 Bbls / day (barrels / day 47,700 m ³ / d). The reservoir performance today is exceptionally good in terms of well productivity, actual water cut and average pressure The key factors for ensuring success in this project were: 1) constructive solutions for downhole architecture and completion based on new technologies; 2) monitoring at a modern technical level in real time of the field (innovative field); and 3) overall field development and design of peripheral waterflooding.

Example 3

general information

At the field of this example, they started production in 1998 with a working flow rate of 500,000 Bbls / day (barrels / day 79500 m ³ / d). The field was developed exclusively by drilling horizontal wells 1 km long. The plans envisaged an increase in production to 750,000 Bbls / day (barrels / day 119250 m ³ / d) by 2010. Upgrades were launched to reduce the rate of decline in well productivity, gas factor (GF), and associated capital development and operating costs.

Geology

The field is characterized by a hollow folded with a north-east / south-west stretching with an anticline, consisting mainly of Cretaceous sandstone, schists, and carbonates. The collector consists of growth of rudists, transversely changing in the barrier and facies of offshore slopes. Although the porosity of the skeleton is generally high (on average, 25%) and does not change laterally, permeability is facies dependent and exhibits spatial variability. In the south, where low energy lagoon deposits dominate, permeability ranges from 5 to 10 millidarsi. 3D seismic data indicate that the reservoir contains a series of faults. These faults and cracks are identified by logging in an open hole and are the most prevalent in the northern part of the reservoir and can increase reservoir quality where they occur. Since the mechanism of depletion of the collector is mainly the expansion of the gas cap, this also increases the risk of a gas cone.

Impact of asymmetric manifold conformity assessment (RCAA ™)

The field was initially developed using 120 horizontal wells producing 500,000 Bbls / day (barrels / day, 79500 m ³ / d). The rate of depletion of the field exceeded the forecast. An in-depth study showed that a large number of wells need to be drilled to maintain the pace at the right level. Fracture analysis revealed that wells needed a higher productivity index (PI). Knowledge systems in the form of ranking wells showed that wells located in some areas of the field produced production below forecast. These zones were identified as having permeability.

Diagnostic plots of PI versus well length revealed a correlation indicating that longer wells produced more oil. A number of reservoir studies and drilling have been carried out, which has revealed the possibility of drilling significantly longer and more complex wells. This led to the concept of maximum contact reservoir (MRB) wells. MRC wells are characterized by numerous branches, with several pipes running in different directions through different horizontal and vertical zones of the reservoir. This design helps to drain more oil from the reservoir, both short-term and long-term, accelerating both production and return. A higher PI in MRC wells solves several problems: 1) move away from low flow rates in dense facies; 2) the formation of a gas cone is prevented or slowed down; and 3) the number of wells that are otherwise required to increase production and oil recovery to the required level is reduced. As a result, the first MRC wells were drilled. These wells successfully reduced the decline in production, halted the formation of a gas cone, and increased the average well production by six times.

Field performance was dramatically improved and project capital expenditures were reduced. The above resulted in plans to increase the rate of production. The key factors in a successful modernization program were: 1) constructive solutions for downhole architecture and completion based on new technologies; and 2) integrated reservoir monitoring programs.

Example 4

general information

The reservoir in this example has been in operation for over 50 years and has an advanced state of depletion, more than 85% of the reserves have already been mined. The primary displacement for production is provided by peripheral flooding. It was decided to modernize to reduce the decline in well productivity and rapidly increasing production watering. An auxiliary task was to reduce the requirements for ESPs and related capital costs.

Geology

The field is mined from a carbonate reservoir 60+ meters thick, which consists of several shallowing cycles in the upward direction. The reservoir has an average porosity of more than 15% and a permeability of up to several Darcy. The upper half of the collector has, in general, a very high collector quality; the lower half contains numerous intercalations of high and low reservoir quality. The remaining reserves in the field are mainly in the thin oil column under the secondary gas cap and in the low-permeability facies in the uppermost layer located in the northern half of the field. The collector has more than 300 meters of structural closure and a weak initial pressure of the circulating water, which was replaced by peripheral flooding.

Impact of asymmetric manifold conformity assessment (RCAA ™)

The operator found that extracting the remaining oil contained in a thin oil column requires several hundred vertical wells with completion in the low-permeability upper section of the reservoir and equipped with ESPs. However, gap analysis found that the current reservoir design does not support actual performance. The analysis revealed that cone formation and low PI wells are an obstacle to extracting the remaining oil from an outdated development project. As an integral part of the method, various graphs of well diagnostics were created during the simulation, which indicated the advantages of increasing contact with the reservoir. As a result of a series of meetings, the exchange of ideas gave a new understanding to the collector. This improved understanding of reservoir mechanics led to the placement of MRC wells in the uppermost zone of the structure, resulting in stabilization of the rate of oil production and water flooding at the field. The resulting diagnostic schedule for comparing unit costs briefly revealed the main advantage of the strategy, which provides a 15-fold reduction in development costs with MRC wells in comparison with vertical completion.

Production at the field has dramatically improved in terms of declining well production, rate of pressure drop, productivity of new wells and overall water cut. Significant savings were obtained from the exclusion of the ESP installation. The main factors in achieving successful results were: 1) the development of new and highly effective structural solutions for downhole architecture and completion; 2) modernization of overhaul programs; and 3) modification of the purpose of production / injection for peripheral flooding.

Example 5

general information

This collector has been in operation for over 30 years. A dual displacement mechanism is used; covering the top of the gas cap and supporting the bottom of the active aquifer system. The collector is in a state of significant depletion. It was decided to upgrade to improve the productivity of wells in an environment with increasing development problems, which include high drilling costs, a shrinking oil production window, reservoir heterogeneity and restrictions on water and gas processing facilities.

Geology

Production at the field is carried out in a sandstone reservoir 100 m thick, located in an environment formed by the sea and river. The reservoir consists of the lower interval of the main sandstone and the upper interval of the sandstone bed. The reservoir has an average porosity of more than 20% and a permeability of up to several Darcy. The lower half of the collector is of very high quality; the upper half contains winding channels of high quality, but of limited length. Most of the reserves recovered today are obtained from the main sandstone by simple selection; most of the remaining reserves are located in a difficult to determine the location of the upper layer of sandstone.

Impact of asymmetric manifold conformity assessment (RCAA ™)

The oil column has decreased in the best areas of the reservoir due to long-term production. Development in poorer reservoir areas is required. The gap analysis revealed that the previous development schemes cannot be used, since the lower quality reservoir was disjunctive and had a PI below the average. The gap analysis, in addition, revealed that the location of the sandstone interlayer was more difficult than predicted. The ranking of the wells revealed that the wells drilled into the upper interlayer of sandstone were flooded and became unproductive faster than predicted. By identifying the location of the wells with the worst performance, a correlation was made between the deviation of the wells and performance.

During the study of the reservoir and geology, it was found that processing 3-D seismic data to analyze the dependence of the reflection amplitude on the angle of incidence (AVA) can ensure that geophysicists detect a layer of sandstone that previously could not be detected by resolving seismic data. Application of the AVA analysis showed the location of the sandstone interlayer and ensured proper well placement with proper deviation from fluid contact. The analysis also led to the appropriate application of modern completion techniques for this stage of the field’s life cycle.

Productivity has improved significantly in both new wells and well-repaired wells. The main factors for successful results were: 1) an improved understanding of sandstone continuity obtained using high-tech seismic data processing (AVA); 2) the use of modern methods of completion; 3) the use of geosteering; and 4) new design solutions for well architecture.

Claims (26)

1. A method for assessing compliance with the technical requirements of an oil reservoir regarding production and oil recovery for the development of an action plan to increase production and / or oil recovery from an oil reservoir, comprising:
the establishment of many reservoir performance indicators that relate to oil production and return from the reservoir, and performance indicators include one or more leading indicators and one or more retarded indicators;
multiplying by the weight coefficient of one or more indicators of the collector's work with establishing a higher weight than at least one other collector's working indicator, including multiplying by the weighting factor of at least one of the leading indicators with establishing a higher weight than at least at least one of the lagging indicators for asymmetric analysis of the performance of the collector;
obtaining data related to performance indicators for the oil reservoir, the data being generated using at least one of the following: (I) measuring the physical properties of one or more existing production oil wells and / or injection wells, (II) selecting and analyzing one or several core samples from a reservoir, or (III) establishing a relationship between data of one or more different types according to (I) or (II);
formation of performance indicators for the oil reservoir according to the data;
and determining a compliance rating for an oil reservoir based on an asymmetric analysis of reservoir performance, the compliance rating for at least one of the following: reservoir or oil recovery. 2. The method according to claim 1, in which the measurement of the physical properties of one or more operating production oil wells and / or injection wells of the reservoir includes at least one of the following: 1) sampling of fluid, oil, water and gas in the well , 2) pressure measurement using a reusable reservoir tester or other devices, or 3) determining fluid saturation from well logs. 3. The method according to claim 1, in which
one or more leading indicators is selected from the group consisting of the index of depleted wells, the gradient of depleted wells, the gas factor, the gradient of the gas factor, changes in reservoir pressure, the rate of decline in oil production, the gradient in the rate of decline in oil production, waterflood coefficient, gradient of waterflood coefficient, water cut , water cut gradient, production decline indicator and production profitability index,
one or several lagging indicators are selected from the group consisting of the following: average production rates for production wells fluid, oil production rate, water withdrawal rate, depletion rate, depletion rate of forecast total return, depletion rate of confirmed reserves 1Р, depletion state, forecast state of depletion total return, depletion state of mobile initial oil reserves in the reservoir, dimensionless depression on the reservoir, dimensionless productivity index, dimensionless injectivity index, gas rate, flow rate by liquid, maximum effective rate of selection, oil rate, water rate, pressure gradient, gradient of productivity index, rate limit, dimensionless rate limit, oil recovery factor, oil recovery coefficient, mobile oil recovery coefficient, theoretical maximum oil recovery coefficient, transfer index abilities, coefficient of compensation of selection, coefficient of compensation of selection on a surface and coefficient of compensation of selection of a collector. 4. The method according to claim 1, where the rating of compliance with technical requirements for the oil reservoir is additionally determined based on the development management rating for the oil reservoir, and the reservoir development management rating is determined using asymmetric weight processing of performance data related to the following categories: development management scheme collector, increasing the value of reserves, development and operation plan, survey of the collector, application of technology and knowledge management. 5. The method according to claim 4, in which
performance indicators related to the reservoir development management scheme include oil recovery scheme, field depletion rate, well flow rate / depression on the formation, risk of displacement method and feasibility of the production shelf,
performance measures related to increasing the value of reserves include OIIP (initial reservoir oil reserves) / GIIP (initial reservoir gas reserves) confirmation, waterflood coverage, displacement efficiency, stock confirmation and risk reduction,
performance indicators related to the development and operation plan include the implementation of the production plan, field productivity, pressure management, gas management, water management and depression control,
performance indicators related to the reservoir survey include the development of a comprehensive plan and the implementation of a comprehensive plan,
performance indicators related to the application of the technology include drilling technology, completion technology, modeling technology, and optimization technology for dynamic interpretation of the reservoir, and
performance indicators related to knowledge management include a knowledge management index. 6. The method according to claim 1, further comprising performing a gap analysis by comparing the difference between a manufacturer’s target or an ideal indicator and current production and / or oil recovery. 7. The method according to any one of claims 1 to 6, in which the rating of compliance with technical requirements is determined, at least in part, by analyzing at least one of the collector performance indicators or data related to the collector performance indicators using a computer system having a processor and system memory and displaying information related to the rating of compliance with technical requirements, and the displayed information contains at least one of the following: a detailed sheet or schedule, etc. dstavlyayuschy performance indicators or developed on their basis. 8. The method according to claim 7, in which
single development indicators include one or more of the following: cost factor, drilling cost coefficient, overhaul cost coefficient, efficiency coefficient, drilling efficiency coefficient, overhaul efficiency coefficient, average contact value of a production well collector or average contact value of an injection well collector;
workload indicators include one or more of the following: training, number of documents, number of training days, number of courses within the company, number of courses taught by third parties, research, ongoing research for less than twelve months, ongoing research for more than twelve months, modeling or ongoing laboratory or field trials of new methods or technologies;
business plan indicators include one or more of the following: a forecast of the rate of production by fluid, a forecast of the rate of oil production for the business planning cycle, a forecast of the rate of production of water for the business planning cycle, or a forecast of water cut for the business planning cycle; and
over-planned goals include one or more of the following: statistical performance indicators, a business plan forecast that takes into account the speed of implementation of new technologies and best practices, production development costs, selection compensation coefficient, surface selection compensation coefficient or water cut. 9. A method of developing an action plan to increase production and oil recovery from an oil reservoir, comprising:
performing asymmetric analysis of the oil reservoir to determine compliance with the technical requirements of the reservoir, moreover, the asymmetric analysis is performed by multiplying one or more reservoir performance indicators by a weight factor, making its weight greater than at least one of the other reservoir performance indicators;
establishing at least one of the following: the required rate of depletion or the necessary rate of production and total oil recovery for the oil reservoir;
constructing a model of an oil reservoir that defines the location of oil in the reservoir, including at least one of the following: connectivity or lack of connectivity of oil in the reservoir, potential paths of oil flows as a result of oil extraction from the reservoir at natural flow rates and / or pressure of the fluid in the reservoir and / or pumping auxiliary fluids into the manifold; and
development of an action plan, which includes the production architecture, relating to: 1) existing production oil wells, that is, their number, location, design and production data, 2) auxiliary fluid injection volumes to facilitate the displacement of oil in the reservoir into existing production wells, i.e. data on the use of one or more injection wells and the volume of auxiliary fluids injected through one or more injection wells, and if sary, 3) treatment for the stimulation of one or more existing wells acting to increase productivity. 10. The method according to claim 9, in which the asymmetric analysis of the oil reservoir to determine compliance with the technical requirements of the reservoir includes determining a development management rating for the oil reservoir, and the reservoir development management rating is determined using asymmetric weight processing of performance data related to the following categories: reservoir management scheme, increasing the cost of reserves, development and operation plan, reservoir survey, application technology and knowledge management. 11. The method according to claim 9, where at least one of the following: performing an asymmetric analysis, establishing the required production rate and total return, building an oil reservoir model or developing an action plan is performed using a computer system having a processor and a system storage device and displaying information related to the oil reservoir, and wherein generating the model of the oil reservoir is performed at least partially by a computer system, the model of the oil reservoir contains at least one of the following: a numerical model or a visual display of part or all of the oil reservoir. 12. The method according to claim 9, where the auxiliary fluids contain water and / or gas, and the method further comprises developing an architecture related to auxiliary fluids, including the separation of auxiliary fluids from oil extracted from the reservoir, and the processing of auxiliary fluids media, and the architecture related to auxiliary fluids includes at least one of the following: disposal, re-injection or sale of auxiliary fluids. 13. The method according to claim 9, in which when establishing the required production rate and total return for the oil reservoir, take into account the amount of funds that the manufacturer intends to invest in increasing production and oil recovery from the reservoir, and at the same time develop an action plan that includes the production architecture, relating to existing production oil wells, includes the development and placement of at least one maximum contact well with a reservoir having a plurality of sidetracks and at least partially but horizontal trunks. 14. A method for implementing an action plan to increase production and oil recovery from an oil reservoir, comprising:
obtaining an action plan developed using asymmetric analysis of the oil reservoir to determine compliance with the technical requirements of the reservoir, moreover, the asymmetric analysis is performed by multiplying one or more reservoir performance indicators by a weight factor, creating a weight greater than at least one of the other reservoir performance indicators, which includes multiplying by the weight coefficient of at least one leading indicator with the creation of a higher weight than at least one of a lagging indicator, and the action plan includes a production architecture relating to at least one of the following: 1) new operating oil production wells, their number, location, design, 2) injection of auxiliary fluids to facilitate oil displacement in the reservoir operating production wells, i.e. the placement of one or more injection wells and the volume of auxiliary fluids injected through one or more injection wells n, 3) construction of maximum contact hole, and 4) a treatment for the stimulation of one or more existing wells acting to increase productivity and 5) modifying one or more existing wells acting to reduce the flow rate;
one or more of the following:
the placement of new existing production oil wells at the sites of the oil reservoir and the construction of new existing production oil wells in accordance with the action plan;
placement of injection wells at the oil reservoir sites in accordance with the action plan to facilitate the displacement of oil in the reservoir into new existing production oil wells and, if necessary, into long-existing oil wells of the oil reservoir;
commencement of operation of the maximum contact well on an oil reservoir having a main well from which oil is removed and several lateral shafts extending transversely from the main well, with at least some of the lateral well being connected to the main well at various points along the length main wellbore;
processing to intensify the influx of one or more of the first active production wells in the oil reservoir to increase the productivity of the first operational production wells; or
the modification of one or more second operational production wells in the oil reservoir to reduce the flow rate of the second operational production wells. 15. The method according to 14, in which the asymmetric analysis of the oil reservoir to determine compliance with the technical requirements of the reservoir includes determining the development management rating for the oil reservoir, and the reservoir development management rating is determined using asymmetric weight processing of performance data related to the following categories: reservoir management scheme, increasing the cost of reserves, development and operation plan, reservoir survey, application e technology and knowledge management. 16. The method according to claim 4, in which the asymmetric analysis and the development of an action plan are carried out, at least in part, using a computer system having a processor and a system storage device and displaying information related to the oil reservoir. 17. The method according to 14, where the new existing production oil wells are built with one or more underground production control devices selected from the group consisting of: bottom-hole valves, bottom-hole feed devices, impellers, choke devices, borehole submersible pumps, separation devices for sealing or isolating a portion of the oil reservoir and perforation in the downhole pipe to increase the contact area of the reservoir, at least one of the new operational production kvazhin constructed as a borehole maximum contact with the manifold having a plurality of lateral boreholes and the at least partially horizontal wellbores, and, where the new current operating oil wells construct includes perforations well pipes, with the number and direction of the perforations is performed according to the action plan. 18. The method according to 14, further comprising at least one of the following:
changing the internal design of existing oil wells to increase the area of contact with the reservoir and at the same time increase the productivity of the wells;
design and / or installation of equipment for separating auxiliary fluids from oil recovered from the reservoir and processing auxiliary fluids;
processing to intensify the flow of one or more existing oil wells to increase productivity using at least one of the following: high pressure fracturing, acid fracturing, or acid flushing;
closing one or more long-standing oil wells to change the flow of oil through the reservoir in a way that ultimately gives drainage of oil from the reservoir more drainage than when long-existing oil wells are not shut. 19. A computer-implemented method for monitoring and tracking the performance of an oil reservoir relative to at least one of the following: production or recovery, comprising:
making or receiving measurements related to the performance of oil wells in an oil reservoir and inputting measurements into a computer system having a processor and system memory;
moreover, the computer system relates measurements to performance indicators, at least some of which are leading indicators and lagging indicators of the performance of an oil well in an oil reservoir, and the computer system multiplies at least one of the leading indicators by a weight factor, giving it a higher weight than at least one lagging indicator;
a computer system compares at least some of the measurements and / or performance related to the performance of an oil well in an oil reservoir with predetermined emergency levels or levels of start-up circuits; and
when a measurement or indicator passes beyond the emergency level or the start-up circuit setting with a fall below a minimum or an excess of a maximum, the computer system performs at least one of the following: 1) changes at least one parameter of the oil well production at the oil reservoir or 2) warns the control manifold , the owner and / or third party, that the emergency level or the start-up setting of the start-up circuit for the oil reservoir has been crossed. 20. The method according to claim 19, where the computer system further displays information related to at least one measurement and / or performance indicator related to the performance of an oil well. 21. The method according to claim 20, where the computer system displays information in the form of a graph and / or scale of the device. 22. The method according to claim 19, in which the transition of the emergency level or the settings of the starting circuit results in at least one of the following:
increased oil production by one or more reservoir oil wells;
reduction in oil production by one or more reservoir oil wells;
increase oil production by putting into operation one or more new oil wells in the reservoir or stopping the operation of one or more oil wells;
reducing oil production by commissioning one or more new oil wells in the reservoir or stopping the operation of one or more oil wells;
increased injection of auxiliary fluid into the reservoir;
reducing the injection of auxiliary fluid into the reservoir; or
processing to stimulate the inflow of at least one oil well to increase well productivity. 23. A machine-readable medium having executable instructions stored thereon, which, when executed by a computer system having a processor and system storage device, enables the computer system to execute the method according to one of claims 19-22. 24. A method for assessing compliance with the technical requirements of an oil reservoir regarding production and oil recovery to develop an action plan to increase production and / or oil recovery, comprising:
the establishment of many reservoir performance indicators that relate to oil production and return from the reservoir;
multiplying by the weight coefficient of one or more indicators of the collector’s performance with the establishment of a higher weight than at least one other collector’s performance indicator for asymmetric analysis of the collector’s performance indicators;
obtaining data related to the performance of the reservoir, and the data is generated using at least one of the following: (I) measuring the physical properties of one or more existing production oil wells and / or injection wells, (II) selecting and analyzing one or more core samples from the reservoir or (III) establishing the relationship between the data of one or more different types at positions (I) or (II);
collector performance indicators based on data; and
determining a compliance rating for an oil reservoir related to at least one of the following: reservoir production or oil recovery, wherein the compliance rating is based at least in part on a development management rating for the oil reservoir,
the reservoir development management rating is determined by using asymmetric weight processing of performance data related to the following categories: reservoir development management scheme, increasing the cost of reserves, development and operation plan, reservoir survey, technology application and knowledge management,
moreover, performance indicators related to the reservoir development management scheme include oil recovery scheme, field depletion rate, well flow rate / depression on the formation, risk of displacement method and feasibility of the production shelf,
performance indicators related to increasing the value of reserves include OIIP (initial reservoir oil) / GIIP (initial reservoir gas) confirmation, waterflood coverage, displacement efficiency, stock confirmation, and risk reduction,
performance indicators related to the development and operation plan include the implementation of the production plan, field productivity, pressure management, gas management, water management and depression control,
performance indicators related to the reservoir survey include the development of a comprehensive plan and the implementation of a comprehensive plan,
performance indicators related to the application of the technology include drilling technology, completion technology, modeling technology and optimization technology for dynamic interpretation of the reservoir, and
performance indicators related to knowledge management include a knowledge management index. 25. A method for assessing compliance with the technical requirements of an oil reservoir regarding production and oil recovery to develop an action plan to increase production and / or oil recovery, comprising:
the establishment of many reservoir performance indicators that relate to oil production and return from the reservoir;
multiplying by the weight coefficient of one or more indicators of the collector’s performance with the establishment of a higher weight than at least one other collector’s performance indicator for asymmetric analysis of the collector’s performance indicators;
obtaining data related to the performance of the reservoir, and the data is generated using at least one of the following: (I) measuring the physical properties of one or more existing production oil wells and / or injection wells, (II) selecting and analyzing one or more core samples from the reservoir, or (III) establishing the relationship between the data of one or more different types at positions (I) or (II);
collector performance indicators based on data; and
determining a compliance rating for an oil reservoir related to at least one of the following: oil production or return to an oil reservoir, the compliance rating based at least in part on a development management rating for the oil reservoir,
moreover, the reservoir development management rating is determined using asymmetric weight processing of performance data related to the following categories: reservoir development management scheme, increasing the cost of reserves, development and operation plan, reservoir survey, technology application and knowledge management, while indicators of the development management scheme collectors and increase the value of reserves are multiplied by weighting factors, making their weight higher than the weight of indicators of the development plan and ex luatatsii, application of technology, reservoir surveys and knowledge management. 26. The method according A.25, in which the indicator of the development and operation plan is multiplied by a weight coefficient, making its weight higher than the weight of the technology application indicator, which is multiplied by a weight coefficient, making its weight higher than the weight of the reservoir survey indicator, which is multiplied by the weight making it weight higher than the weight of the knowledge management indicator.

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