WO2012134497A1 - Procédé pour estimer de façon dynamique une compétence de réservoir de pétrole et augmenter une production et une récupération par analyse asymétrique de mesures de performances - Google Patents

Procédé pour estimer de façon dynamique une compétence de réservoir de pétrole et augmenter une production et une récupération par analyse asymétrique de mesures de performances Download PDF

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Publication number
WO2012134497A1
WO2012134497A1 PCT/US2011/030940 US2011030940W WO2012134497A1 WO 2012134497 A1 WO2012134497 A1 WO 2012134497A1 US 2011030940 W US2011030940 W US 2011030940W WO 2012134497 A1 WO2012134497 A1 WO 2012134497A1
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reservoir
petroleum
plan
oil
recovery
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PCT/US2011/030940
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English (en)
Inventor
Nansen G. Saleri
Robert M. Toronyi
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QRI Group, LLC
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Priority to RU2013148583/08A priority Critical patent/RU2571542C2/ru
Priority to CN201180002391.5A priority patent/CN102812203B/zh
Priority to PCT/US2011/030940 priority patent/WO2012134497A1/fr
Publication of WO2012134497A1 publication Critical patent/WO2012134497A1/fr

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells

Definitions

  • the invention is in the field of petroleum recovery, more particularly in the field of petroleum reservoir design, management and response.
  • Petroleum is a critical fuel source and is the life blood of modern society. There is tremendous economic opportunity in finding and extracting petroleum. Due to a variety of technical and geological obstacles, it is typically impossible to recover all of the petroleum contained in a reservoir.
  • While the technology may, in fact, exist to increase current production and/or increase total long-term recovery for a petroleum reservoir, an impediment to implementing an intelligent long-term plan for maximizing current output, extending the life of a given reservoir, and increasing total recovery is the inability to accurately assess the health and deficiencies of the reservoir. For example, some or all of the producing wells of a reservoir may show diminishing output, which might lead some to believe the reservoir is drying up. However, the reservoir may, in fact, contain much larger quantities of recoverable petroleum but be under-producing simply due to poor placement and/or management of the existing wells and the failure to know whether and where to place new wells. The inability to properly diagnose inefficiencies and failures and implement an intelligent recovery plan can result in diminished short-term productivity and long-term recovery.
  • the main impediment to maximizing production and recovery from a reservoir is the inability to gather, intelligently analyze and correctly understand the relevant data. Diagnosing the health of a petroleum reservoir is not straightforward and is much like trying to decipher the health of a human body, but at a location far beneath the earth or ocean. Moreover, the available data may take years to accumulate and assess, yet may be dynamically changing, making it difficult, if not impossible, to formulate and implement an economically and/or technically feasible plan of action. The result is continuing low short-term productivity and low long-term recovery from the petroleum reservoir. BRIEF SUMMARY OF THE INVENTION
  • the present invention seeks to overcome existing technical, economic and institutional impediments that reduce production and recovery from a petroleum reservoir by more accurately assessing the actual condition of an existing reservoir and implementing an intelligent plan of action in order to increase short-term production rates and long-term recovery of petroleum from the reservoir. It does so by gathering information using a unique set of metrics and information gathering techniques and analyzing the gathered information in a targeted fashion by properly weighting the data in the context of the particular reservoir in question and the goals of the producer.
  • the method integrates a wide variety of information using specific metrics. Some are known while others are unique to the inventive process.
  • the metrics include both leading and lagging indicators of petroleum reservoir productivity. While producers typically focus on lagging indicators, such as declining production and/or increasing water-cut, the present invention makes substantial use of leading indicators that are more predictive of future prouction declines or other problems before they occur. That permits the formulation and implementation of a plan of action before the reservoir health declines too far.
  • An analogy is preventative versus curative health care. The latter attempts to find a remedy for a sick patient while the former seeks to prevent the patient from getting sick.
  • Lagging indicators may, however, be a good tool to ensure accountability. Relevant information regarding reservoir condition is gathered in a far more broad-based and comprehensive manner compared to conventional techniques.
  • the invention implements an intensely focused and demanding information gathering process in order to obtain and comprehensively analyze all available information that may be relevant to the reservoir condition. All known sources of relevant information may be tapped during an intensive information gathering period.
  • the invention analyzes the gathered information and accurately assesses the condition of a given reservoir by appropriately weighting the various data points.
  • the process of weighting different data points with greater or lesser emphasis is referred to "asymmetric assessment".
  • metrics typically the leading indicators, which are more useful than others (e.g., lagging indicators) in realistically assessing the present and future condition of a petroleum reservoir.
  • the manner in which certain metrics are weighted may depend on the particular reservoir in question and/or the specific performance goals of the producer.
  • a plan of action is formulated based on the properly gathered, analyzed and weighted data for a particular reservoir.
  • the plan of action may require modest or substantial changes in how extraction of petroleum is carried out for that reservoir.
  • the plan of action is based on an accurate assessment of the short- , mid- and long-term condition of the reservoir and is tailored to the specific conditions of the reservoir and/or needs of the producer, the plan of action is far more likely to succeed and result in increased short-, mid- and/or long-term production and profits compared to what is possible using conventional methods.
  • a plan of action is implemented in order to increase short-term production and/or long-term recovery (e.g., proven reserves).
  • the plan of action may include one or more of the following: (1) modifying and/or stimulating one or more existing wells, (2) constructing new wells, (3) injection of pressurized fluids and/or gas in a more intelligent and strategic manner, and (4) shutting or slowing down production by one or more existing wells.
  • the petroleum reservoir may be monitored to ensure compliance with design and production goals, e.g., as set by RCAATM.
  • Alarms or trigger points may be provided which, when exceeded such as by falling below a specified minimum or exceeding a specified maximum, call for a response.
  • the response may be a notification to a manager or other interested party, or it may be an automatic adjustment to some production parameter.
  • inventive reservoir competency asymmetric assessment methods of the invention have the ability to increase short-, mid- and long-term productivity and recovery by about 5-40%. In some cases, the inventive methods will permit economically and technically viable extraction of a majority of a reservoir's known capacity, up to about 80-85% in some cases. This is a surprising and unexpected result given the tremendous untapped economic potential that currently exists but has been unable to spur production of even a majority of known reservoir capacity given all that is currently known about petroleum reservoir maintenance and extraction.
  • Figures 1A and IB are two halves of a chart which illustrates an exemplary master plan for implementing one method for dynamically assessing petroleum reservoir competency and increasing production and recovery through asymmetric analysis of performance metrics;
  • Figure 2 is an exemplary graph that illustrates the difference between production and recovery of a reservoir before and after implementation of the inventive methods;
  • Figures 3A-3D illustrate exemplary dashboards within a computer generated and displayed control room that monitors and analyzes data from producing wells of a petroleum reservoir;
  • Figure 4 schematically illustrates exemplar ⁇ ' computer architecture that can be used to gather, analyze and/or display data gather from and about a petroleum reservoir;
  • Figures 5A-5F are graphs which illustrate various leading indicators used to assess and/or enhance reservoir competence
  • Figures 6A-6I are graphs which illustrate various lagging indicators used to assess and/or enhance reservoir competence
  • Figures 7A-7C are graphics which illustrate various unit development metrics used to assess and/or enhance reservoir competency
  • Figures 8A-8C are graphs which illustrate various workload metrics used to assess and/or enhance reservoir competency
  • Figures 9A-9B are graphics which graphically illustrate various business plan metrics used to assess and/or enhance reservoir competency
  • Figures 1 OA- IOC are graphs which graphically illustrate various stretch goals used to assess and/or enhance reservoir competency
  • Figure 11 illustrates an exemplary maximum reservoir contact (MRC) well used to increase productivity of a single producing oil well.
  • MRC maximum reservoir contact
  • the present invention is directed toward a comprehensive method for enhancing ongoing production and ultimate recovery of petroleum from a reservoir.
  • This method may be referred to as Reservoir Competency Asymmetric AssessmentTM (or RCAATM).
  • RCAATM includes several closely interrelated sub-methods or modules that are employed in concert and sequentially. They are (i) analyzing and diagnosing the specific and unique features of a reservoir (i.e., its "DNA") using targeted metrics, (ii) designing a plan of action for maximizing current production and ultimate recovery from the reservoir, (iii) implementing the plan of action so as to increase current production and ultimate recovery, and (iv) monitoring or tracking the performance of the petroleum reservoir using targeted metrics and making adjustments to production parameters, as necessary, to maintain desired productivity and recovery.
  • Each of the sub-methods relies on intense knowledge gathering techniques, which include taking direct measurements of the physics, geology, and other unique conditions and aspects of the reservoir and, where applicable, considering the type, number, location and efficacy of any wells that are servicing, or otherwise associated with, the reservoir (e.g. , producing wells, dead wells, and observation wells), analyzing the present condition or state of the reservoir using asymmetric weighting of different metrics, and prognosticating future production, recovery and other variables based on a comprehensive understanding of the specific reservoir DNA coupled with the asymmetric weighting and analysis of the data.
  • the gathered information may relate to measurements and data generated by others.
  • RCAATM is an assessment process which guides both the planning and implementation phases of petroleum recovery. All hydrocarbon assets carry an individual "DNA" reflective of their subsurface and surface features. RCAATM is an enabling tool for developing and applying extraction methods which are optimally designed to the specifications of individual hydrocarbon reservoirs. Its main value is assisting in the realization of incremental barrels of reserves and production over and above levels being achieved using standard industry techniques. This, in turn, may reduce long-term capital and operating expenses.
  • implementation of RCAATM spans six interweaving and interdependent tracks: i) Knowledge Systems; ii) Q6 Surveys; iii) Deep Insight Workshops; iv) Q-Diagnostics; v) Gap Analysis; and vi) Plan of Action.
  • the information gathered from these tracks is integrated using modern knowledge- sharing mediums including web-based systems and communities of practice.
  • a comprehensive chart showing the conceptual and temporal interrelation of the six tracks is illustrated in Figures 1A and IB (i.e., two halves of one chart). While the overall business model includes both technological and non-technological means for gathering the relevant information, the method cannot be implemented without the use of physical processes and machinery for gathering key information.
  • implementing a plan of action involves computerized monitoring of well activity. And enhanced reservoir performance results in a physical transformation of the reservoir itself.
  • Physical processes that utilize machinery to gather data include, for example, 1) coring to obtain down hole rock samples (both conventional and special coring), 2) taking down hole fluid samples of oil, water and gas, 3) measuring initial pressures from RFT or like devices, and 4) determining fluid saturations from well logs (both cased hole and open hole).
  • the reservoir is transformed from a lower-producing to a higher-producing asset.
  • Figure 2 illustrates how the inventive process physically transforms the petroleum reservoir and/or recovery system by increasing current production and overall long-term recovery.
  • Monitoring the performance of the reservoir before, during and/or after implementation of a plan of action involves the use of a computerized system (i.e., part of the "control room") that receives, analyzes and displays relevant data (e.g., to and/or between one or more computers networked together and/or interconnected by the internet).
  • relevant data e.g., to and/or between one or more computers networked together and/or interconnected by the internet.
  • metrics that can be monitored include 1) reservoir pressure and fluid saturations and changes with logging devices, 2) well productivity and drawdown with logging devices, fluid profile in production and injection wells with logging devices, and oil, gas and water production and injection rates.
  • Relevant metrics can be displayed on the internet. Web based systems can share such data.
  • Figures 3A-3D illustrate exemplary "dashboards" that can be used to graphically display certain metrics (e.g. , leading and lagging) compiled from ongoing data sampling of producing wells.
  • the dashboards can provide a quick visual diagnostic tool
  • FIG. 4 illustrates an exemplary computer-implement monitoring system 400 that monitors reservoir performance, analyzes information regarding reservoir performance, displays dashboard metrics, and optionally provides for computer- controlled modifications to maintain optimal oil well performance.
  • Monitoring system 400 includes a main data gathering computer system 402 comprised of one or more computers located near a reservoir and linked to reservoir sensors 404.
  • Computer system 402 may comprise a plurality of networked computers (e.g., each of which is designed to analyze a sub-set of the overall data generated by and received from the sensors 404).
  • Reservoir sensors 404 are typically positioned at producing oil well, and may include both surface and sub-surface sensors. Sensors 404 may also be positioned at water injection wells, observation wells, etc.
  • the data gathered by the sensors 404 can be used to generate performance metrics (e.g., leading and lagging indicators of production and recovery).
  • the computer system 402 may therefore include a data analysis module 406 programmed to generate metrics from the received sensor data.
  • a user interface 408 provides interactivity with a user.
  • Data storage device or system 410 can be used for long term storage of sensor data and/or metrics.
  • the computer system 402 can provide for at least one of manual or automatic adjustment to production 412 by reservoir production units 414 (e.g., producing oil wells, water injection wells, gas injection wells, heat injectors, and the like, and sub-components thereof). Adjustments might include, for example changes in volume, pressure, temperature, well bore path (e.g., via closing or opening of well bore branches).
  • the user interface 408 permits manual adjustments to production 412.
  • the computer system 402 may, in addition, include alarm levels or triggers that, when certain conditions are met, provide for automatic adjustments to production 412.
  • Monitoring system 400 may also include one or more remote computers 420 that permit a user, team of users, or multiple parties to access information generated by main computer system 402.
  • each remote computer 420 may include a dashboard display module 422 that renders and displays dashboards (e.g., as illustrated in Figures 3A-3D), metrics, or other information relating to reservoir production.
  • Each remote computer 420 may also include a user interface 424 that permits a user to make adjustment to production 412 by reservoir production units 414.
  • Each remote computer 420 may also include a data storage drive (not shown).
  • a network 430 such as, for example, a local area network ("LAN”), a wide area network (“WAN”), or even the Internet.
  • LAN local area network
  • WAN wide area network
  • the various components can receive and send data to each other, as well as other components connected to the network.
  • Networked computer systems and computers themselves constitute a "computer system" for purposes of this disclosure.
  • Networks facilitating communication between computer systems and other electronic devices can utilize any of a wide range of (potentially interoperating) protocols including, but not limited to, the IEEE 802 suite of wireless protocols, Radio Frequency Identification (“RFID”) protocols, ultrasound protocols, infrared protocols, cellular protocols, one-way and two-way wireless paging protocols, Global Positioning System (“GPS”) protocols, wired and wireless broadband protocols, ultra- wideband "mesh” protocols, etc.
  • RFID Radio Frequency Identification
  • GPS Global Positioning System
  • IP Internet Protocol
  • TCP Transmission Control Protocol
  • RDP Remote Desktop Protocol
  • HTTP Hypertext Transfer Protocol
  • SMTP Simple Mail Transfer Protocol
  • SOAP Simple Object Access Protocol
  • Computer systems and electronic devices may be configured to utilize protocols that are appropriate based on corresponding computer system and electronic device on functionality. Components within the architecture can be configured to convert between various protocols to facilitate compatible communication. Computer systems and electronic devices may be configured with multiple protocols and use different protocols to implement different functionality. For example, a sensor 404 at an oil well might transmit data via wire connection, infrared or other wireless protocol to a receiver (not shown) interfaced with a computer, which can then forward the data via fast ethernet to main computer system 402 for processing. Similarly, the reservoir production units 414 can be connected to main computer system 402 and/or remote computers 420 by wire connection or wireless protocol.
  • RCAATM utilizes a variety of reservoir performance metrics, including both leading and lagging indicators, that can provide information regarding the "DNA" of a reservoir. In addition, it utilizes unit development metrics, workload metrics, business plan metrics, and stretch goals. These indicators and metrics typically utilize specialized terminology and variables that may not be readily understood by the lay person. The following nomenclature and definitions are provided to clarify and enhance understanding of the disclosed metrics and how they may relate to reservoir properties.
  • ER T Theoretical Maximum Recovery Factor (TMRF). The maximum fraction of the OIIP that can be recovered from a particular displacement process, dimensionless Volumetric sweep efficiency or volumetric conformance. The volume of the reservoir contacted by injected fluid divided by the total volume, dimensionless
  • Npoe Dimensionless cumulative oil volume Expressed as a fraction of the Expected Ultimate Recovery, dimensionless pDm Dimensionless cumulative oil volume. Expressed as a fraction of the Mobile Oil Initially In Place, dimensionless NpDo Dimensionless cumulative oil volume. Expressed as a fraction of
  • a dd Drawdown Pressure The external boundary pressure minus the flowing sandface pressure, psi Median Pressure Drawdown. Median pressure drawdown value for all producing wells completed in a particular reservoir, psi
  • VRR Voidage Replacement Ratio The injection volume divided by the produced production volume for a specific time period.
  • N PV * (1 - S wc )
  • N M PV*(l-S or -S wc )
  • PIDM (PI/PI iv )M A dd(D ) - (A dd / Apdd(iv))ivi
  • IP Depletion ⁇ ⁇ / 1 ⁇
  • the reservoir performance metrics utilized in RCAATM are generally classified as leading indicators, lagging indicators, unit development metrics, workload metrics, business plan metrics, and stretch goals.
  • leading indicators are more predictive of future productivity and/or recovery than lagging indicators.
  • Lagging indicators may, however, provide an accurate accountability tool. Both types of indicators can be used to identify gaps between reality and the ideal and help improve production and recovery.
  • leading indicators that can be used in RCAATM.
  • a first leading indicator is the "Dead Well Index”
  • a related leading metric is the "Dead Wells Gradient”.
  • the Dead Well Index is determined by the number of dead wells divided by the sum of both dead and active producers. The ratio is therefore dimensionless.
  • the Dead Wells Gradient is the normalized yearly rate of change of dead well index: (DWI), (DWIi-DWIo) / DWI 0 , yf '.
  • Figure 5A is a bar graph that shows an exemplary year-to-year comparison of the Dead Well Index. It also includes a line showing the Dead Wells Gradient.
  • a second leading indicator is the "Gas Oil Ratio” (GOR).
  • GOR Gas Oil Ratio
  • a related leading metric is the "Gas Oil Ratio Gradient”
  • the Gas Oil Ratio is the producing ratio of gas to oil volume: (R) - AG P I ⁇ ⁇ , scf/stb.
  • the Gas Oil Ratio Gradient is the rate of change of the Gas Oil Ratio: GOR fs: Ri- R 0 , yf'.
  • Figure 5B is a bar graph that shows an exemplary year-to-year comparison of the Gas Oil Ratio. It also includes a line showing the Gas Oil Ratio Gradient.
  • a third leading indicator is the "Reservoir Pressure Change".
  • the Reservoir Pressure Change is the difference in annual volumetric weighted average reservoir pressure: psi-yf' .
  • Figure 5C is a bar graph that shows an exemplary year-to-year comparison of the Reservoir Pressure Change.
  • a fourth leading indicator is the "Oil Decline Rate”.
  • a related leading metric is the "Oil Decline Rate Gradient”.
  • the Oil Decline Rate Gradient is the annual change in Oil Decline Rate, or Ci - C 0 , yf 2 .
  • Figure 5D is a bar graph that shows an exemplary year-to-year comparison of the Oil Decline Rate. It also includes a line showing the Oil Decline Rate Gradient.
  • a fifth leading indicator is the "Waterflood Efficiency”.
  • a related leading metric is the "Waterflood Efficiency Gradient”.
  • the Waterflood Efficiency Gradient is the normalized yearly rate of change in waterflood efficiency: (E w ) - Ewi - E w0 , yf 1 .
  • Figure 5E is a bar graph that shows an exemplary year-to-year comparison of the Waterflood Efficiency. It also includes a line showing the Waterflood Efficiency Gradient.
  • a sixth leading indicator is the "Water Cut”.
  • a related leading metric is the "Water Cut Gradient”.
  • the Water Cut Gradient is the normalized yearly rate of change in water cut, or WCi - WCo, y l .
  • Figure 5F is a bar graph that shows an exemplary year-to-year comparison of the Water Cut. It also includes a line showing the Water Cut Gradient.
  • a first lagging indicator is the "Average Producer Liquid Rates", which includes both "Oil Rate” and "Water Rate".
  • Figure 6A is a bar graph that shows an exemplary year-to-year comparison of the Oil Rate and Water Rate.
  • a second lagging indicator is the "Depletion Rate”.
  • a first type of Depletion Rate is the “Expected Ultimate Recovery (EUR) Depletion Rate”, which equals ⁇ ⁇ / EUR, and is dimensionless.
  • Figure 6B is a bar graph that shows an exemplary year-to-year comparison of the Expected Ultimate Recovery (EUR) Depletion Rate and IP Depletion Rate.
  • a third lagging indicator is the "Depletion State”.
  • a third type of Depletion State is simply the OIIP Depletion State.
  • Figure 6C is a bar graph that shows an exemplary year-to-year comparison of the Expected Ultimate Recovery Depletion State, the Mobile OIIP Depletion State, and the OIIP Depletion State.
  • a fourth lagging indicator is the "Dimensionless Pressure Drawdown"
  • Figure 6D is a bar graph that shows an exemplary year-to-year comparison of the Dimensionless Pressure Drawdown.
  • a fifth lagging indicator is the "Dimensionless Productivity Index".
  • the Dimensionless Productivity Index is the median Productivity Index (PI) divided by the median ideal vertical Productivity Index and is dimensionless: (PI / PIJV)M- Figure 6E is a bar graph that shows an exemplary year-to-year comparison of the Dimensionless Productivity Index.
  • a sixth lagging indicator is the "Dimensionless Injectivity Index".
  • a seventh lagging indicator is the "Gas Rate".
  • Figure 6G is a bar graph that shows an exemplary year-to-year comparison of the Gas Rate.
  • An eighth lagging indicator is the "Liquid Rate".
  • a first type of Liquid Rate is the “Maximum Efficient Rate” (MER), mbd, and is the reservoir off-take rate above which will occur significant reduction in estimated ultimate recovery.
  • Figure 6H is a bar graph that shows exemplary year-to- year comparisons of the MER, oil rate and water rate.
  • a ninth lagging indicator is the "Pressure Gradient".
  • the Pressure Gradient is the median pressure difference across a distance, e.g. , the pressure difference between a producer and injector divided by the distance, or ⁇ / , psi/ft.
  • a tenth lagging indicator is the "Productivity Index Gradient".
  • the Productivity Index Gradient is the change in the median productivity index as a result of reservoir compaction: 1 - (PIMI PIMO), bpd/psi.
  • An eleventh lagging indicator is "Rate Restrictions”. Rate Restrictions are the sum of wellhead potential rates minus the sum of restricted rates, mbd.
  • a variation includes Dimensionless Rate Restrictions, which are the effective rate restrictions divided by MSC, dimensionless.
  • a twelfth lagging indicator is the "Recovery Efficiency”.
  • a thirteenth lagging indicator is the "Transmissibility Index”.
  • Transmissibility Index is the permeability-cross-sectional area product divided by distance: kA / L, md-ft.
  • a fourteenth lagging indicator is the "Voidage Replacement Ratio" (VRR).
  • a first type of Voidage Replacement Ratio is the “Surface Voidage Replacement Ratio”, which is the VRR at surface conditions of pressure and temperature: AW; / ( ⁇ ⁇ + AW P ), dimensionless.
  • a second type of Voidage Replacement Ratio is the “Reservoir Voidage Replacement Ratio”, which is the VRR at reservoir conditions of pressure and temperature: (AWi x B w )/ (( ⁇ ⁇ x B 0 ) + (AW P x B w )), dimensionless.
  • Figure 61 is a bar graph that shows exemplary year-to-year comparisons of the Surface Voidage Replacement Ratio and Reservoir Voidage Replacement Ratio.
  • a first unit development metric is the "Cost Factor”.
  • a first type of Cost Factor is the “Drilling Cost Factor”, which is the average annual initial oil production rate divided by the drilling and completion cost, bpd/$.
  • a second type of Cost Factor is the “Workover Cost Factor”, which is the average annual initial oil production rate divided by the workover cost, bpd/$.
  • Figure 7A is a bar graph that shows exemplary year-to-year comparisons of the Drilling Cost Factor and Workover Cost Factor.
  • a second unit development metric is the "Efficiency Factor” (or Rig Efficiency Factor).
  • a first type of Efficiency Factor is the “Drilling Efficiency Factor”, which is the average annual initial oil production rate divided by the number of days required to drill and complete a well, bpd/rig-days.
  • a second type of Efficiency Factor is the “Workover Efficiency Factor”, which is the average annual initial oil production rate divided by the number of days required to workover a well, bpd/rig-days.
  • Figure 7B is a bar graph that shows exemplary year-to-year comparisons of the Drilling Efficiency Factor and Workover Efficiency Factor.
  • a third unit development metric is the "Median Reservoir Contact”.
  • a first type of Median Reservoir Contact involves producers, which measures the median producer reservoir contact, ft.
  • a first type of Median Reservoir Contact involves injectors, which measures the median injector reservoir contact, , /?.
  • Figure 7C is a bar graph that shows exemplary year-to-year comparisons of Median Reservoir Contact for both producers and injectors.
  • a first workload metric is Professional Training.
  • a first type is Papers, or the number of papers submitted to outside organizations for presentation and/or publication, annual count.
  • a second type is Training Days, or the number of days spent in in-house or third party courses divided by total professional manpower count, annual count.
  • a third type is In-House Courses, or the number of in-house courses, annual count.
  • a fourth type is Third Party Courses, or the number of third party courses, annual count.
  • Figure 8A is a bar graph that shows exemplary year-to-year comparisons of different types of Professional Training.
  • a second workload metric is Studies.
  • a first type is Short Term, or ongoing studies (excluding simulation) lasting less than twelve months, annual count.
  • a second type is Long Term, or ongoing studies (excluding simulation) lasting more than twelve months, annual count.
  • a third type is Simulation, or ongoing numerical simulation studies, annual count.
  • a fourth type is Special Testing, or ongoing lab/field trials of new methods/technologies, annual count.
  • Figure 8B is a bar graph that shows exemplary year-to-year comparisons of different types of Studies.
  • a third workload metric is the "Well Count”.
  • a first type of Well Count is "New Wells”, which is the number of new wells drilled for the year, annual count.
  • a second type of Well Count is “Active (Horizontal/Lateral/Slant)", which is the mean number of active non-vertical producers operating for the year, annual count.
  • a third type of Well Count is “Active Total”, which is the mean number of all active producers operating for the year, annual count.
  • Figure 8C is a bar graph that shows exemplary year-to-year comparisons of Well Count for each of New Wells, Active (Horizontal/Lateral/Slant), and Active Total.
  • a first business plan metric is "Fluid Rates".
  • a first type of Fluid Rate is the “Oil Rate”, which is the forecast oil rate for a five year business planning cycle, mbd.
  • a second type of Fluid Rate is the “Water Rate”, which is the forecast water rate for a five year business planning cycle, mbd.
  • a third type of Fluid Rate is the "Water Cut”, which is the forecast water cut for a five year business planning cycle, mbd.
  • Figure 9A is a bar graph that shows exemplary year-to-year comparisons of Fluid Rates for each of Oil Rate, Water Rate, and Water Cut.
  • a first business plan metric is "Producer Drilling Requirements”.
  • a first type of Producer Drilling Requirement is "New Wells", or the total number of producers required to provide the forecast oil rate, annual count.
  • a second type of Producer Drilling Requirement is "Sidetracks", or the total number of sidetracks of existing producers to provide the forecast oil rate, annual count.
  • Figure 9B is a bar graph that shows exemplary year-to-year comparisons of Producer Drilling Requirements for both New Wells and Sidetracks.
  • a first stretch goal is "Components”.
  • a first type of Components stretch goal is "Historical”: the last five years of performance are provided for perspective.
  • a second type is "Forecast”: a five year business plan forecast that considers the current rate of implementation of new technologies and best practices.
  • a third type is "Goal”: a five year forecast that considers a 10% acceleration in the implementation of new technologies and best practices.
  • Figure 1 OA is a bar graph that shows exemplary year-to-year comparisons and forecasts for Production Development Cost, particularly historical, forecast and goal.
  • a third stretch goal is "Voidage Replacement Ratio" (VRR).
  • VRR Vehicle Replacement Ratio
  • One type is the Surfact VRR, which is the VRR at surface conditions: AW; / ( ⁇ ⁇ + AW P ), dimensionless.
  • Figure 1QB is a bar graph that shows exemplary year-to-year comparisons and forecasts for Surface Voidage Replacement Ratio, particularly historical, forecast and goal.
  • a fourth stretch goal is "Water Cut".
  • the Water Cut is the producing ratio of water to liquid volume: AW P / ( ⁇ ⁇ + AW P ), dimensionless.
  • Figure I OC is a bar graph that shows exemplary year-to-year comparisons and forecasts for Water Cut, particularly historical, forecast and goal.
  • RCAATM integrates a wide variety of information; however, its success in arriving at optimal solutions derives from its ability to filter out non-critical parameters and recognize fundamental areas of reservoir underperformance. This is achieved by means of a set of metrics designated as “Integrative Metrics”, Integrative Metrics (also called “Special Metrics”) include:
  • RRRTM Reservoir Management Rating
  • Integrative Metrics provide a numerical assessment of critical reservoir performance parameters which, in turn, become the screening basis for planning and implementation of optimal solutions.
  • a reservoir which scores poorly on RDITM points to the fact that its recovery design is mismanaged.
  • Case in point a reservoir being depleted without the benefit of a pressure-maintenance or secondary- recovery process will have a low RDITM score.
  • Remedial actions will need to consider a secondary-recovery (e.g., waterflood).
  • the Integrative Metrics will point in this direction very rapidly. As a result, correct application of RCAATM will result in increased recoveries and production rates while providing superior utilization of capital.
  • RMRTM is a structured approach for assessing the quality of reservoir management used in the recovery of hydrocarbons from a particular reservoir. It involves the use and analysis of a unique set of metrics, indices and quality measures as they relate to the physical state of the reservoir, the positioning and operation of wells (e.g., producers and injectors), and how the reservoir is managed (i.e., the long- term plan governing production and recovery).
  • a detailed description of RMRTM is set forth in U.S. Provisional Application No. 61/154,503 which was filed February 23, 2009, and entitled “METHOD OF ASSESSING THE QUALITY OF RESERVOIR MANAGEMENT," the disclosure of which is incorporated by specific reference.
  • RMRTM In order to implement RMRTM, a field is evaluated and judged (scored) on the basis of six categories using a letter grading system (A, B, C, and D). [See Table 2 below].
  • A, B, C, and D a letter grading system
  • the six categories can be assessed according to the following criteria:
  • Reservoir Management Design Is there a Reservoir Management Design? Does the design include Reservoir Management Tenets? Have the tenets been applied in the correct fashion? Reserves Appreciation Have the components of reserves determination been validated? Have the risks to achieving and appreciating reserves been identified? Have contingency plans been prepared?
  • FPDI Field Productivity Deficiency Index GC: Geological Complexity
  • RMI Risk Mitigation Index
  • VAR Value at Risk
  • a management score is assigned using the following weighting factors:
  • the foregoing weighting factors are used to generate a Reservoir Management RatingTM (RMRTM) Matrix, which identifies subcategories of metrics used to evaluate the competency of reservoir management within the various categories. The metrics are, in turn, used to generate a score.
  • the Reservoir Management RatingTM (RMRTM) 5 Matrix is illustrated below in Table 1.
  • a scoring scale for assessing reservoir management according to RMRTM is illustrated below in Table 2.
  • the Reservoir Management Design has a weighting of 25% relative to the overall Reservoir Management RatingTM. Important issues are 1) whether there is a Reservoir Management Design, 2) whether the design includes reservoir management tenets, and 3) whether the tenets been applied in the correct fashion. As set forth in Table 1 above, the Reservoir Management Design includes five subcategories, which are equally weighted relative to each other
  • RDITM Recovery Deficiency Indicator
  • RE is the projected Recovery Efficiency for the current recovery process
  • E A the fraction of floodable pore volume area swept by a displacing fluid
  • E[ the fraction of the floodable pore volume in the vertical direction swept by a displacing fluid, The Ideal case assumes 100% swept.
  • the metric for Field Depletion Rate is the Field Depletion Index (FDI).
  • FDI Field Depletion Index
  • RMF Risk Management Factor (determined in the following tables)
  • RMF Risk Management Factor
  • the metric for Well Rate/Drawdown is the Well Rate/Drawdown Index
  • the metric for Displacement Process Risk is the Displacement Process Risk Index (DPR1), which is defined or determined below. (Proviso: IF the downside risk of recovering 2P reserves has not been determined, THEN assign "60" to this subcategory and continue to the next subcategory.)
  • DPR1 Displacement Process Risk Index
  • VAR current the amount of 2P reserves at risk under the current recovery mechanism
  • the metric for Plateau Sustainability is the Plateau Sustainability Index (PSI), which is defined or determined below, with further reference to Table 9. (Proviso: IF the field depletion plan does not allow for plateau production, THEN assign "60" to this subcategory and continue to the next subcategory.)
  • PSI Plateau Sustainability Index
  • PSI % EUR (3 ⁇ 4 Decline Rate Onset * RMF
  • Decline Rate Onset the point at which no further actions (e.g., drilling new wells or workovers) can reverse natural decline under the current displacement process.
  • the Reserves Appreciation has a weighting of 25% relative to the overall Reservoir Management RatingTM, important issues are 1 ) whether the components of reserves determination been validated, 2) whether the risks to achieving and appreciating reserves been identified, and 3) whether contingency plans been prepared. As set forth in Table 1 above, the Reserves Appreciation includes five subcategories, which are equally weighted relative to each other
  • OIIP/GIIP Verification Index The OVI is determined according to the following criteria set forth in Table
  • the metric for Sweep Efficiency is the Sweep Efficiency Index (SEI).
  • SEI Sweep Efficiency Index
  • the Sweep Efficiency Index is defined or determined as follows (Proviso: IF the reservoir is under depletion or compression drive, THEN assign "NA” to this subcategory and continue to the next subcategory):
  • E A the fraction of floodable pore volume in the horizontal direction swept by a displacing fluid under the current plan
  • Ei the fraction of the floodable pore volume in the vertical direction swept by a displacing fluid under the current plan.
  • the metric for Displacement Efficiency is the Displacement Efficiency Index (DEI).
  • DEI Displacement Efficiency Index
  • the Sweep Efficiency Index is defined or determined with reference to Table 1 1. (Proviso: IF the reservoir is under depletion or compression drive, THEN assign "NA” to this subcategory and continue to the next subcategory.)
  • the metric for Reserves Verification is the Reserves Verification Index (RVI).
  • RVI Reserves Verification Index
  • VAR the amount of 2P reserves at risk under the current recovery mechanism
  • V A G the amount of increase in 2P reserves that can be recovered as a result of an improved reservoir management design.
  • the metric for Risk Mitigation is the Risk Mitigation Index (RMI).
  • RMI Risk Mitigation Index
  • Figure 1 is a graph which illustrates how overall petroleum reserves of reservoir can be increases through risk mitigation as a result of implementation of RMRTM.
  • the Development and Operating Plan has a weighting of 20% relative to the overall Reservoir Management RatingTM. An important issue is whether the desired design goals and operating targets are being achieved. As set forth in Table 1 above, the Development and Operating Plan includes six subcategories, which are equally weighted relative to each other
  • the metric for Production Plan Achievement is the Production Plan Achievement Index (PPAI).
  • PPAI Production Plan Achievement Index
  • the Production Plan Achievement Index is defined or determined as follows, with further reference to Table 14.
  • the metric for Field Productivity is the Field Productivity Deficiency Index (FPDI).
  • FPDI Field Productivity Deficiency Index
  • the Field Productivity Deficiency Index is defined or determined as follows.
  • the metric for Pressure Management is the Pressure Management Index (PMI).
  • PMI Pressure Management Index
  • the Pressure Management Index is defined or determined as follows (Proviso: IF the reservoir is in its initial transient period, THEN assign "NA" to this subcategory and continue to the next subcategory):
  • the metric for Gas Management is the Gas Management Index (GMI).
  • the Gas Management Index is defined or determined with reference to Table 15. (Proviso: IF there is no gas cap or gas injection, THEN assign "NA" to this subcategory and continue to the next subcategory.)
  • the metric for Water Management is the Water Management Index (WMI).
  • WMI Water Management Index
  • the Drawdown Management Index is the Drawdown Management Index (DMI).
  • the Drawdown Management Index is defined or determined with reference to Table 16.
  • Reservoir Surveillance has a weighting of 10% relative to the overall Reservoir Management RatingTM. An important issue is how good is the Surveillance Program (tracking the right parameters the right way at the right times). As set forth in Table 1 above, Reservoir Surveillance includes two subcategories, which are equally weighted relative to each other
  • the metric for Master Plan Design is the Surveillance Plan Design Index (SPDI).
  • SPDI Surveillance Plan Design Index
  • the Surveillance Plan Design Index is defined or determined with reference to Table 17.
  • the metric for Master Plan Implementation is the Surveillance Plan Implementation Index (SPII).
  • SPII Surveillance Plan Implementation Index
  • the Surveillance Plan Implementation Index is defined or determined with reference to Table 18.
  • the category Technology Application has a weighting of 15% relative to the overall Reservoir Management RatingTM. Important issue are 1) whether the most appropriate technologies are being implemented to achieve the Recovery Design goals and 2) how ready and receptive is the reservoir owner or manager in considering state-of-the-art or alternate appropriate technologies. As set forth in Table 1 above, the category Technology Application includes four subcategories, which are equally weighted relative to each other.
  • the metric for Drilling Technology is the Drilling Technology Index (DTI).
  • the Drilling Technology Index is defined or determined with reference to Table 19.
  • DTI Drilling Technology Index
  • the metric for Completion Technology is the Completion Technology Index
  • the metric for Stimulation Technology is the Stimulation Technology Index (STI).
  • the Stimulation Technology Index is defined or determined with reference to Table 21.
  • the metric for Reservoir Dynamics Technology is the Reservoir Dynamics Technology Index (RDTI).
  • RDTI Reservoir Dynamics Technology Index
  • the Reservoir Dynamics Technology Index is defined or determined with reference to Table 22.
  • Reservoir Dynamics Technology includes formation evaluation and reservoir characterization, forecasting, surveillance and testing technologies.
  • the category Knowledge Management has a weighting of 5% relative to the overall Reservoir Management RatingTM. Important issue are 1) what is the organization's commitment to knowledge sharing initiatives, 2) whether data quality is complete, uniform, and consistent, while maintaining integrity and lacking duplication, 3) whether the owner or manager has access to virtual collaboration environments and how well utilized they are, and 4) whether the owner or manager has access to daily, monthly, or annual reports critical to your operations.
  • KMI Knowledge Management Index
  • KMI Knowledge Management Index
  • KM impacts key measures of organizational (1-100) * 0.30 .3 to 30 performance such as decreased cycle times, CAPEX/OPEX
  • All or part of the RMRTM method may be implemented using a conventional computer system comprised of one or more processors, volatile memory, non-volatile memory or system storage, and one or more input-output devices.
  • a conventional computer system comprised of one or more processors, volatile memory, non-volatile memory or system storage, and one or more input-output devices.
  • An example is computer system 400 discussed above and illustrated in Figure 4.
  • a method of assessing the quality of reservoir management used in the recovery of petroleum from a reservoir includes: 1) establishing reservoir management metrics for each of the following categories: a) reservoir management design, b) reserves appreciation, c) development and operating plan, d) reservoir surveillance and monitoring, e) technology application, and f) knowledge management; 2) weighting the reservoir management metrics according to the categories to which they belong; 3) obtaining data relating to the reservoir management metrics, at least some of the data being generated by at least one of (i) measuring a physical property of one or more producing oil wells and/or injector wells of the reservoir, (ii) taking and analyzing one or more core samples from the reservoir, or (iii) establishing a relationship between one or more different types of data from (i) or (ii); 4) generating the reservoir management metrics from the data; and 5) determining a reservoir management rating for the petroleum reservoir based on the reservoir management metrics, the reservoir management rating relating to at least one of production or recovery of petroleum from the
  • PGITM Production Gain Index
  • the Production Gain Index for a petroleum reservoir is defined as:
  • PGI -——————————————————————————a related index, the Global Productivity Index (GPITM), is defined as
  • ⁇ Aq A net actual production gain, stbpd (standard barrels produced per day);
  • ⁇ Joi d Sum of productivity indices of all producers prior project deployment, stbpd/psi;
  • CE fi Interference factor, which is an empirically derived factor that accounts for the loss in the aggregate production gain due to well interference. Its formula is as follows:
  • the dimensionless Production Gain Index is based on the petroleum engineering concept of the productivity index (J), which is a measure of the ability of the well to produce. It is defined as the well's stabilized flow rate measured at surface conditions divided by the well's drawdown. Drawdown is the difference in static bottom-hole pressure and stabilized flowing bottom-hole pressure.
  • the production gain index is a new method for quickly estimating the net gain in oil rate for a developed oil field (or reservoir) as a result of increasing aggregate well productivity.
  • the means by which the aggregate well productivity for a field may be increased include drilling additional producing wells, stimulation of existing wells, and increasing the reservoir contact of existing wells.
  • PGI enable engineers, managers, and investors to efficiently and quickly estimate the oil production rate, and financial gains, on a field basis when implementing certain types of capital projects.
  • the PGI is directly correlated with reservoir contact (i.e. , the greater the increase in reservoir contact, the greater the expected PGI).
  • an exemplary process for determining the production gain index includes: (1) determining or obtaining the net actual production gain, stbpd ⁇ AqA), (2) determining or obtaining the sum of current oil rates for existing producers, stbpd ( ⁇ qoid), and (3) dividing the net actual production gain by the sum or current oil rates for existing producers according to the following equation:
  • the PGI can be determined by (1) determining or obtaining the interference factor (C£) for a reservoir, (2) determining or obtaining the global productivity index (GPITM), which is the ratio of (a) the sum of productivity indices of all producers post project deployment, stbpd/psi ( ⁇ Jv ew ) and (b) the sum of productivity indices of all producers prior project deployment, stbpd/psi ( Jo ), and multiplying the interference factor by the difference between the global productivity index (GPITM) and 1 , according to the following equation:
  • the interference factor is determined according to the following equation:
  • the Recovery Deficiency IndicatorTM is a new leading indicator and metric that is designed to quickly assess the potential for increases in petroleum recovery from a reservoir.
  • the RDITM may form part of the RMRTM analysis.
  • a more detailed description of RDITM is disclosed in U.S. Provisional Application Number 61/101 ,008, which was filed September 29, 2008, and entitled "ASSESSING PETROLEUM RESERVOIR RESERVES AND POTENTIAL FOR INCREASE", the disclosure of which is incorporated by specific reference.
  • the RDITM is determined by taking the ratio of a reservoir's recovery efficiency (RE), or recovery factor, and its ideal recovery factor (IRE). This is represented as follows:
  • the recovery efficiency (RE) for a given petroleum reservoir is defined as the product of three factors:
  • EA the areal displacement efficiency, which is the fraction of floodable pore volume area swept by a displacing fluid
  • E v vertical displacement efficiency, which is the fraction of the floodable pore volume in the vertical plane swept by a displacing fluid
  • E D pore displacement efficiency, which is the fraction of oil saturation at the start of injection which is displaced by a displacing fluid in the invaded zone.
  • ED pore displacement efficiency
  • S or is defined as residual oil saturation, which can be measured on core plug samples in the lab after being flooded by ten pore volumes of a displacing fluid;
  • S wc is the water saturation at initial reservoir conditions.
  • Determination of the ideal recovery efficiency (IRE) for the reservoir is based on the traditional petroleum engineering concept of recovery efficiency (RE), which, as noted above, can be defined as the ratio of the volume of produced oil to the volume of oil initially in place (OIIP).
  • RE recovery efficiency
  • Values or estimates of EA, EV and ED can be determined in the field by operating existing observation wells or by drilling and logging new wells in swept areas of the reservoir.
  • production experience in very long-lived oil reservoirs in the Middle East and East Texas indicate that values of EA and Ey can reach 100%, especially using modern extraction technologies (e.g. , drilling, completion, formation evaluation, reservoir simulation, etc.).
  • the ideal reservoir efficiency can be derived from the reservoir efficiency by assuming that both EA and Ey are equal to 100%.
  • the IRE equation is simplified to just a determination of E D .
  • the ideal recovery efficiency for a given petroleum reservoir can be denoted by the equation:
  • Reservoir deficiency indicator (RDITM) values can be broken into five ranges or reservoir deficiency scores ("RDS"), which can be used to evaluate and highlight degrees of non-conformance and potential actions that can be taken to correct the shortfall in actual recovery compared to ideal recovery.
  • RFS reservoir deficiency scores
  • the reservoir deficiency scores can be tabulated as shown in Table 24 below:
  • Recovery deficiency indicators that are very high may indicate a highly efficiently operated reservoir with well implemented recovery techniques and strategies.
  • scores that are very low indicate significant room for improvement, translating into higher ultimate recovery and potential reserves.
  • Scores that exceed 100%, or which are unrealistically close to 100%, may be evidence of fraud on the part of the reservoir owner.
  • At least some of the information that is used to assess reservoir competency is gathered using Q6 surveys.
  • Q6 surveys The following are exemplary Q6 survey questions that can be answered by the reservoir owner or manager in order to help asses reservoir competency.
  • KPI's Key Performance Indicator's
  • RCAATM A detailed description of RCAATM is attached as an appendix to U.S. Provisional Application No. 61/031 ,167 filed February 25, 2008, and entitled "METHOD FOR DYNAMICALLY ASSESSING PETROLEUM RESERVOIR COMPETENCY THROUGH ASYMMETRIC ANALYSIS OF PERFORMANCE METRICS," the disclosure of which is incorporated herein in its entirety including the appendix thereto (hereinafter referred to as "RCAA document").
  • the RCAA document includes various sections, including an executive overview and a client SME (subject matter expert) workbook.
  • the executive overview briefly describes the RCAATM and what it seeks to accomplish and includes subsections relating to the preamble, QRI® (Quantum Reservoir Impact) reservoir management model, principal focus areas, and gap analysis.
  • the client SME workbook includes subsections relating to Q6 surveys, knowledge systems, deep insight workshops, Q-diagnostics, gap analysis, and plan of action (see Figure 1 ).
  • the various pieces of RCAATM interact together in a synergistic manner in order to maximize the ability knowledgably increase reservoir productivity (i.e., production and reserves).
  • exemplary methods for gathering formation may include knowledge systems, Q6 surveys, and deep insight workshops to ensure that all the relevant information is obtained.
  • the relevant information can be gathered in as little as 72 hours or as much as 180 days. A typical case may take about 90 days to accumulate the relevant information regarding the current state of affairs of a reservoir.
  • Examples of the knowledge pool used to gather information relating to a specific reservoir includes production and drilling data, core and PVT lab testing, special analysis testing, well construction, well design, geophysics, petrophysics, geology, selective and monitored field trials, and reservoir data.
  • a dashboard can provide instant monitoring of many dynamically changing variables at once. They may include triggers or alarms, such as maxima or minima which, when met, may require affirmative steps to alter how production is being carried. These include, for example, closing or opening valves in the well bore, choking or increasing flow rate by adjusting impellers, activating or altering pumps to increase flow rate, making perforations in the pipe to begin removing oil in certain locations in the bore, and stimulation of existing wells, such as by fracking or acidization, to increase the amount of rock through which oil flows.
  • a method of assessing the competency of a petroleum reservoir relative to production and recovery for purposes of initiating a plan of action to increase production and/or recovery comprising: 1) establishing a plurality of reservoir performance metrics that relate to the production and recovery of petroleum from the reservoir; 2) weighting one or more of the reservoir performance metrics more heavily than at least one other of the reservoir performance metrics to facilitate asymmetric analysis of the reservoir performance metrics; 3) obtaining data relating to the reservoir performance metrics, the data being generated by at least one of (i) measuring a physical property of one or more producing oil wells and/or injector wells of the reservoir, (ii) taking and analyzing one or more core samples from the reservoir, or (iii) establishing a relationship between one or more different types of data from (i) or (ii); 4) generating the reservoir performance metrics from the data; and 5) determining a competency rating for the petroleum reservoir based on asymmetric analysis of the reservoir performance metrics, the competency rating relating to at least one of
  • the data relating to the reservoir performance metrics are input into a computer, which then analyzes and displays the data in one or more forms, such as spreadsheets and tables (e.g., as illustrated in Figures 5-10).
  • the displayed data can be used to assess reservoir competency. In general, the worse an existing reservoir is currently being managed and operated, the more gains can be made through implementation of the RCAATM methodology.
  • the metrics that are most important in assessing reservoir competency include the leading indicators described above.
  • useful leading indicators include dead well index, dead well gradient, gas oil ratio, gas oil ratio gradient, reservoir pressure change, oil decline rate, oil decline rate gradient, waterflood efficiency, waterflood efficiency gradient, recovery deficiency indicator, or production gain index.
  • lagging indicators include average producer liquid rates, oil rate, water rate, depletion rate, expected ultimate recovery depletion rate, IP depletion rate, depletion state, expected ultimate recovery depletion state, mobile oil initially in place depletion state, dimensionless pressure drawdown, dimensionless productivity index, dimensionless injectivity index, gas rate, liquid rate, maximum efficient rate, pressure gradient, productivity index gradient, rate restrictions, dimensionless rate restrictions, recovery efficiency, oil recovery factor, mobile oil depletion efficiency, theoretical maximum recovery efficiency, transmissibility index, voidage replacement ratio, surface voidage replacement ratio, reservoir voidage replacement ratio.
  • Other useful metrics for assessing the competency of a petroleum reservoir include unit development metrics, workload metrics, business plan metrics, and stretch goals.
  • metrics can be selected and weighted according to what is described in the section above relating to RMRTM.
  • the asymmetric assessment of reservoir competency helps to understand the specific DNA or state of affairs of the reservoir, which provides insight as to how a plan of action to increase productivity and recovery is to be designed. As more information is learned regarding the reservoir, other metrics may become more or less important to the analysis.
  • the RCAATM allows for distillation of the data. It takes a complex picture that may be meaningless and distills it to a very clear picture. This helps develop a more intelligent and successful plan of action, and provides a tool for executing the plan of action. It acts as a continual guide to the organization.
  • ⁇ ix Sigma
  • 6 ⁇ Six Sigma
  • the purpose of 6 ⁇ is to identify outliers that are far outside the mean, such as oil producing wells. In many cases, outliers may simply be bad apples suitable for shutdown. However, the outliers might in some cases be the most highly productive oil wells of a reservoir. They might point to the ideal and form the basis for duplication by other oil wells or provide information regarding favorable subsurface conditions in the vicinity of the outlier oil wells. Outliers might be identified, for example, using a productivity gradient metric that compares oil well productivity across the entire reservoir.
  • a method for assessing the competency of a petroleum reservoir involves determining a reservoir management rating by asymmetrically weighting performance metrics relating to the following categories: reservoir management design, reserves appreciation, development and operating plan, reservoir surveillance, technology application, and knowledge management.
  • the performance metrics relating to reservoir management design including recovery design, field depletion rate, well rate/drawdown, displacement process risk, and plateau sustainability.
  • the performance metrics relating to reserves appreciation including oil OIIP/GIIP verification, sweep efficiency, displacement efficiency, reserves verification, and risk mitigation.
  • the performance metrics relating to development and operating plan including production plan achievement, field productivity, pressure management, gas management, water management, and drawdown management.
  • the performance metrics relating to reservoir surveillance including master plan design and master plan implementation.
  • the performance metrics relating to technology application including drilling technology, completion technology, stimulation technology, and reservoir dynamics technology.
  • the performance metric relating to knowledge management including knowledge management index.
  • the forgoing performance metrics are weighted according to the following weighting criteria: reservoir management design ⁇ reserves appreciation > development and operating plan > technology application > reservoir surveillance > knowledge management.
  • PGI Planar Graphik-to-Value
  • factors that involve PGI such as the level of reservoir contact, formation damage upon completion of a well, and the diameter of the bore.
  • Factors that affect whether there may be formation damage include, for example, the type of rock, drilling velocity, and pressure balance during drilling (e.g. , over balance might cause formation damage, which under balance might cause a blow out).
  • safe operation of the drilling equipment might require 500 pounds of overburden.
  • higher overburden might cause damage by pushing mud into the well. This, in turn, might prevent obtaining a good flow rate through the well.
  • Remedies to low PI may include, for example, one or more of an acid job, acid frack (i.e. , fracture), high pressure frack, and washing with water.
  • RDI RDI-related factors that may affect or determine reservoir competency
  • factors that involve RDI such as aerial sweep, vertical sweep, displacement efficiency, pore throat, and lithology. These mainly help in gap analysis, which asses the difference between the producer's goals and current production and recovery.
  • external factors may affect which metrics are most important. These include economic factors (i.e. , what is the time horizon of the owner in terms of dollars spent versus dollars earned from an enhanced recovery plan using RCAATM.
  • risk factors In general, risk factors can be mitigated by properly designing a recovery plan.
  • a plan of action according to RCAATM is formulated based on the properly gathered, analyzed and weighted data for a particular reservoir.
  • the plan of action constitutes a comprehensive road map with details regarding agreed upon metrics and key performance indicators. Because the plan of action is based on an accurate assessment of the short-, mid- and long-term condition of the reservoir and is tailored to the specific conditions of the reservoir and/or needs of the producer, the plan of action is far more likely to succeed and result in increased short-, mid- and/or long- term production and profits compared to what is possible using conventional methods.
  • designing a plan to increase productivity and/or recovery involves obtaining data from the diagnosis step described above and working with the producer to understand the benefits and limits of one or more possible plans of action.
  • RMRTM for example, will help develop of a rating system that permits a producer to intelligently assess a desirable plan of action. Workshops may be employed to test out different plans of action to determine what works best given the goals of the producer.
  • a producer may be content with providing a lower initial investment in improving reservoir competency, which will generally increase the initial return of investment but at the cost of reducing long-term production and ultimate recovery. Later increases in long-term production and recovery will generally cost more in the long run when taking this approach. Conversely, a producer having a longer-term horizon may be willing to providing a higher initial investment in improving reservoir competency. This generally decreases the initial return of investment but increases long-term productivity and recovery, which results in a reduction in total expenditure to maximize productivity and recovery.
  • a method of designing a plan of action for increasing production and recovery of petroleum from a petroleum reservoir comprises: 1) performing asymmetric analysis of the petroleum reservoir to determine reservoir competency, the asymmetric analysis being performed by weighting one or more reservoir performance metrics more heavily than at least one other reservoir performance metric; 2) establishing at least one of a desired depletion rate or a desired production rate and ultimate recovery for the petroleum reservoir; 3) building a replica of the petroleum reservoir that defines location of petroleum in the reservoir, including at least one of connectivity or disconnectivity of oil within the reservoir, potential flow paths of the petroleum as a result of extracting oil from the reservoir as a result of natural flow rates and/or fluid pressures in the reservoir and/or injection of ancillary fluids in the reservoir; and 4) designing a plan of action that includes production architecture relating to i) producing oil wells, including the number, location and how they are designed and operated, ii) injection of ancillary fluids (e.g., water and/or gas) to help drive oil toward the producing wells, including
  • performing asymmetric analysis of the petroleum reservoir to determine reservoir competency includes determining a reservoir management rating for the petroleum reservoir, the reservoir management rating being determined by asymmetrically weighting performance metrics relating to the following categories: reservoir management design, reserves appreciation, development and operating plan, reservoir surveillance, technology application, and knowledge management.
  • At least one of performing asymmetric analysis, establishing a desired production rate and ultimate recovery, building a replica of the petroleum reservoir, or designing a plan of action is carried out by means of a computer system having a processor and system memory and displaying information relating petroleum reservoir.
  • generating the replica of the petroleum reservoir is performed at least in part by a computer system, the replica of the petroleum reservoir comprising at least one of a numerical model or a visual display of some portion or all of the petroleum reservoir.
  • the method of designing a plan of action may further comprise designing architecture relating to the ancillary fluids including separation of the ancillary fluids from petroleum extracted from the reservoir and processing of the ancillary fluids.
  • the architecture relating to the ancillary fluids including at least one of disposal, reinjection or sale of the ancillary fluids.
  • the plan of action or production architecture includes design and placement of at least one maximum contact well having a plurality of branched, at least partially horizontal well bores.
  • This type of well is known as a "maximum reservoir contact" (MRC) well.
  • An exemplary MRC well is illustrated in Figure 1 1 , and includes a multiple branched well bore 1100, including a pluarality of spaced-apart well bore subsections 1102 that extended generally horizonatally through one or more strata 1104 of the reservoir.
  • the well bore subsections 1102 may also be positioned vertically relative to each other in order to better drain oil found at different reservoir depths.
  • an MRC well is used to better drain oil pockets that are generally fluidly interconnected.
  • RCAATM Another aspect of RCAATM is implementation of the plan of action formulated based on the properly gathered, analyzed and weighted data for a particular reservoir.
  • the plan of action is designed in consideration of the RMRTM and to increase productivity and/or recovery from the reservoir.
  • a method of implementing a plan of action for increasing production and recovery of petroleum from a petroleum reservoir comprising: 1) obtaining a plan of action designed using asymmetric analysis of the petroleum reservoir to determine reservoir competency, the asymmetric analysis being performed by weighting one or more reservoir performance metrics more heavily than at least one other reservoir performance metric, the plan of action including production architecture relating to i) new producing oil wells, including the number, location and how they are designed, ii) injection of ancillary fluids to help drive oil in the reservoir toward the producing wells, including the placement of one or more injector wells and volume of ancillary fluids injected through one or more injector wells, and optionally iii) stimulation of one or more existing producing wells to increase productivity; 2) placing new producing oil wells in locations at the petroleum reservoir and constructing the new producing oil wells according to the plan of action; and 3)_placing injector wells in locations at the petroleum reservoir according to the plan of action in order to help drive oil in the
  • the new producing oil wells are constructed so as to include one or more subsurface production control devices selected from the group consisting of down hole valves, down hole flow devices, impellers, choking devices, down hole submersible pumps, separation devices to pack or seal off a portion of the petroleum reservoir, and perforations in well pipe to increase reservoir contact area.
  • subsurface production control devices selected from the group consisting of down hole valves, down hole flow devices, impellers, choking devices, down hole submersible pumps, separation devices to pack or seal off a portion of the petroleum reservoir, and perforations in well pipe to increase reservoir contact area.
  • At least one of the new producing oil wells is constructed as a maximum reservoir contact well having a plurality of branched and at least partially horizontal well bores (See Figure 1 1 ).
  • the new producing oil wells may also be constructed to as to include well pipe perforations, with the number and direction of the perforations being in accordance with the plan of action.
  • implementing the plan of action further comprises redesigning the interior of one or more pre-existing oil wells in order to increase reservoir contact area and thereby increase well productivity.
  • Implementing the plan of action may also include placing injector wells and designing the volume of ancillary fluids injected through the injectors so as to be in accordance with the plan of action.
  • Implementing the plan of action may further include constructing and/or placing equipment for separating the ancillary fluids from petroleum extracted from the reservoir and processing the ancillary fluids.
  • Implementing the plan of action may further including stimulating one or more existing oil wells to increase productivity, such as by at least one of high pressure fracking, acid fracking, or acid washing.
  • implementing the plan of action may include shutting down one or more pre-existing oil wells so as to alter flow of petroleum through the reservoir in a manner that ultimately drains more oil from the reservoir than if the pre-existing oil wells were not shut down.
  • RCAATM Another aspect of RCAATM is monitoring and tracking the performance of a petroleum reservoir, such as one designed or improved according to RCAATM. Again, proper monitoring and tracking of reservoir performance may be highly dependent on properly gathering, analyzing and weighting data relating to the reservoir. In general, leading indicators are better able to help predict future adverse events, and provide the ability to resolve or remedy such events, than lagging indicators.
  • a computer implemented method of monitoring and tracking reservoir performance relative to at least one of production or recovery comprising: 1 ) taking or receiving measurements relating to oil well performance at a petroleum reservoir and inputting the measurements into a computer system having a processor and system memory; 2) the computer system relating the measurements to performance metrics, at least some of which are leading indicators of oil well performance; 3) the computer system comparing at least some of the measurements and/or performance metrics relating to oil well performance to predetermined alarm levels or triggers; and 4) upon a measurement or performance metric exceeding an alarm level or trigger point by falling below a minimum or exceeding a maximum, the computer system performing at least one of i) altering at least one production parameter by an oil well or ii) alerting a reservoir manager, owner and/or third party that an alarm level or trigger point has been exceeded.
  • the computer system may also display information relating to at least one measurement and/or performance metric relating to oil well performance, such as graphically and/or so as to appear as a dial (e.g.,
  • exceeding an alarm level or trigger point may result in or require at least one of increasing or reducing oil production by one or more oil wells of the reservoir.
  • exceeding an alarm level or trigger point may result in or require at least one of increasing or reducing oil production by putting one or more new oil wells into production at the reservoir or stopping production by one or more oil wells.
  • exceeding an alarm level or trigger point may result in or require at least one of increasing or reducing ancillary fluid injection into the reservoir.
  • exceeding an alarm level or trigger point may result in or require stimulation of at least one oil well to increase well productivity.
  • the field in this example has been on production under a peripheral waterflood. It is in a mature state of depletion with more than 70% of its reserves already produced. Re-engineering efforts were initiated to reduce field decline rates and water-cuts. A secondary objective was to lower ESP requirements and associated capital programs.
  • the field produces from a 60+ meters thick carbonate reservoir which is comprised of numerous shoaling-upwards cycles.
  • the reservoir has an average porosity of more than 15% and permeability up to several darcies.
  • the upper half of the reservoir is generally very high reservoir quality; the lower half contains numerous interbeds of high and low reservoir quality.
  • the lower half reservoir quality is enhanced by the addition of fracture permeability which significantly increases reservoir conductivity while also increasing risks of premature water breakthrough.
  • the reservoir has more than 300 meters of structural closure and a weak initial edge-water drive which was replaced with a peripheral waterflood.
  • Gap analysis and knowledge systems in the form of well ranking were employed to recognize deficiencies in the prior depletion plan and provide direction as to remedies.
  • the subject reservoir was undergoing peripheral water flooding with the objective of cycling as much water as possible to maximize ultimate recovery.
  • the operator produced the down-dip front-row producers at high rates and water cuts.
  • the up-dip producers suffered from low pressures which lead to a high dead well count and diminished up-dip oil potential.
  • the operator was trying to impose a viscous dominated recovery model on a gravity dominated system. Solutions to this problem included employing a unified water management plan of individual producers coupled with the use of horizontal geometries for new wells and workovers.
  • the field in this example went on-stream in 2006 with a production rate of 300,000 Bbls/day and was the third increment of a three-increment field development plan. It is under a peripheral waterflood. Re-engineering efforts in designing the new production increment were initiated due to concern about premature water breakthrough, excessive development costs and high well decline rates, all due to complex geology. These concerns were based on experience gained through the development and performance of two adjacent oil-containing increments.
  • the field produces from a 60 meter thick carbonate reservoir which is comprised of numerous shoaling-upwards cycles.
  • the reservoir has an average porosity of about 15% and permeability up to 100 millidarcies.
  • the upper half of the reservoir is generally moderate reservoir quality; the lower half contains numerous interbeds of moderate and low reservoir quality.
  • the reservoir quality is enhanced by the addition of fracture permeability which significantly aids in the recovery process.
  • the reservoir has more than 250 meters of structural closure and a weak initial edge- water drive which was replaced with a peripheral waterflood.
  • the first increment was developed using vertical wells and the second increment utilized short horizontals. While horizontal wells were an improvement over verticals, both configurations suffered from relatively low productivity indexes (Pis), which resulted in the wells dying at lower water cuts. Usually, this action created the need for more drilling and ESPs to maintain rate.
  • interdisciplinary workshops and surveys were performed. The workshops brought into consideration new reservoir physical models, which in turn produced recommendation on the best technologies and methodologies to leverage those models. Ultimately, this activity led to the design and use of advanced well architecture, downhole monitoring and control, and I-Fields.
  • the field came successfully on-stream 5 months ahead of schedule and fully in line with planned production targets (300,000 Bbls/day).
  • the reservoir performance to date has been exceptionally good in terms of sustained well productivities, actual water-cuts and average reservoir pressures.
  • Key factors in ensuring the success of this project were: 1) well architecture designs and completions based on new technologies; 2) state-of-the-art real-time field monitoring (I-Field); and 3) overall field development and peripheral waterflood designs.
  • the field is characterized as a gently folded northeast/southwest-trending anticline consisting primarily of Cretaceous age sandstones, shales, and carbonates.
  • the reservoir consists of rudist buildups that vary laterally into barrier and shelf slope facies. While matrix porosity is generally high (with an average of 25%) and does not vary laterally, permeability is facies-dependent and exhibits spatial variability. In the south which is dominated by low-energy lagoon deposits, typical permeabilities range from 5 to 10 millidarcies.
  • 3D seismic data show that the reservoir contains a number of faults. These faults and fractures have been identified from open hole logs and are most prevalent in the northern part of the reservoir and can enhance reservoir quality where they occur. Because the reservoir depletion mechanism is primarily gas cap expansion, this also increases the risk of gas coning.
  • MRC Maximum Reservoir Contact
  • the reservoir in this example has been on production for more than 50 years and is in an advanced state of depletion, with more than 85% of its reserves already produced.
  • the main production drive is from a peripheral waterflood. Re- engineering efforts were initiated to reduce declines in well productivities and rapidly increasing water-cuts. A secondary objective was to lower ESP requirements and associated capital costs.
  • the field produces from a 60+ meters thick carbonate reservoir which is comprised of numerous shoaling-upwards cycles.
  • the reservoir has an average porosity of more than 15% and permeability up to several darcies.
  • the upper half is generally very high reservoir quality; the lower half contains numerous interbeds of high and low reservoir quality.
  • the remaining reserves in the field are largely in a thin oil column below a secondary gas cap and in a low permeability facies in the topmost layer located in the northern half of the field.
  • the reservoir has more than 300 meters of structural closure and a weak initial edge-water drive which was replaced with a peripheral waterflood.
  • This reservoir has been on production for more than 30 years. It benefits from a dual drive mechanism; an over lying gas cap and an underlying active aquifer system. It is in a mature state of depletion. Re-engineering efforts were initiated to improve the productivity of wells in an increasingly challenging development environment that involved high drilling costs, shrinking oil target window, reservoir heterogeneity and limitations on water and gas handling facilities.
  • the field produces from a 100 meter thick sandstone reservoir deposited in a fluvio-marine environment.
  • the reservoir consists of a lower main sand and an upper stringer sands interval. It has an average porosity of more than 20% and permeability up to several darcies.
  • the lower half of the reservoir is very high quality; the upper half contains meandering channels of high quality, but limited continuity. Most of the reserves recovered to date are from the easy to produce main sand; the majority of the remaining reserves reside in the difficult to locate, upper stringer sands.

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Abstract

L'invention porte sur des procédés pour estimer avec précision la condition d'un réservoir de pétrole et concevoir et mettre en œuvre un plan d'action pour augmenter la production et la récupération de pétrole à partir du réservoir. Des informations est réunie à l'aide d'un ensemble unique de mesures et de techniques de rassemblement d'informations, et analysée d'une façon ciblée par pondération appropriée des données dans le contexte du réservoir particulier et des buts du producteur. Une note de réservoir est générée à l'aide d'une analyse asymétrique de mesures, puis est utilisée pour formuler un plan d'action. Une architecture de production (par exemple, un nombre, un emplacement et un mode de construction de puits de pétrole et d'injecteur) est ensuite construite en fonction du plan d'action. Des performances de réservoir peuvent être contrôlées de façon continue et utilisées de façon continue pour vérifier des buts de production et de récupération et/ou pour délivrer des déclenchements ou des alarmes pour modifier l'équipement de production.
PCT/US2011/030940 2011-04-01 2011-04-01 Procédé pour estimer de façon dynamique une compétence de réservoir de pétrole et augmenter une production et une récupération par analyse asymétrique de mesures de performances WO2012134497A1 (fr)

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CN201180002391.5A CN102812203B (zh) 2011-04-01 2011-04-01 用于通过性能量度的非对称分析来动态地评估石油储集层能力并提高产量和采收率的方法
PCT/US2011/030940 WO2012134497A1 (fr) 2011-04-01 2011-04-01 Procédé pour estimer de façon dynamique une compétence de réservoir de pétrole et augmenter une production et une récupération par analyse asymétrique de mesures de performances

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