EP2619636B1 - Production monitoring system and method - Google Patents

Production monitoring system and method Download PDF

Info

Publication number
EP2619636B1
EP2619636B1 EP11827029.7A EP11827029A EP2619636B1 EP 2619636 B1 EP2619636 B1 EP 2619636B1 EP 11827029 A EP11827029 A EP 11827029A EP 2619636 B1 EP2619636 B1 EP 2619636B1
Authority
EP
European Patent Office
Prior art keywords
production
injection
measurement signals
processes
temporal
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Active
Application number
EP11827029.7A
Other languages
German (de)
English (en)
French (fr)
Other versions
EP2619636A1 (en
EP2619636A4 (en
Inventor
Arild BØE
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Production Monitoring AS
Original Assignee
Production Monitoring AS
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Production Monitoring AS filed Critical Production Monitoring AS
Publication of EP2619636A1 publication Critical patent/EP2619636A1/en
Publication of EP2619636A4 publication Critical patent/EP2619636A4/en
Application granted granted Critical
Publication of EP2619636B1 publication Critical patent/EP2619636B1/en
Active legal-status Critical Current
Anticipated expiration legal-status Critical

Links

Images

Classifications

    • 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
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • 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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure

Definitions

  • the present invention relates to production monitoring systems for monitoring production and injection from a configuration of oil and/or gas wells. Moreover, the invention concerns methods of monitoring aforesaid oil and/or gas wells for controlling operation of the wells. Furthermore, the invention relates to software products recorded on machine-readable data storage media, wherein the software products are executable upon computing hardware for implementing the aforementioned methods.
  • a contemporary oil and/or gas production system 10 includes multiple production and injection wells 80 including corresponding boreholes 20 penetrating into an underground geological formation 30 bearing an oil deposit 40 and/or a gas deposit 50.
  • the geological formation 30 corresponds to one or more anticlines 60 which form a natural containment for the oil deposit 40 and/or gas deposit 50.
  • the geological formation 30 is usually highly heterogeneous.
  • the deposits 40 , 50 are often contained within regions of porous rock with multiple fissures, cavities and structural weaknesses which define maximum pressures which can be sustained by the regions during oil and/or gas extraction.
  • Excessive pressure applied to the geological formation 30 can risk causing multiple unwanted fractures, namely "out of zone" fractures.
  • fracturing of boreholes 20 of the system 10 can cause multiple seabed surface fissures which can leak water and/or hydrocarbons, namely potentially causing severe environmental pollution in an offshore environment.
  • Such an event of multiple seabed surface fissures is believe to have occurred in the Gulf of Mexico in connection with the oil rig Deepwater Horizon , April 2010.
  • a contemporary problem is that software tools for controlling oil and/or gas production systems are insufficiently evolved for coping with complex dynamic characteristics of spatially-extensive porous oil and/or gas wells, namely a system of producers and injectors operating in conjunction with a heterogeneous porous medium.
  • the present invention seeks to provide an improved production monitoring system for providing enhanced control of complex oil and/or gas production systems.
  • the present invention seeks to provide an improved method of monitoring a complex production system comprising a plurality of producers and injectors operating in association with a heterogeneous porous medium.
  • a production monitoring system as defined in claim 1: there is provided a production monitoring system comprising a plurality of injection and production units coupled in operation to sensors for measuring physical processes occurring in operation in the injection and production units and generating corresponding measurement signals for computing hardware, wherein the computing hardware is operable to execute software products for processing the signals, characterized in that the software products are adapted for the computing hardware to analyse the measurement signals to abstract a parameter representation of the measurement signals, and to apply a temporal analysis of the parameters to identify temporally slow processes and temporally fast processes therein, and to employ information representative of the slow processes and fast processes to control a management process for controlling operation of the system.
  • the invention is of advantage in that analyzing the signals from the injection and production units into a plurality of temporal processes of mutually different time durations provides valuable insight into operation of the injection and production units and thereby enables the injection and production units to be controlled better.
  • the injection and production units have associated therewith production and injection rates (r A , r B ), together with upper and lower borehole pressures (p U , p L ) as the sensor signals, and the management processes is adapted to control the injection and production units in respect of one or more of: production rate, operating safety, maintenance requirement.
  • the temporal analysis involves applying a temporal filter for analysing temporal characteristics of the measurement signals by modelling the measurement signals, and determining deviations between the measurement signals and corresponding modelled measurement signals for identifying the temporally fast processes.
  • the temporal filter employs a Kalman filter.
  • the analysis is adapted for determining interaction between the injection and production units when intercepting a formation which is mutually common to the injection and production units.
  • the injection and production units include at least one of: oil and/or gas wells, multiple apparatus in a production facility, continuous mining facilities, geological water extraction facilities.
  • a method of monitoring a plurality of injection and production units characterized in that the method includes:
  • the method includes the injection and production units having associated therewith production and injection rates (r A , r B ), together with upper and lower borehole pressures (p U , p L ) as the sensor signals, and the management processes being operable to control the injection and production units in respect of one or more of: production rate, operating safety, maintenance requirement.
  • the method includes the temporal analysis involving applying a temporal filter for analysing temporal characteristics of the measurement signals by modelling the measurement signals, and determining deviations between the measurement signals and corresponding modelled measurement signals for identifying the temporally fast processes.
  • the temporal filter employs a Kalman filter.
  • a software product recorded on a machine-readable data storage medium, wherein the software product is executable on computing hardware for implementing a method pursuant to the second aspect of the invention.
  • an underlined number is employed to represent an item over which the underlined number is positioned or an item to which the underlined number is adjacent.
  • a non-underlined number relates to an item identified by a line linking the non-underlined number to the item.
  • the non-underlined number is used to identify a general item at which the arrow is pointing.
  • the boreholes 20A, 20B are associated with wells 80A , 80B respectfully.
  • the well 80A is employed to inject fluid
  • the well 80B is employed to receive fluid from the geological formation 30.
  • the geological formation 30 is usually heterogeneous in spatial nature. Temporally, the geological formation 30 exhibits a changing behaviour as depicted in FIG. 2 when fluid is removed from the formation 30 as denoted by a curve 120 , wherein an abscissa axis 100 denotes time t , and an ordinate axis 110 represents a rate r of production of oil and/or gas from the geological formation 30.
  • the oil deposit 40 and the gas deposit 50 will be under considerable natural pressure resulting in the well 80B producing oil and/or gas without the well 80A being required to inject fluid into the geological formation 30.
  • an apex 130 corresponding to maximum production rate is reached.
  • fluid increasingly has to be injected via the well 80A to maintain the production rate r from the well 80B.
  • a trajectory as denoted by 140 is eventually followed, unless advanced extraction techniques are used to flush out last remaining oil and gas from the geological formation 30 as denoted by a curve 150 .
  • a curve 150 For example, many older oil wells in Saudi Arabia are now believed to be past their apex 130 , and Saudi Arabia is increasingly seeking oil and gas offshore in order to satisfy World demand for oil and gas.
  • FIG. 2 represents a simple overview of production characteristics over a lifetime of the system 10 in respect of the borehole 20B adapted to extract fluid at a rate r B from the geological formation 30.
  • the system 10 can be represented as an equivalent electrical circuit as presented in FIG. 3 , wherein p A represents a pressure developed by the well 80A in its borehole 20A, and p B represents a pressure developed by the well 80B in its borehole 20B .
  • a flow resistance k A corresponds to that of a spatial region near a distal end of the borehole 20A
  • a flow resistance k B corresponds to that of a spatial region near a distal end of the borehole 20B.
  • the geological formation 30 is typically porous such that the oil deposit 40 and the gas deposit 50 are included within pores and cavities of the geological formation 30 ; the formation 30 has a spatial capacity denoted by c G and has an equivalent pressure p G .
  • the pressure p G is high from natural causes and will assist to maintain the production rate r B prior to the apex 130.
  • the borehole 20A must be maintained under elevated pressure relative to the borehole 20B , in other words p A > p B , in order to maintain oil and gas production after the apex 130.
  • FIG. 3 is a gross simplification of a real oil and/or gas well.
  • the flow resistances k A , k B can be dynamically changing, for example due to sedimentation, fracture of porous fissures, and opening of fissures as oil is removed.
  • the capacity c G of the geological region can also be temporally varying during oil and gas extraction. The mean pressure p G of the geological formation 30 will not be directly determinable without an additional borehole being drilled which is expensive.
  • an oil and/or gas well is a complex entity to measure, monitor and analyze.
  • pressures can be conveniently measured at top and bottom regions of the boreholes 20A , 20A ; these pressures will be referred to as p AU and p AL for the borehole 20A , and p BU and p BL for the borehole 20B .
  • the boreholes 20A, 20B will themselves represent flow resistance h A , h B respectively to fluid flow therethrough.
  • the boreholes 20A, 20B can be many kilometres long. If t is employed to denote time, a better representation for FIG. 1 is provided in FIG. 4 .
  • the flow resistances h A , k A , h B , k B as well as the capacity c G are potentially partially random functions of time t .
  • Such complexity potentially renders the system 10 difficult to control for achieving optimal oil and/or gas production.
  • such complexity extends beyond an equivalent model as represented in FIG. 4 on account of a real oil and gas producing system 10 being spatially extensive and intercepted by multiple pairs of boreholes 20 , for example as represented in FIG. 5 .
  • FIG. 5 there are n pairs of boreholes 20 which all communicate to varying extents with the geological formation 30.
  • the formation 30 associated with the platforms 80 can include interlinked regions whose properties change in a complex temporal manner during oil and/or gas extraction.
  • a complex array of boreholes 20 serves the geological formation 30 including many mutually coupled anticlines and layers of strata which exhibit unpredictable temporally varying flow resistance characteristics during oil and/or gas extraction therefrom, such that an equivalent model as illustrated in FIG. 5 is more pertinent to employ when attempting to monitor and control the system 10 .
  • optimal control of system 10 as depicted in FIG. 5 is highly complex, for example on account of the pressure p G within the geological formation 30 being a function of spatial location within formation 30.
  • the pressure p G within the formation 30 is defined by P G ( x , y, z, t ) wherein z , y, z are Cartesian coordinates for defining a region including the formation 30 , and t denotes time.
  • the inventors of the present invention have devised improved methods of monitoring and controlling the system 10 as depicted in FIG. 5 .
  • a conventional simulated approach for monitoring and controlling oil and gas production systems is to utilize multi-parameter input and output models based upon a conversion matrix for monitoring and controlling the systems.
  • such a simulated approach becomes too complex and computationally intensive, even when considerable computing power is applied to implement the simulated approach.
  • methods pursuant to the present invention are more efficient and are potentially susceptible to being implemented using relatively modest computing resources.
  • the borehole 20A operable as an "injector” and the borehole 20B operable as a “producer” enable oil and/or gas production to occur.
  • Continuous measurements of borehole distal pressure, namely p LA , p LB , and borehole proximate pressure (wellhead pressure), namely p UA , p UB , are made, together with measures of flow rates r A , r B for the "injector" and "producer” respectively.
  • FIG. 6 In FIG.
  • an abscissa axis 210 denotes time t
  • an ordinate axis 220 denotes a parameter of the system 10 , for example well-head proximate pressure.
  • the tests 200 conventionally involve applying a step perturbation change in flow rate r by applying a step change in one or more of the flow resistance h A and/or h B , or by changing the proximate wellhead pressures p AU , p BU A response of the system 10 to the step change perturbation at each well 80 provides insight into the flow resistances k A , k B , and also the capacity c G for each well 80 , namely for a portion of the geological region 30 associated with the wells 80A, 80B.
  • a time constant associated with an exponential pressure response to a step change in flow rate r provides an indication of the capacity c G
  • a magnitude of the pressure response provides an indication of the flow resistances k A , k B associated with the wells 80.
  • a quasi-constant measurement is only approximate when the geological formation 30 is extensive, porous and is intersected by multiple sets of boreholes 20.
  • a problem with such a conventional approach to testing boreholes 20 of a complex oil and/or gas production system is that, as illustrated in FIG. 6 , various discrete temporal events can occur which can influence borehole operation significantly in periods between tests 200. Moreover, it is uneconomical and/or undesirable to increase a frequency of the tests 200 on account of them being disruptive to production.
  • the inventors have appreciated, when controlling the system 10 including multiple pairs of mutually interacting boreholes 20 , that it is desirable to monitor several parameters, for example sand content in the flow r B in the borehole 20B by way of acoustic measurement. Moreover, it is also desirable to monitor other parameters including:
  • the present invention employs, in overview, a form of algorithm 300 as depicted in FIG. 7 .
  • the algorithm 300 includes:
  • a Kalman filter is a mathematical method which uses measurements that are observed in respect of time t that contain random variations, namely "noise", and other inaccuracies, and produces values that tend to be closer to true values of the measurements and their associated computed values.
  • the Kalman filter produces estimates of true values of measurements and their associated computed values by predicting a value, estimating an uncertainty of the predicted value, and then computing a weighted average of the predicted value and the measured value. Most weight in the Kalman filter is given to the computed value of least uncertainty. Estimates produced by Kalman filters tend to be closer to true values than the original measurements because the weighted average has a better estimated uncertainty than either of the values that went into computing the weighted average.
  • the algorithm 300 is based on a Kalman filter formulation of an oil and/or gas production system 10 having N i injectors and N p producers. Downhole distal pressure measurements p LA , p LB as well as wellhead proximate pressure measurements p UA , p UB in the injector and producer boreholes 20A, 20B are made available to the algorithm 300. In certain situations, only wellhead proximate pressures p UA , p UB are measured and corresponding data is supplied to the algorithm 300.
  • the algorithm 300 is also provided with measurements of injection and production flow rates r A , r B as a function of time t .
  • the injection and production flow rates r A , r B are beneficially measured using at least one of: ultrasonic measurement sensors, electromagnetic measurement sensors, pressure difference sensors associated with a flow resistance (for example a flow orifice or section of pipe).
  • the set of parameters J j in Equations 3 and 4 corresponds closely to an injectivity index and a productivity index. These indices are defined by physical properties of the fluids conveyed via the boreholes 20A , 20B and also porosity characteristics of the geological formation 30. Moreover, the set of parameters K ji and K jp represent an interaction between a well 80 " j " and an injector well 80A " i " or a producing well 80B " p ", namely as depicted in FIG. 5 .
  • the time derivative of the output variable Y is affected by combination of pressure gradient, P *, related to the well 80 " j ", and an influence from all system 10 variables at the time " t “, including an influence from the well 80 " j " itself.
  • the pressure gradient P * is susceptible to cause rapid changes as well as slow changes in operation of the system 10 , whereas interactions between wells 80 are found normally to cause slow changes. Separating influences of fast processes within the system 10 from slow processes therein is significant for reducing a computational load when using the algorithm 300 to monitor and control the system 10.
  • a semi steady state for the system 10 and its associated geological formation 30 is defined as an operating condition wherein a rate of change of pressure within the geological formation 30 is independent of spatial location within the formation 30.
  • the geological formation 30 achieves a semi steady state once initial pressure gradients have propagated within the geological formation 30 to reach its peripheral boundaries.
  • the semi steady state it is feasible for the semi steady state to be a dynamic description, but its associated time scales need to be longer than a time frame in which transient events, for example transient pressure events, occur within the geological formation 30 , for example at least a factor of 3 times difference in respective time frames, more preferably at least a factor of 10 times difference in respective time frames.
  • a normal semi steady state formulation corresponds to a single well 80 formulation wherein effects of other wells 80 in the system 10 are only accounted for through changes in a common reservoir pressure so that Equations 5 and 6 (Eq. 5 and Eq.
  • Equation 1 Equation 1 (Eq. 1) above enables a recursive solution to be achieved wherein a zero-order solution for describing the system 10 corresponds to a solution obtained without interaction.
  • This conclusion derived from mathematic analysis has enabled the inventors to appreciate that the complex system 10 can be conveniently separated out into quasi steady state characteristics on the first hand, and short term dynamic characteristics on the other hand. Such a conclusion would not be obvious from superficial inspection of the system 10 wherein events within the system 10 would be expected to occur in a continuous temporal spectrum requiring very considerable computing power to model accurately.
  • Equation 7 Equation 7
  • Equation 8 Equation 8
  • Such a zero-order representation in respect of Y is, in many ways, similar to a Hall plot employed in injection monitoring.
  • Equation 9 Eq. 9
  • Equation 10 Eq. 10
  • d Y w , j 1 d t ⁇ i K j i . Y j 0 + ⁇ p K j p .
  • Y p 0 ⁇ p K j i . ⁇ V i J i ⁇ ⁇ p K j p .
  • Equation 9 corresponds to the semi steady state formation as provided in Equation 5 (Eq. 5).
  • the present invention provides a Kalman filter formulation which reproduces semi steady state conditions within the system 10.
  • the Kalman filter formulation is also a generalization because it does not assume uniformity amongst wells 80 , neither does it assume well 80 interaction through a common reservoir pressure. This is a major benefit provided by the present invention.
  • Equation 1 Equation 1
  • Equation 12 Equation 12
  • the state variables Y j and Q are generated from a time series of borehole pressures p LA (t) , p LB (t), an initial pressure within the geological formation 30 , and measured and/or allocated flow rates r A , r B .
  • the injectivities, productivities and a matrix describing interactivity between wells 80 are estimated.
  • Aforementioned methods of monitoring and controlling the system 10 are not only capable of predicted quasi steady state conditions within the system 10 , but also coping with transient situations after closing or opening a well 80 of the system 10.
  • the method of the invention is based upon an assumption that a transient occurring within the system 10 is so fast such that interaction portions of Equation 1 (Eq. 1) and Equation 12 (Eq. 12) remain constant during the period of the transient.
  • the constant interaction portions is representative of an effective change in the pressure of the geological formation 30 as observed from a given well 80 with index j.
  • the method of the invention assumes that a time period of transient events which occur within a given well 80 of the system 10 is much shorter than a time scale in which the geological formation 30 responds generally to the transient events.
  • the method of the present invention namely utilizing the algorithm 300 , applied to monitor and control the system 10 would employ a data set corresponding to well 80 pressure/injection rate versus time. Whenever a shut-in or start-up of a given well 80 occurs within the system 10 , sensor data from the given well 80 is provided to a computing arrangement at a sufficient frequency for describing time scale of the shut-in and start-up.
  • the algorithm 300 is beneficially implemented as one or more software products stored on machine-readable data storage media.
  • the one or more software products are executable on computing hardware coupled via one or more interfaces to the multiple wells 80 whose boreholes 20 intersect with the geological formation 30.
  • the one or more software products enable operation of the system 10 to be monitored, as well as accommodating control back to the multiple wells 80 of the system 10 for improving operation of the system 10.
  • Such control can be optimized in several different ways, for example for maximum oil and gas production, for minimum maintenance and testing, for lowest operating pressure when there is a risk of fracture of the geological formation 30 for example.
  • the algorithm 300 employs Kalman filter methods, or equivalent alternative estimation methods, to estimate model parameters for Equation 1 and Equation 12 (Eq. 1 and Eq. 12) based upon measurements of pressures p and rate r as a function of time t .
  • the algorithm 300 employs two different time scales:
  • the algorithm 300 takes account of rapid changes in the system 10 such as opening and closing of wells 80 , fracture events, and bursts or similar. These rapid changes are conveniently monitored by rapid measurable changes in injectivities and/or productivities. For example, a fracture resulting in a change of injectivity will be manifest as a rapid change in the injectivity of a particular well 80.
  • the "fast-loop" solution employed in the algorithm 300 takes account of operational changes such as opening or closing chokes, opening or closing a sleeve and other changes modifying the response of the system 10 and/or its associated surface sub-system 400.
  • the "fast-loop” and “slow-loop” solutions employed in the algorithm 300 take account of phenomena resulting in slow changes, for example over time periods of weeks, in parameters describing the system 10.
  • the solutions take account of single well 80 as well as multi-well 80 changes within the system 10 .
  • Example multi-well 80 changes are accounted for in the interaction part of Equation 1 and Equation 12 (Eq. 1 and Eq. 12), for example changes in effective overall pressure in the geological formation 30 (i.e. "reservoir pressure"), "out-of-zone” injections and aquifer support.
  • Example single well 80 changes include slow degradation or improvements in productivity and injectivity caused by skin developments or similar processes; "skin development” refers to formation of surface layers within the borehole 20 and in the geological formation 30 which resist flow of fluid via surfaces onto which the layers have formed, wherein the skin development can potentially have detrimental or beneficial characteristics depending upon circumstances. Moreover, the "fast-loop” and “slow-loop” solutions are also able to identify to long term effects of rapid event-type changes, for example as identified in changes in production and/or injection rates in wells 80.
  • the algorithm 300 is thus operable, via its Kalman filter, to compute estimates of parameters including:
  • the algorithm 300 namely implemented in computing hardware 400 and sensing instruments 410 coupled thereto, has technical effect in that it senses physical conditions of the system 10 as sensed signals, analyses the signals, and then generates outputs which can be used for controlling operation of the system 10 to improve its productivity, increase operating safety and/or reduce maintenance costs. Improved operating safety is achieved by more appropriate control which assists to avoid blowouts, fractures and similar. Enhanced productivity is achieved by employing a more suitable injectivity strategy. Reduced maintenance can be achieved by maintaining appropriate productivity rates and/or injectivity rates for avoiding sedimentation which can block wells 80 and which is costly and time-consuming to rectify.
  • algorithm 300 can also be used for controlling other types of industrial processes and also mining operations, for example continuous seabed suction systems for extracting valuable minerals from ocean floor sediments and silt; such ocean mining processes must maintain appropriate flow rates and move extraction nozzles to most valuable mineral deposits in a dynamic real-time basis, namely activities which are advantageously controlled by using computing hardware executing the algorithm 300.
  • the present invention is susceptible to being used with existing contemporary injection and production wells 80 , both in on-shore applications and also in off-shore applications.

Landscapes

  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Geophysics (AREA)
  • Geophysics And Detection Of Objects (AREA)
  • General Factory Administration (AREA)
EP11827029.7A 2010-09-21 2011-09-21 Production monitoring system and method Active EP2619636B1 (en)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
NO20101311A NO20101311A1 (no) 2010-09-21 2010-09-21 Produksjons målingssystem og fremgangsmåte
PCT/NO2011/000265 WO2012039626A1 (en) 2010-09-21 2011-09-21 Production monitoring system and method

Publications (3)

Publication Number Publication Date
EP2619636A1 EP2619636A1 (en) 2013-07-31
EP2619636A4 EP2619636A4 (en) 2017-04-26
EP2619636B1 true EP2619636B1 (en) 2018-08-29

Family

ID=44970853

Family Applications (1)

Application Number Title Priority Date Filing Date
EP11827029.7A Active EP2619636B1 (en) 2010-09-21 2011-09-21 Production monitoring system and method

Country Status (5)

Country Link
EP (1) EP2619636B1 (no)
AU (1) AU2011306526B2 (no)
BR (1) BR112013006608A2 (no)
NO (1) NO20101311A1 (no)
WO (1) WO2012039626A1 (no)

Families Citing this family (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20180010430A1 (en) * 2015-02-20 2018-01-11 Production Monitoring As Production monitoring - multi volume dynamic semi steady parametric model
GB2555803B (en) * 2016-11-09 2021-11-10 Equinor Energy As System and method for providing information on production value and/or emissions of a hydrocarbon production system

Family Cites Families (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CA2661367C (en) * 2006-08-30 2015-08-25 Shell Canada Limited Method for controlling and/or optimizing production of oil and/or gas wells and facilities
WO2008100148A2 (en) * 2007-02-15 2008-08-21 Epsis As Data handling system
US20080201706A1 (en) * 2007-02-15 2008-08-21 Jan-Erik Nordtvedt Data handling system
US8170801B2 (en) * 2007-02-26 2012-05-01 Bp Exploration Operating Company Limited Determining fluid rate and phase information for a hydrocarbon well using predictive models
EA201000680A1 (ru) * 2007-10-30 2013-05-30 Бп Корпорейшн Норт Америка Инк. Способ и система помощи при бурении буровой скважины
CA2656853A1 (en) * 2008-03-03 2009-09-03 Satellite Systems And Solutions, Inc. Method and apparatus for mitigating environmental impact due to fluid leaks

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
None *

Also Published As

Publication number Publication date
EP2619636A1 (en) 2013-07-31
WO2012039626A1 (en) 2012-03-29
NO331098B1 (no) 2011-10-03
NO20101311A1 (no) 2011-10-03
AU2011306526B2 (en) 2014-11-27
BR112013006608A2 (pt) 2020-09-15
EP2619636A4 (en) 2017-04-26
AU2011306526A1 (en) 2013-04-11

Similar Documents

Publication Publication Date Title
Rocha-Valadez et al. Assessing wellbore integrity in sustained-casing-pressure annulus
EP3259444A1 (en) Method and apparatus for early detection of kicks
NO20230489A1 (en) Real-time parameter adjustment in wellbore drilling operations
EP3455458B1 (en) Multi-step subsidence inversion for modeling lithospheric layer thickness through geological time
US8594818B2 (en) Production monitoring system and method
Bohloli et al. Determination of the fracture pressure from CO2 injection time-series datasets
CN110671095A (zh) 一种地质地层压力智能随钻软测量方法
Gomes et al. Impact of Reservoir Reactions on Thermodynamic Scale Predictions
Ameen Fracture and in-situ stress characterization of hydrocarbon reservoirs: definitions and introduction
AU6930287A (en) Method for hydraulic fracture propagation in hydrocarbon- bearing formations
Akinbinu Prediction of fracture gradient from formation pressures and depth using correlation and stepwise multiple regression techniques
EP2619636B1 (en) Production monitoring system and method
Chen et al. Early gas kick detection-inversion-control integrated system: The significance of applications of managed pressure drilling: A review
CN114660269B (zh) 一种古潜山天然气动态成藏过程恢复方法
Han et al. Understanding Well Performance of Unconventional Extended Laterals in New Mexico, Delaware Basin
Suleymanov et al. Oil reservoir waterflooding efficiency evaluation method
Vincent et al. A new methodology for naturally fractured reservoir characterization: use of multi-well interference tests interpretation
Jiang et al. Reserves estimation for geopressured gas reservoirs
Dastgerdi et al. Estimation of underground interwell connectivity: A data-driven technology
Fragachan et al. Pressure monitoring: key for waste management injection assurance
US20180010430A1 (en) Production monitoring - multi volume dynamic semi steady parametric model
US20230060528A1 (en) Reservoir fluid flow profiling in a wellbore environment
CN117345204A (zh) 考虑复杂井网及应力敏感的加密井地层压力预测方法及装置
Park et al. Numerical Simulation of FDI Impacts on Parent Well LPO and Child Well EUR in S&T
Leng et al. A physics-based method for forecasting interwell connectivity using injection data

Legal Events

Date Code Title Description
PUAI Public reference made under article 153(3) epc to a published international application that has entered the european phase

Free format text: ORIGINAL CODE: 0009012

17P Request for examination filed

Effective date: 20130422

AK Designated contracting states

Kind code of ref document: A1

Designated state(s): AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO RS SE SI SK SM TR

DAX Request for extension of the european patent (deleted)
RAP1 Party data changed (applicant data changed or rights of an application transferred)

Owner name: PRODUCTION MONITORING AS

RA4 Supplementary search report drawn up and despatched (corrected)

Effective date: 20170328

RIC1 Information provided on ipc code assigned before grant

Ipc: E21B 44/00 20060101ALI20170322BHEP

Ipc: E21B 47/06 20120101ALI20170322BHEP

Ipc: G05B 23/02 20060101AFI20170322BHEP

RIC1 Information provided on ipc code assigned before grant

Ipc: E21B 44/00 20060101ALI20180213BHEP

Ipc: E21B 47/06 20120101ALI20180213BHEP

Ipc: G05B 23/02 20060101AFI20180213BHEP

GRAP Despatch of communication of intention to grant a patent

Free format text: ORIGINAL CODE: EPIDOSNIGR1

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: GRANT OF PATENT IS INTENDED

INTG Intention to grant announced

Effective date: 20180406

RIN1 Information on inventor provided before grant (corrected)

Inventor name: BOEE, ARILD

GRAS Grant fee paid

Free format text: ORIGINAL CODE: EPIDOSNIGR3

GRAA (expected) grant

Free format text: ORIGINAL CODE: 0009210

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: THE PATENT HAS BEEN GRANTED

AK Designated contracting states

Kind code of ref document: B1

Designated state(s): AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO RS SE SI SK SM TR

REG Reference to a national code

Ref country code: GB

Ref legal event code: FG4D

REG Reference to a national code

Ref country code: CH

Ref legal event code: EP

REG Reference to a national code

Ref country code: AT

Ref legal event code: REF

Ref document number: 1035852

Country of ref document: AT

Kind code of ref document: T

Effective date: 20180915

REG Reference to a national code

Ref country code: IE

Ref legal event code: FG4D

REG Reference to a national code

Ref country code: DE

Ref legal event code: R096

Ref document number: 602011051594

Country of ref document: DE

REG Reference to a national code

Ref country code: NL

Ref legal event code: MP

Effective date: 20180829

REG Reference to a national code

Ref country code: LT

Ref legal event code: MG4D

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: LT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: FI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: GR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20181130

Ref country code: RS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: NL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: BG

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20181129

Ref country code: IS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20181229

Ref country code: NO

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20181129

Ref country code: SE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

REG Reference to a national code

Ref country code: AT

Ref legal event code: MK05

Ref document number: 1035852

Country of ref document: AT

Kind code of ref document: T

Effective date: 20180829

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: AL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: LV

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: HR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

REG Reference to a national code

Ref country code: DE

Ref legal event code: R119

Ref document number: 602011051594

Country of ref document: DE

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: CZ

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: IT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: PL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: EE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: AT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: ES

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: RO

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

REG Reference to a national code

Ref country code: CH

Ref legal event code: PL

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: DK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: SM

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: SK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

REG Reference to a national code

Ref country code: BE

Ref legal event code: MM

Effective date: 20180930

REG Reference to a national code

Ref country code: IE

Ref legal event code: MM4A

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MC

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: LU

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180921

PLBE No opposition filed within time limit

Free format text: ORIGINAL CODE: 0009261

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: NO OPPOSITION FILED WITHIN TIME LIMIT

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: DE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20190402

Ref country code: IE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180921

26N No opposition filed

Effective date: 20190531

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: LI

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180930

Ref country code: CH

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180930

Ref country code: FR

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20181029

Ref country code: BE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180930

Ref country code: SI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MT

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180921

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: TR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: PT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: HU

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT; INVALID AB INITIO

Effective date: 20110921

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: CY

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180829

Ref country code: MK

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180829

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: GB

Payment date: 20230823

Year of fee payment: 13