Patent Application
20250067167
The present invention relates to methods and systems for reservoir monitoring using tracers. Aspects of the invention include a method and system for monitoring characteristics of zonal flow in a producing well. Aspects of the invention also include estimating a distribution of inflow rates in a hydrocarbon production well.
Hydrocarbon reservoirs are a subsurface accumulation of hydrocarbons contained in porous or fractured rock formations. When drilling a well, the well can extend through multiple layers of a reservoir. Each of the multiple layers may produce fluid to the well and each layer may have different flow properties due a number of factors including volume of hydrocarbon in the layer, permeability of the layer and depth.
During the lifespan of the well the influx from one or more layers or zones can change over time. This influx change can occur due to naturally occurring pressure differences or it can occur due to different rates of depletion during the well's life. Reservoir management and optimised oil recovery requires an understanding of the reservoir, the distribution of fluids within the reservoir, and the rates of influx from each layer or zone into the production well.
There is generally a need for a method and system for monitoring a multilayer reservoir which addresses one or more problems identified above.
It is amongst the aims and objects of the invention to provide a method and system for monitoring a multilayer reservoir and/or monitoring at least one depleted layer in a multilayer reservoir.
It is amongst the aims and objects of the invention to provide a method and system for monitoring a multilateral well and/or monitoring at least one depleted zone, layer or lateral in a multilateral well.
It is another object of the present invention to provide a method and system for monitoring the characteristics of multilayer reservoir.
It is another object of the present invention to provide a method and system for monitoring the characteristics of influx zones in a multilateral well.
It is another object of the present invention to provide a method and system for monitoring zonal flow in a producing well.
It is a further object of an aspect of the invention to provide a method and system for estimating the distribution of inflow rates in hydrocarbon production wells.
Further aims and objects of the invention will become apparent from reading the following description.
According to a first aspect of the invention, there is provided a method of estimating static pressure of one or more influx zones to a production well; the method comprises; arranging at least one tracer source with distinct tracer materials in known levels of the well; inducing production flow in the production well for at least two different flow rates; collecting at least one sample downstream of the one or more influx zones for each flow rate; measuring a bottom hole pressure for each flow rate; analysing the at least one sample for the presence or absence of tracer; based on the tracer data and bottom hole pressure data estimating a static pressure for the one or more influx zones.
The method may comprise identifying at least one bottom hole pressure where one or more influx zones start or stop flowing to a production well. The method may comprise calculating and/or determining static pressure of one or more influx zones to a production well.
The method may comprise arranging at least one tracer source in known levels of the well by installing, positioning or placing at least one tracer source in known levels of the well.
The one or more influx zones may be from the same reservoir. The one or more influx zones may be from different layers of the same reservoir. The one or more influx zones may be from different reservoirs. The one or more influx zones may be from different layers of different reservoirs. The one or more influx zones may be from one or more laterals in the same wellbore. The one or more influx zones may be from one or more different laterals in the same layer of a reservoir. The one or more influx zones may be from one or more different laterals in one or more different layers of the same reservoir. The one or more influx zones may be from one or more different laterals from different reservoirs. The method may comprise arranging at least one tracer source with distinct tracer materials in known levels of one or more laterals in the well;
The method may comprise estimating, calculating, determining and/or monitoring the static pressure of one or more influx zones of a multilayer reservoir to a production well. The method may comprise estimating, calculating, determining and/or monitoring the static pressure of one or more influx zones of a multilateral well. The method may comprise calculating, estimating, monitoring and/or measuring the static pressure for the one or more influx zones.
The method may comprise measuring the bottom hole pressure using a pressure measurement apparatus or pressure gauge. The pressure measurement apparatus or pressure gauge may be located downhole. The method may comprise measuring the static bottom hole pressure. The method may comprise measuring the flowing bottom hole pressure. The method may comprise logging measured bottom hole pressure for each flow rate.
The method may comprise modifying, changing and/or adjusting the production flow rate by operation of a choke connected to the production tubing. The choke may be a downhole choke or a surface choke. The method may comprise adjusting the flow choke inducing production flow in the production well for at least two different flow rates. The method may comprise adjusting the flow choke inducing production flow in the production well for three or more different flow rates.
The method may comprise producing hydrocarbons from the well at a first production flow rate, collecting at least one sample downstream of the one or more influx zones for the first flow rate and measuring a bottom hole pressure for the first flow rate. The method may comprise producing hydrocarbons from the well at a second production flow rate, collecting at least one sample downstream of the one or more influx zones for the second flow rate and measuring a bottom hole pressure for the second flow rate. The method may comprise producing hydrocarbons from the well at a third or further production flow rate, collecting at least one sample downstream of the one or more influx zones for the third or further flow rate and measuring a bottom hole pressure for the third or further flow rate.
The method may comprise adjusting the flow rate of the production flow to adjust the bottom hole pressure. The method may comprise increasing the flow rate of the production flow to decrease the bottom hole pressure. The method may comprise decreasing the flow rate of the production flow to increase the bottom hole pressure. The method may comprise adjusting the flow rate of the production flow to raise the bottom hole pressure above or to a static pressure of at least one or more zones to stop influx for the at least one or more zones. The method may comprise adjusting the flow rate of the production flow to raise the bottom hole pressure at or above a static pressure of a first influx zone to stop influx for the first zone. The method may comprise adjusting the flow rate of the production flow to raise the bottom hole pressure at or above a static pressure of a second influx zone to stop influx for the second influx zone. The method may comprise adjusting the flow rate of the production flow to raise the bottom hole pressure at or above a static pressure of each of a third or further zones to stop influx from the third or further zones.
The method may comprise adjusting the flow rate of the production flow to lower the bottom hole pressure below a static pressure of at least one or more zones to start influx for the at least one or more zones. The method may comprise adjusting the flow rate of the production flow to lower the bottom hole pressure below a static pressure of a first influx zone to start influx from the first zone. The method may comprise adjusting the flow rate of the production flow to lower the bottom hole pressure below static pressure of a second influx zone to start influx from the second influx zone. The method may comprise adjusting the flow rate of the production flow to lower the bottom hole pressure below a static pressure of each of a third or further zones to start influx from the third or further zones.
The method may comprise adjusting the production flow rate until at least one tracer is not detected in the at least one sample. The method may comprise decreasing the production flow rate until at least one tracer is not detected in the at least one sample.
The method may comprise estimating, calculating, determining and/or monitoring a static pressure of one or more zones by measuring and/or identifying the production flow rate where tracer from one or more zones is not present in the one or more samples and measuring and/or identifying the flowing bottom hole pressure at that flow rate.
The method may comprise estimating, calculating, determining and/or monitoring a static pressure of one or more zones of one or more laterals by measuring and/or identifying the production flow rate where tracer from one or more zones is not present in the one or more samples and measuring and/or identifying the flowing bottom hole pressure at that flow rate. The method may comprise estimating, calculating, determining and/or monitoring a static pressure of a first zone by measuring and/or identifying a first production flow rate where tracer from the first zone is not present in the one or more samples and measuring and/or identifying a first flowing bottom hole pressure at the first production flow rate. The first flowing bottom hole pressure may be equal to the static pressure of the first zone. The method may comprise estimating, calculating, determining and/or monitoring a static pressure of a second zone by measuring and/or identifying a second production flow rate where tracer from the second zone is not present in the one or more samples and measuring and/or identifying the flowing bottom hole pressure at the second flow rate. The second flowing bottom hole pressure may be equal to the static pressure of the second zone. The method may comprise estimating, calculating, determining and/or monitoring a static pressure of a third or further zone by measuring and/or identifying a third or further production flow rate where tracer from the third or further zone is not present in the one or more samples and measuring and/or identifying the flowing bottom hole pressure at the third or further flow rate. The third or further flowing bottom hole pressure may be equal to the static pressure of the third or further zone.
The method may comprise adjusting the rate until at least one tracer is first detected in the at least one sample. The method may comprise increasing the rate until at least one tracer is first detected in the at least one sample.
The method may comprise measuring and/or identifying a bottom hole pressure at a flow rate where there is only inflow from one zone and the corresponding tracer is the only tracer present in the one or more samples. The method may comprise measuring and/or identifying a flowing bottom hole pressure at a flow rate where there is only inflow from one zone and the corresponding tracer is the only tracer present in the one or more samples.
The method may comprise measuring and/or identifying a bottom hole pressure of each lateral at a flow rate where there is only inflow from one zone and the corresponding tracer is the only tracer present in the one or more samples. The method may comprise measuring and/or identifying a flowing bottom hole pressure of each lateral at a flow rate where there is only inflow from one zone and the corresponding tracer is the only tracer present in the one or more samples.
The method may comprise estimating, calculating, determining and/or monitoring a static pressure of a first zone by measuring and/or identifying a first production flow rate where tracer from the first zone first appears in the one or more samples and measuring and/or identifying a first flowing bottom hole pressure at the first production flow rate. The first flowing bottom hole pressure may be equal to the static pressure of the first zone.
The method may comprise estimating, calculating, determining and/or monitoring a static pressure of a second zone by measuring and/or identifying a second production flow rate where tracer from the second zone first appears in the one or more samples and measuring and/or identifying the flowing bottom hole pressure at the second flow rate. The second flowing bottom hole pressure may be equal to the static pressure of the second zone.
The method may comprise estimating, calculating, determining and/or monitoring a static pressure of a third or further zone by measuring and/or identifying a third or further production flow rate where tracer from the third or further zone is first detected in the one or more samples and measuring and/or identifying the flowing bottom hole pressure at the third or further flow rate. The third or further flowing bottom hole pressure may be equal to the static pressure of the third or further zone.
The method may comprise estimating, calculating and/or monitoring a composite productivity index for the zones of the well. The method may comprise calculating or estimating a productivity index for each zone.
The method may comprise analysing the at least one sample for type of tracer and/or concentration of tracer. The method may comprise detecting the presence or absence of the at least one tracer at a detection location. The method may comprise detecting the concentration of the tracer or each tracer at a detection location. The detection location may be a downhole location, a surface location, or at a location in a direction towards the surface of the production well.
The well may comprise two or more influx zones to a production well. The two or more influx zones may be from the same reservoir. The two or more influx zones may be from different layers of the same reservoir. The two or more influx zones may be from different reservoirs. The two or more influx zones may be from different layers of different reservoirs. The two or more influx zones may be from one or more laterals in the same wellbore. The two or more influx zones may be from one or more different laterals in the same layer of a reservoir. The two or more influx zones may be from one or more different laterals in one or more different layers of the same reservoir. The two or more influx zones may be from one or more different laterals from different reservoirs.
The method may comprise installing at least one tracer source with distinct tracer materials at each influx zone. The method may comprise installing at least one tracer source with distinct tracer materials in known levels of one or more laterals in the well; The method may comprise analysing the at least one sample for the presence or absence of the two or more tracers. Based on the tracer data identifying a bottom hole pressure where one or more influx zones start or stop flowing to a production well and determining a static pressure for the two or more influx zones. The method may comprise calculating contribution of flow from the two or more influx zones.
The at least one tracer source may be arranged downstream and exposed to the fluids in at least one of the influx zones. The at least one well fluid may be at least one of oil, gas and/or water. The method may comprise collecting, testing or measuring the at least one well fluid downstream of the influx locations such as at surface. The method may comprise measuring the flow rate of the production flow. The method may comprise measuring the flow rate of the production flow at surface.
By providing tracer sources at known positions in the well distinct tracer molecules may be accurately installed, located or positioned at upstream and/or downstream of each zone so that a distinct tracer can be released into each influx zone flow. The tracer sources may be installed by arranging, fixing and/or immobilising tracer sources in the well. The at least one tracer source may be installed at, downstream and/or upstream of each influx zone. The at least one tracer source may be installed adjacent to the influx zone.
The tracer material may be a passive tracer material configured to release tracer molecules when contacted by any type of well fluid from the influx zone. The tracer material may be a passive tracer material configured to release tracer molecules when contacted by any type of well fluid from the influx zone where the tracer source is installed, located and/or positioned. The tracer material may be configured to selectively release tracer molecules from the tracer material into a specific well fluid on contact with the particular well fluid. The tracer material may be designed to release tracer when the tracer material is exposed to a target fluid i.e. oil, gas or water. The tracer material may be a solid, liquid or gas. The tracer material may be selected from the group comprising chemical, fluorescent, phosphorescent, magnetic, DNA and radioactive compounds. The tracer material may comprise chemical tracers selected from the group comprising perfluorinated hydrocarbons or perfluoroethers. The perfluorinated hydrocarbons may be selected from the group of perfluoro buthane (PB), perfluoro methyl cyclopentane (PMCP), perfluoro methyl cyclohexane (PMCH).
The tracer material may comprise a tracer and a carrier. The carrier may be a matrix material. The matrix material may be a polymeric material. The tracer may be chemically immobilized within and/or to the carrier. The tracer material may be chemically immobilized by a chemical interaction between the tracer and the carrier. The tracer material may be chemically immobilized in a way that it releases tracer molecules or particles in the presence of a chemical trigger. The carrier may be a selected from poly methyl methacrylates (PMMA), poly methylcrylates, poly ethylenglycols (PEG), poly lactic acid (PLA) or poly glycolic acid (PGA) commercially available polymers or copolymers thereof.
The carrier may be selected from polymers with higher rates of tracer molecules release such as polyethylene and polypropylene. The tracer may be physically dispersed and/or physically encapsulated in the carrier. The tracer material may release tracer molecules into fluid by dissolution or degradation of the carrier and/or the tracer into the fluid. The carrier may be selected to controllable degrade on contact with a fluid. The carrier may be selected to degrade by hydrolysis of the carrier. The tracer and/or the carrier may be fluid specific such that the tracer molecules will be released from the tracer material as a response to a contact with a target liquid. By varying the chemical interaction between the tracer and the polymer the release mechanism and the rate of release of tracer molecules from the tracer material may be controlled. Preferably the tracer is released from the tracer carrier with an even release rate.
The tracers and/or the carrier may be chemically intelligent such that tracer molecules will be released from the tracer material as a response of specific events, e.g. they respond to an oil flow (oil-active) but show no response to a water flow (water-resistant). Another group of chemical compounds can be placed in the same region, which release tracers in water flow (water-active) but show no response to an oil flow (oil-resistant). The tracers and/or the carrier may be chemically intelligent such that tracer molecules will be released from the tracer material as a response the exposure of the tracer material to a well fluid and/or a target well fluid.
Release tracer molecules from the tracer sources may be detected and its concentration measured by different techniques such as optical detection, optical fibers, spectrophotometric methods, PCR techniques combined with sequential analysis, chromatographic methods, or radioactivity analysis. The invention is not restricted to the above-mentioned techniques. The tracer molecules may be detected and its concentration measured by sampling production fluid. The sampling may be conducted at the one or more of said sampling times. The sampling may be conducted downhole downstream of the tracer release apparatus or at surface. Samples may be collected for later analysis.
The tracer molecules may be detected by a detection device such a probe. The detection device may facilitate real time monitoring and/or analysis of the tracer in the production fluid.
The at least one tracer source may be retrofitted into an existing tubing. The at least one tracer source may be retrievable, installed, replaced and/or adjusted by wireline, slickline, coiled tubing, drill pipe or similar conveyance. The at least one source may be installed or replaced and may be conveyed through the production tubing by wireline, slickline, coiled tubing, drill pipe or similar conveyance. The at least one tracer source may be conveyed onto at least one landing nipple.
The method may comprise two or more tracer sources. The two or more tracer sources may be configured for connection to a production tubing at different positions along the production tubing. The tracer release apparatus may be positioned downstream of an influx zone at known locations in the well. Each tracer source may comprise a distinct tracer material. Each tracer release apparatus may be arranged at, downstream and/or upstream of a different influx zone and exposed to the fluids from influx zone.
The method may comprise inducing production at a two or more selected flow rates to allow flow to enter the production flow through each specific influx zones and carry the tracer located at that zone to propagate downstream with the production flow.
The method may comprise inducing a steady state flow. The method may comprise inducing a steady state flow condition in the production rate of the entire production flow or for at least one of the influx zones. The method may comprise adjusting the production flow to a different steady state flow.
The method may comprise identifying static pressure gradients along the well at one or more influx zones. The method may comprise mapping the static pressures for each influx zone. The method may comprise mapping the static pressures for each influx zone in each lateral of the well. The method may comprise mapping the static pressures for each lateral of the well. The method may comprise estimating, calculating, monitoring and/or determining water injection pressures and/or gas injection pressure that is required to maintain a pressure of the reservoir.
The method may comprise identifying crossflow in the well. The may comprise identifying one or more source zones of crossflow in the well. The may comprise identifying one or more destination zones of crossflow in the well. The method may comprise estimating, calculating, monitoring and/or determining conditions and/or flow rates for crossflow between zones.
The method may comprise analysing the static pressure gradients along the well to determine whether zones or layers of the reservoir are in hydraulic communication. The method may comprise analysing the static pressure gradients along or between laterals of well. The method may comprise analysing the static pressure gradients along the well to determine whether zones or layers of the reservoir are not in hydraulic communication. Determining whether the layer or zones of the reservoir are in hydraulic communication may assist in evaluating the economic value of infill injector wells to provide additional sweep of hydrocarbon in a layer or zone exhibiting a lower static pressure.
The method may comprise measuring, estimating, calculating, monitoring and/or determining the static pressure of one or more depleted zones or layer by conducting multi-rate flow testing. The method may comprise measuring, estimating, calculating, monitoring and/or determining the static pressure of one or more depleted zones in one or more laterals by conducting multi-rate flow testing. The method may comprise quantifying differential pressure depletion between two or more zones by conducting multi-rate flow testing. The method may comprise quantifying differential pressure depletion between two or more zones in different laterals by conducting multi-rate flow testing. The method may comprise assessing if there is depletion occurring in any lateral. The method may comprise assessing inflow contribution from one or more lateral.
The method may comprise estimating, calculating, monitoring and/or determining a static pressure for each zone. The method may comprise estimating, calculating, monitoring and/or determining a static pressure difference between two or more zones of a multilayer reservoir. The method may comprise estimating, calculating, monitoring and/or determining the static pressure of two or more influx zones of a multilateral well. The method may comprise estimating, calculating, monitoring and/or determining an influx profile for each zone and/or lateral in the well.
The method may comprise inferring information on the difference in the amount and/or volume of hydrocarbon in each zone based on the zonal static pressure data. The method may comprise inferring information on the amount and/or volume of hydrocarbon in each zone based on the zonal static pressure data. The method may comprise inferring information on the amount and/or volume of hydrocarbon in each lateral and/or zone of each lateral based on the zonal static pressure data. The method may comprise identifying depleted zones based on the zonal static pressure data. The method may comprise optimising future field development and production from selected zones based on the zonal static pressure data. The depletion status of at one or more zones may be inferred based on the static pressure of the one or more zones.
The method may comprise creating a reservoir model. The method may comprise tuning a reservoir model to match the production history of static pressure of at least one zone. The method may comprise providing an accurate model of producing zones with remaining hydrocarbon reserves. The method may comprise analysing the model data to assess the need, economic viability and/or location of additional infill drilling of additional production wells.
The method may be a computer-implemented method. The method may be a computer-implemented history matching method. The method may comprise storing the measurement data to a database. The method may comprise storing the model data to a database. The detection and/or analysis of tracer in production fluid may be a separate method to the release of tracer from the tracer source and/or the collection of one of more samples. Samples may be collected and the tracer detected at a time or jurisdiction which is separate and distinct from the location of well and therefore the collection of the samples.
According to a second aspect of the invention, there is provided a method of estimating static pressure of one or more influx zones or influx locations to a production well; wherein the well comprises tracer sources with distinct tracer materials in known levels of the well, the method comprises:
The method may comprise identifying at least one bottom hole pressure where one or more influx zones start or stop flowing to a production well. The method may comprise calculating, determining and/or monitoring static pressure of one or more influx zones to a production well.
The one or more influx zones may be from the same reservoir. The one or more influx zones may be from different layers of the same reservoir. The one or more influx zones may be from different reservoirs. The one or more influx zones may be from different layers of different reservoirs. The one or more influx zones may be from one or more laterals in the same wellbore. The one or more influx zones may be from one or more different laterals in the same layer of a reservoir. The one or more influx zones may be from one or more different laterals in one or more different layers of the same reservoir. The one or more influx zones may be from one or more different laterals from different reservoirs. The method may comprise arranging at least one tracer source with distinct tracer materials in known levels of one or more laterals in the well;
Embodiments of the second aspect of the invention may include one or more features of the first aspect of the invention or its embodiments, or vice versa.
According to a third aspect of the invention, there is provided a system for estimating static pressure of one or more influx zones or influx locations to a production well with one or more influx zones or influx locations to a production flow, the system comprising:
The sampling device may be configured to collect or take samples of well fluid downstream of a tracer release location. The sampling device may be configured to collect or take samples of well fluid downstream of the known level of the well. The sampling device may be configured to collect or take samples of the production flow. The sampling device may be configured to collect or take samples at one or more sampling times.
The sampling device may be configured to collect or take samples of well fluid at the surface or downhole. The sampling device may be configured to collect or take samples for further analysis onsite or offsite. The sampling device may be configured to detect the presence of one or more tracers. The sampling device may be configured to detect the presence of tracer one or more tracers in real time. The sampling device may be configured to measure the concentration of one or more tracers in the well fluid. The sampling device may be configured to measure the concentration of one or more tracers in the well fluid in real time.
The system may comprise a tracer analyser for analysing the type of tracer in the one or more samples. The system may comprise a tracer analyser for analysing the one or more tracer concentrations.
The system may comprise a processor. The processor may be configured to analyse the tracer data and the bottom hole pressure data. The processor may be configured to estimate, determine, calculate and/or monitor a static pressure for an influx zone based on the analysed tracer data and identifying a bottom hole pressure where the influx zone starts and/or stops flow to a production well. The processor may be configured to estimate, determine, calculate and/or monitor a static pressure for each influx zone based on the analysed tracer data and identifying the bottom hole pressures where each influx zone starts and/or stops flow to a production well. The processor may be configured to estimate, determine, calculate and/or monitor a static pressure for each influx zone in one or more laterals based on the analysed tracer data and identifying the bottom hole pressures of the one or more laterals where each influx zone starts and/or stops flow to a production well.
The one or more influx zones may be from the same reservoir. The one or more influx zones may be from different layers of the same reservoir. The one or more influx zones may be from different reservoirs. The one or more influx zones may be from different layers of different reservoirs. The one or more influx zones may be from one or more laterals in the same wellbore. The one or more influx zones may be from one or more different laterals in the same layer of a reservoir. The one or more influx zones may be from one or more different laterals in one or more different layers of the same reservoir. The one or more influx zones may be from one or more different laterals from different reservoirs. The method may comprise arranging at least one tracer source with distinct tracer materials in known levels of one or more laterals in the well;
The at least one tracer source may be configured to be installed in known levels of the well by arranging the tracer sources in the annulus, in or on the production tubing or other components of the completion. The at least one tracer source may be configured to be installed in known levels of one or more laterals in the well. The at least one tracer source may be configured to be arranged at, downstream or upstream of each influx zone. The at least one tracer source may be arranged adjacent to the influx zone. The tracer source may be located in a tracer release apparatus. The tracer source and/or tracer release apparatus may be arranged, installed and/or mounted at known locations near each influx location. The at least one tracer source and/or tracer release apparatus may be configured to hold the tracer material against the outside wall of the production tubing, in the annulus and/or against the formation.
The choke assembly may be configured to adjust the flow rate of the production flow to adjust the bottom hole pressure. The choke assembly may be configured to increase the flow rate of the production flow to decrease the bottom hole pressure. The choke assembly may be configured to decrease the flow rate of the production flow to increase the bottom hole pressure. The choke assembly may be configured to adjust the flow rate of the production flow to raise the bottom hole pressure above a static pressure of at least one or more zones to stop influx for the at least one or more zones. The choke assembly may be configured to adjust the flow rate of the production flow to raise the bottom hole pressure at or above a static pressure of a first influx zone to stop influx for the first zone. The choke assembly may be configured to adjust the flow rate of the production flow to raise the bottom hole pressure at or above a static pressure of a second influx zone to stop influx for the second influx zone. The choke assembly may be configured to adjust the flow rate of the production flow to raise the bottom hole pressure at or above a static pressure of each of a third or further zones to stop influx from the third or further zones. The choke assembly may be configured to adjust the flow rate of the production flow to lower the bottom hole pressure below a static pressure of at least one or more zones to start influx for the at least one or more zones. The choke assembly may be configured to adjust the flow rate of the production flow to lower the bottom hole pressure below a static pressure of a first influx zone to start influx from the first zone. The choke assembly may be configured to adjust the flow rate of the production flow to lower the bottom hole pressure below static pressure of a second influx zone to start influx from the second influx zone. The choke assembly may be configured to adjust the flow rate of the production flow to lower the bottom hole pressure below a static pressure of each of a third or further zones to start influx from the third or further zones.
Embodiments of the third aspect of the invention may include one or more features of the first or second aspect of the invention or its embodiments, or vice versa.
According to a fourth aspect of the invention, there is provided a system for estimating static pressure of one or more influx zones or influx locations to a production well with one or more influx zones or influx locations to a production flow, the system comprising:
The at least one probe device may be arranged in the production flow in the production tubing. The at least one probe may be located downhole or at surface. The at least one probe may be a sampling device, a detector probe and/or a real time detector probe.
The at least one probe device may be configured to detect the presence of one or more tracers. The at least one probe device may be configured to detect the presence of tracer one or more tracers in real time. The at least one probe device may be configured to measure the concentration of one or more tracers in the well fluid. The at least one probe device may be configured to measure the concentration of one or more tracers in the well fluid in real time.
Embodiments of the fourth aspect of the invention may include any of features of the first to third aspects of the invention or their embodiments, or vice versa.
According to a fifth aspect of the invention, there is provided a system for estimating an influx profile for at least one well fluid from a reservoir to a producing hydrocarbon well with two or more influx zones or influx locations to a production flow, the system comprising:
The system may comprise a tracer analyser for analysing samples for tracer type and/or tracer concentration from said possible sources. The tracer sources may be configured to release tracer into the well at an even release rate. The tracer sources may be configured to release tracer at a known release rate.
The system may be configured to estimate, calculate and/or monitor an influx profile for the two or more influx zones or influx locations to a production flow. The system may be configured to estimate, calculate and/or monitor an influx profile for one or more laterals. The system may be configured to estimate, calculate and/or monitor an influx profile for two or more influx zones in one or more laterals. The system may be configured for estimating an influx profile for each lateral. The system may be configured to estimate, calculate and/or monitor an influx profile for two or more influx zones in each lateral.
Embodiments of the fifth aspect of the invention may include any of features of the first to fourth aspects of the invention or their embodiments, or vice versa.
According to a sixth aspect of the invention, there is provided a method of estimating an influx profile for at least one well fluid from a reservoir to a producing hydrocarbon well with two or more influx zones to a production flow;
The method may comprise identifying at least one bottom hole pressure where one or more influx zones start or stop flowing to a production well.
The method may comprise estimating, calculating and/or monitoring a composite productivity index for the two or more zones of the well. The method may comprise estimating, calculating and/or monitoring a productivity index for each zone. The method may comprise estimating, calculating and/or monitoring a productivity index for each lateral. The method may comprise estimating, calculating, monitoring and/or assuming a distributed productivity index for each zone. The method may comprise estimating, calculating, monitoring and/or assuming a distributed productivity index for each lateral.
The method may comprise creating a model of the well. The model of the well may comprise parameter selected from the group comprising: zone location, lateral information, production flow rate, productivity index for the well, productivity index for each zone, static pressure of each zone, flowing bottom hole pressure, pressure difference between static pressure of each zone and flowing bottom hole pressure, total influx volume of the well, influx volume of each zone, petrophysical data of the well and/or core data of the well.
The method may comprise tuning the model. The method may comprise comparing modelled total influx volume of the well with measured total influx volume of the well for a known flow rate.
The method may comprise comparing modelled static pressure of one or more zone with measured static pressure of one or more zone for a known flow rate. The method may comprise comparing adjusting one or more parameters until the modelled total influx volume of the well matches with measured total influx volume of the well for a known flow rate. The method may comprise comparing adjusting one or more parameters until the modelled total influx volume of the well matches with measured total influx volume of the well for a known flow rate. The method may comprise comparing adjusting one or more parameters until the modelled total influx volume of the well matches with measured total influx volume of the well for a known flow rate.
Embodiments of the sixth aspect of the invention may include one or more of any of features of the first to fifth aspects of the invention or their embodiments, or vice versa.
According to a seventh aspect of the invention, there is provided a method of estimating an influx profile for at least one well fluid from a reservoir to a producing hydrocarbon well with two or more influx zones to a production flow;
The method may comprise identifying at least one bottom hole pressure where one or more influx zones start or stop flowing to a production well.
The method may comprise measuring a bottom hole pressure for each lateral at each flow rate. The method may comprise estimating, calculating, monitoring and/or determining a static pressure for each influx zone in one or more laterals based on the analysed tracer data.
Embodiments of the seventh aspect of the invention may include one or more of any of features of the first to sixth aspects of the invention or their embodiments, or vice versa.
According to an eighth aspect of the invention there is provided a method of collecting samples for later analysis in estimating an influx profile for at least one well fluid from a reservoir to a producing hydrocarbon well with two or more influx zones to a production flow; wherein the well comprises distinctive tracer sources installed, positioned or placed at the two or more influx zones; the method comprises;
The method may comprise measuring a bottom hole pressure for each flow rate. The method may comprise measuring a flowing bottom hole pressure for each flow rate.
Embodiments of the eighth aspect of the invention may include one or more of any of features of the first to seventh aspects of the invention or their embodiments, or vice versa.
According to a ninth aspect of the invention there is provided a method of estimating an influx profile for at least one well fluid from a reservoir to a producing hydrocarbon well with two or more influx zones or influx locations to a production flow;
The method may comprise estimating, calculating, determining and/or monitoring the contribution of flow from the two or more influx zones. The method may comprise estimating, calculating, determining and/or monitoring the contribution of flow from zones in two or more laterals. The method may comprise estimating, calculating, determining and/or monitoring the contribution of flow from two or more laterals.
The method may comprise analysing samples collected during a first steady state flow in the production rate of the entire production flow or for at least one of the influx zones. The method may comprise analysing samples collected during a second or further steady state flow in the production rate of the entire production flow or for at least one of the influx zones.
Embodiments of the ninth aspect of the invention may include one or more features of the first to eighth aspects of the invention or their embodiments, or vice versa.
According to a tenth aspect of the invention there is provided a method of estimating an influx profile for at least one well fluid to a producing hydrocarbon well with two or more influx zones to a production flow, wherein the well comprises distinctive tracer sources installed, positioned or placed at each of the two or more influx zones in known levels of the well; the method comprising the steps of:
The two or more influx zones may be from the same reservoir. The two or more influx zones may be from different layers of the same reservoir. The two or more influx zones may be from different reservoirs. The two or more influx zones may be from different layers of different reservoirs. The two or more influx zones may be from one or more laterals in the same wellbore. The two or more influx zones may be from one or more different laterals in the same layer of a reservoir. The two or more influx zones may be from one or more different laterals in one or more different layers of the same reservoir. The two or more influx zones may be from one or more different laterals from different reservoirs.
The method may comprise estimating, calculating and/or monitoring a composite productivity index for the zones of the well. The method may comprise estimating, calculating and/or monitoring a productivity index for each zone. The method may comprise estimating, calculating, monitoring and/or assuming a distributed productivity index for each zone. The method may comprise creating a model of the well. The model of the well may comprise one or more parameter selected from the group comprising zone location, production flow rate, productivity index for the well, productivity index for each zone, static pressure of each zone, flowing bottom hole pressure, pressure difference between static pressure of each zone and flowing bottom hole pressure, total influx volume of the well, influx volume of each zone, petrophysical data of the well and/or core data of the well.
The method may comprise tuning the model. The method may comprise comparing modelled total influx volume of the well with measured total influx volume of the well for a known flow rate.
The method may comprise comparing modelled static pressure of one or more zone with measured static pressure of one or more zone for a known flow rate. The method may comprise comparing adjusting one or more parameters until the modelled total influx volume of the well matches with measured total influx volume of the well for a known flow rate. The method may comprise comparing adjusting one or more parameters until the modelled total influx volume of the well matches with measured total influx volume of the well for a known flow rate. The method may comprise comparing adjusting one or more parameters until the modelled total influx volume of the well matches with measured total influx volume of the well for a known flow rate. The method may comprise adjusting one or more parameters until the modelled data best fits the measured data.
Embodiments of the tenth aspect of the invention may include one or more features of the first to ninth aspects of the invention or their embodiments, or vice versa.
According to an eleventh aspect of the invention there is provided a method for improving the accuracy of a reservoir model estimating an influx profile for at least one well fluid to a producing hydrocarbon well with two or more influx zones to a production flow, the method comprising:
The model of the well may comprise one or more parameters selected from the group comprising zone location, lateral information, production flow rate, productivity index for the well, productivity index for each zone, static pressure of each zone, flowing bottom hole pressure, pressure difference between static pressure of each zone and flowing bottom hole pressure, total influx volume of the well, influx volume of each zone, petrophysical data of the well and/or core data of the well.
The method may comprise tuning the model. The method may comprise comparing modelled total influx volume of the well with measured total influx volume of the well for a known flow rate.
The method may comprise comparing modelled static pressure of one or more zone with measured static pressure of one or more zone for a known flow rate. The method may comprise comparing adjusting one or more parameters until the modelled total influx volume of the well matches with measured total influx volume of the well for a known flow rate. The method may comprise comparing adjusting one or more parameters until the modelled total influx volume of the well matches with measured total influx volume of the well for a known flow rate. The method may comprise comparing adjusting one or more parameters until the modelled total influx volume of the well matches with measured total influx volume of the well for a known flow rate.
Embodiments of the eleventh aspect of the invention may include one or more features of the first to tenth aspects of the invention or their embodiments, or vice versa.
There will now be described, by way of example only, various embodiments of the invention with reference to the following drawings (like reference numerals referring to like features) in which:
In this example, there are two layers 13a, 13b in the reservoir each with an influx zone location 14a, 14b to the well. Two tracer sources 16a, 16b each with a distinct tracer material for each influx location are installed near each influx location. However, there may be a different number of influx zone locations and/or tracer release apparatus than illustrated in
The choke 15 is adjusted to control the flow rate and pressure to a selected choke flow rate and pressure level. A pressure measurement apparatus 18 is located downhole to measure bottom hole pressures. At the selected choke setting the bottom hole pressure data and flow rate is collected and associated with the specific choke setting.
Produced fluid from the layers 13a, 13b pass through their respective influx zone 14a, 14b and pass their respective tracer sources 16a, 16b. The released tracer is carried to the surface where samples of fluid are taken. The samples are analysed to detect the presence of the tracer and/or the concentration of tracer. The choke is adjusted to one or more further choke setting to adjust the flow rate and pressure level. The bottom hole pressure data, flow rate data and tracer release data is collected for each choke setting.
The results from the multiple rating testing method is used to determine the pressure level where the flowing bottom hole pressure (FBHP) level has increased to a value above the static reservoir pressure of one of the zones 14a, 14b, where the zone stops flowing as identified by the corresponding tracer not detected in the collected fluid samples.
In this example, influx zone 2 (14b) stops flowing at 4000 psi and the static bottom hole pressure (SBHP) before starting the test was 5000 psi. The drawdown in influx zone 1 (14a) at the time zone 2 is not flowing is therefore 1,000 psi. Assuming the well was flowing 1000 bpd at this point, the productivity index (PI) of zone 1 is equal to 1. Increasing the drawdown to 2000 psi (3000 psi FBHP) and assuming the PI of zone 1 remains equal to 1, the influx contribution from zone 1 would be 2,000 bpd. If the measured total flow at the surface is 2,500 bpd, it can be determined that influx contribution from zone 2 is 500 bpd. The PI of zone 2 can be determined based on a 1,000 psi drawdown and contributing 500 bpd, therefore the PI of zone 2 is equal to 0.5
A choke 115 in the well was actuated to change the flow rate three times over a two day period. Produced fluid samples were collected at the surface at regular intervals and analysed for each of the tracers.
The tracer data shows that flow from Zone 1 and Zone 2 ceases when flowing BHP is increased to the value associated with 6,000 bpd. This may allow the identification of static reservoir pressure of specific zones and quantifying the differential pressure depletion between reservoir segments by conducting multi-rate flow testing.
In this example, there are four layers or zones 213a, 213b, 213c, 213d in the reservoir each with an influx zone location 214a, 214b, 214c and 214d to the well. Four tracer sources 216a, 216b, 216c and 216d each with a distinct tracer material for each influx location are installed near each influx location. However, there may be a different number of influx zones and/or tracer release apparatus than illustrated in
Arrows in the examples below denote the direction of fluid travel. The choke 215 is adjusted to control the flow rate and pressure to a selected choke flow rate and pressure level. At the selected choke setting the bottom hole pressure data and flow rate is collected and associated with the specific choke setting.
Produced fluid from the layers 213a, 213b, 213c, 213d pass through the influx zones 214a, 214b, 214c, 214d and pass their respective tracer source 216a, 216b, 216c, 216d releasing tracer which is carried to the surface where samples of fluid are taken. The samples are analysed to detect the presence of the tracer and/or the concentration of tracer.
The choke 215 is adjusted to one or more further choke settings to adjust the flow rate and pressure level. The bottom hole pressure data, flow rate data and tracer release data is collected for each choke setting.
The results from the multiple rating testing method is used to determine the pressure level where the flowing bottom hole pressure (FBHP) level has increased to a value above the static reservoir pressure of one of the zones 214a, 214b, 214c, 214d where the zone stops flowing.
In this scenario of four separate zones that are named Zone A (214a), B (214b), C (214c) and D (214d) with the following determined properties shown in Table 1
Table 1 shows Static Reservoir Pressure and PI values for each zone.
The reservoir 213 having four zones 214a, 214b, 214c, 214d with the static reservoir pressure value and PI parameters in Table 1 would yield a multi-rate profile of as shown in
However, using the tracer data, the static pressures of each of the zones can be determined by analysing the collecting samples at each flow rate and determining when the tracer located at a particular zone stops being released which corresponds with the flow stopping at that particular zone.
In this example, the graph in
Table 2 shows zonal differential pressures and flow rates.
Table 2 shows the differential pressure between Static Reservoir Pressure for each zone and the flowing bottom hole pressure (FBHP). Table 2 also shows expected influx rate Q at each zone. It would appear from the pressure measurement apparatus 218 that the static BHP of Zone A is equal to 9,125 PSI. It would be known from the multi-rate test that the composite PI for all of the zones equals 4. The distribution of the total PI to the individual zones would be based on petrophysical and/or core data.
Additional guidance on the distribution of the measured total PI to the individual layers can be obtained by modeling the multi-rate profile generated from the PI assumptions to the measured multi-rate profile.
As an example, the PI assumptions in Table 2 were modeled to create a predicted curve shown in
In Table 3 below is an inflow distribution for reservoir 213 which would be inferred from the tracer data, zonal pressures and PI distribution if BHP is reduced to 6,000 PSI.
Table 3 shows inflow distribution for reservoir at flowing BHP of 6000 PSI
A model has been created that predicts the inflow distribution across the entire reservoir interval as a function of the flowing BHP.
At a flowing BHP of 6000 PSI, it is observed that the model predicts a total production volume of 10,750 bpd. However, the measured total production volume of the well at flowing BHP 6000 PSI is 12,500 BPD.
It is known from Table 2 that the static BHP measured when the well is not flowing to the surface is not the true BHP of the highest pressured zone as Zone A produces flow to the lower pressure zones. Based on this information, the Pstatic value of Zone A would be increased as shown in Table 4 until the modelled total production volume matches the measured total production volume Q at a flowing BHP 6,000 psi, which in this case Zone A is 10,000 PSI.
Table 4 Adjusted Inflow distribution based on measured volume data for reservoir at flowing BHP of 6000 PSI.
The method may provide a relationship of the flowing bottom hole pressure vs flow rate to generate an Inflow Performance Relationship (IPR) curve. The IPR curve in layered systems may be a composite result of the inflow from all layers and by itself does not provide insight into the relative contribution from each layer. Using tracers positioned at each layer may allow determination of which zones are producing and under which conditions. The tracer data and zonal static pressure data can be combined and through an iterative process, insight can be gained into the inflow distribution from each layer.
The invention may provide a method and system of estimating a static pressure of one or more influx zones to a production well. The method comprises arranging at least one tracer source with distinct tracer materials in known levels of the well; inducing production flow in the production well for at least two different flow rates and collecting at least one sample downstream of the one or more influx zones for each flow rate. The method comprises measuring a bottom hole pressure for each flow rate, analysing at least one sample for the presence or absence of tracer and based on the tracer data identifying a bottom hole pressure where one or more influx zones start or stop flowing to a production well estimating a static pressure for the one or more influx zones.
Embodiments of the invention may facilitate assessment of depletion occurring in any influx zone, layer and/or laterals. Embodiments of the invention may also facilitate assessment of inflow contribution from one or more zones, one or more layers and/or one or more laterals.
Throughout the specification, unless the context demands otherwise, the terms ‘comprise’ or ‘include’, or variations such as ‘comprises’ or ‘comprising’, ‘includes’ or ‘including’ will be understood to imply the inclusion of a stated integer or group of integers, but not the exclusion of any other integer or group of integers. Furthermore, relative terms such as “up”, “down”, “top”, “bottom”, “upper”, “lower”, “upward”, “downward”, “horizontal”, “vertical”, “and the like are used herein to indicate directions and locations as they apply to the appended drawings and will not be construed as limiting the invention and features thereof to particular arrangements or orientations.
The foregoing description of the invention has been presented for the purposes of illustration and description and is not intended to be exhaustive or to limit the invention to the precise form disclosed. The described embodiments were chosen and described in order to best explain the principles of the invention and its practical application to thereby enable others skilled in the art to best utilise the invention in various embodiments and with various modifications as are suited to the particular use contemplated. Therefore, further modifications or improvements may be incorporated without departing from the scope of the invention as defined by the appended claims.
