WO2013092909A1 - Estimation de débits de multiples couches de réservoir d'hydrocarbure dans un puits de production - Google Patents

Estimation de débits de multiples couches de réservoir d'hydrocarbure dans un puits de production Download PDF

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Publication number
WO2013092909A1
WO2013092909A1 PCT/EP2012/076479 EP2012076479W WO2013092909A1 WO 2013092909 A1 WO2013092909 A1 WO 2013092909A1 EP 2012076479 W EP2012076479 W EP 2012076479W WO 2013092909 A1 WO2013092909 A1 WO 2013092909A1
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WIPO (PCT)
Prior art keywords
annulus
fluid
temperature
inflow location
inflow
Prior art date
Application number
PCT/EP2012/076479
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English (en)
Inventor
Andrew W. Woods
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Bp Exploration Operating Company Limited
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Publication date
Application filed by Bp Exploration Operating Company Limited filed Critical Bp Exploration Operating Company Limited
Priority to US14/366,939 priority Critical patent/US20140365130A1/en
Priority to GB1410602.5A priority patent/GB2511019A/en
Publication of WO2013092909A1 publication Critical patent/WO2013092909A1/fr
Priority to NO20140899A priority patent/NO20140899A1/no

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Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/68—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using thermal effects
    • G01F1/684—Structural arrangements; Mounting of elements, e.g. in relation to fluid flow
    • G01F1/688—Structural arrangements; Mounting of elements, e.g. in relation to fluid flow using a particular type of heating, cooling or sensing element
    • G01F1/6884—Structural arrangements; Mounting of elements, e.g. in relation to fluid flow using a particular type of heating, cooling or sensing element making use of temperature dependence of optical properties
    • 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
    • E21B47/02—Determining slope or direction
    • E21B47/026—Determining slope or direction of penetrated ground layers
    • 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
    • E21B47/07—Temperature
    • 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
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E21B47/103—Locating fluid leaks, intrusions or movements using thermal measurements
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/704—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow using marked regions or existing inhomogeneities within the fluid stream, e.g. statistically occurring variations in a fluid parameter
    • G01F1/7044—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow using marked regions or existing inhomogeneities within the fluid stream, e.g. statistically occurring variations in a fluid parameter using thermal tracers
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/704—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow using marked regions or existing inhomogeneities within the fluid stream, e.g. statistically occurring variations in a fluid parameter
    • G01F1/708—Measuring the time taken to traverse a fixed distance
    • G01F1/7084—Measuring the time taken to traverse a fixed distance using thermal detecting arrangements
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/74—Devices for measuring flow of a fluid or flow of a fluent solid material in suspension in another fluid

Definitions

  • the following describes systems and methods for estimating flow of fluid in a production well, and in particular for estimating flow based on temperature.
  • Reservoirs in particular hydrocarbon bearing reservoirs typically contain fluids such as oil, gas and water in layers of permeable reservoir rock. These layers may be separate, or partially interconnected, which is to say that the fluids may flow between layers at only a limited number of points.
  • the layers may have different characteristics, such as permeability of the reservoir rock and viscosity of the fluid, and consequently fluid may flow along each layer at a different rate.
  • waterflooding or similar secondary recovery techniques may be used to force additional fluid (hydrocarbons) out of the reservoirs.
  • hydrocarbons additional fluid
  • the effectiveness of these techniques is diminished if the flood water passes along a layer that is relatively more permeable than the layer occupied by the hydrocarbons.
  • EOR Enhanced oil recovery
  • These techniques include injecting aqueous solutions of polymers such as viscosifiers into the well to partially or fully block a higher permeability layer, and thereby enhance the recovery of hydrocarbons from the less permeable layers.
  • polymers such as viscosifiers
  • polymeric microparticles having labile (reversible) and non-labile internal cross links in which the microparticle conformation is constrained by the labile internal cross links may be used.
  • the microparticle properties, such as particle size distribution and density, of the constrained microparticle are designed to allow efficient propagation through the pore structure of hydrocarbon reservoir matrix rock, such as sandstone.
  • the labile internal cross links On heating to reservoir temperature and/or at a predetermined pH, the labile internal cross links start to break allowing the particles to expand by absorbing the injection fluid (normally water).
  • the expanded particle is engineered to have a particle size distribution and physical characteristics which allow it to impede the flow of injected fluid in the pore structure of the high permeability reservoir layer. In doing so it is capable of diverting subsequently injected fluid into less thoroughly swept zones of the reservoir.
  • Prior methods involve providing flow meters at a number of points in the production well.
  • a sensor can be lowered into a production well to measure flow at different points.
  • methods, devices, systems and software are provided for supporting or implementing functionality to estimate the flow of fluid into a production well and to estimate the tilt of a reservoir.
  • a computer-implemented method for estimating flow of fluid into a production well extending into a reservoir comprising fluid the well comprising a central tubing and an annulus surrounding the central tubing, the annulus being connected to the reservoir so as to receive fluid at one or more inflow locations, and the central tubing having at least one inlet, arranged to allow fluid to flow from the annulus into the central tubing, and being located downstream of the one or more inflow locations, the production well further comprising one or more devices arranged to measure a temperature of fluid within the annulus at a plurality of points along the length of the annulus, the method comprising: receiving temperature data from the one or more devices indicative of a temperature of fluid at a plurality of points along the length of the annulus; identifying a change in temperature of fluid flowing within the annulus on the basis of the received temperature data at the plurality of points; using a model to estimate heat transfer from the central tubing to fluid flowing within the annulus, said model being configured such that the heat transfer is assumed
  • a computer readable storage medium storing computer readable instructions thereon for execution on a computing system to implement a method for estimating flow of fluid into a production well extending into a reservoir comprising fluid, the well comprising a central tubing and an annulus surrounding the central tubing, the annulus being connected to the reservoir so as to receive fluid at one or more inflow locations, and the central tubing having at least one inlet, arranged to allow fluid to flow from the annulus into the central tubing, and being located downstream of the one or more inflow locations, the production well further comprising one or more devices arranged to measure a temperature of fluid within the annulus at a plurality of points along the length of the annulus, the set of instructions being configured to cause the computing system to perform the steps of: receiving temperature data from the one or more devices indicative of a temperature of fluid at a plurality of points along the length of the annulus; identifying a change in temperature of fluid flowing within the annulus on the basis of the received temperature data at the plurality of points; using
  • a system for estimating flow of fluid into a production well extending into a reservoir comprising fluid
  • the well comprising a central tubing and an annulus surrounding the central tubing, the annulus being connected to the reservoir so as to receive fluid at one or more inflow locations, and the central tubing having at least one inlet, arranged to allow fluid to flow from the annulus into the central tubing, and being located downstream of the one or more inflow locations
  • the production well further comprising one or more devices arranged to measure a temperature of fluid within the annulus at a plurality of points along the length of the annulus
  • the system comprising: an interface arranged to receive temperature data, the temperature data having being collected by the one or more devices and being indicative of a temperature of fluid at a plurality of points along the length of the annulus; and a processor arranged to: identify a change in temperature of fluid flowing within the annulus on the basis of the received temperature data at the plurality of points; execute a model to estimate heat transfer from the central tubing to fluid flowing
  • Figure 1 shows a schematic diagram of an oil recovery system and a reservoir in respect of which embodiments are applicable;
  • Figure 2 shows schematic diagram of a section of a production well
  • Figure 3 shows schematic diagram of a section of a production well
  • Figure 4 shows schematic diagram of a processing system in which embodiments may operate
  • Figure 5 shows a computer implemented method of estimating flow into a production well
  • Figure 6 shows a plot of temperature evolution over time
  • Figure 7 shows a computer implemented method of estimating tilt of a reservoir
  • Figure 8 shows a schematic diagram of well locations in a reservoir in which embodiments may be used.
  • a computer-implemented method for estimating flow of fluid into a production well extending into a reservoir comprising fluid the well comprising a central tubing and an annulus surrounding the central tubing, the annulus being connected to the reservoir so as to receive fluid at one or more inflow locations, and the central tubing having at least one inlet, arranged to allow fluid to flow from the annulus into the central tubing, and being located downstream of the one or more inflow locations, the production well further comprising one or more devices arranged to measure a temperature of fluid within the annulus at a plurality of points along the length of the annulus, the method comprising: receiving temperature data from the one or more devices indicative of a temperature of fluid at a plurality of points along the length of the annulus; identifying a change in temperature of fluid flowing within the annulus on the basis of the received temperature data at the plurality of points; using a model to estimate heat transfer from the central tubing to fluid flowing within the annulus, said model being configured such that the heat transfer is assumed
  • a production well will generally receive fluid (i.e. water, oil and/or gas) from the well at a number of discrete locations along the length of the well bore. These locations may be defined by fissures in the underlying rock which serve to transport the fluid towards the well. Fluid will flow from the fissures into the annulus. Within the annulus the fluid from one fissure may mix with fluid from other fissures, and will flow 'downstream' along the annulus (downstream meaning towards the surface). The fluid then flows from the annulus to the central tubing at one or more inlet points. The fluid will subsequently flow downstream along the central tubing to the surface.
  • fluid i.e. water, oil and/or gas
  • DTS downhole temperature sensors
  • the fluid within the central tubing will be warmer than the fluid within the annulus, having originated from a deeper point in the reservoir.
  • This temperature gradient causes heat to flow from the central tubing to the fluid in the annulus.
  • embodiments are able to estimate a flow rate of fluid along the annulus at the point, as the change in temperature will be greater when the flow rate along the annulus is lower, and correspondingly less when the flow rate along the annulus is greater. Therefore, such embodiments are able to estimate a rate at which fluid flows into the annulus at a said inflow location from the change in temperature between the point and the estimated heat transfer.
  • embodiments are able to estimate the flow of fluids into a well using a relatively simple measuring system (the temperature sensor).
  • the method may comprise using the model to determine a specific heat capacity of the fluid and thence estimating a composition of the fluid flowing from the reservoir into the annulus at the first inflow location.
  • the composition of the fluid may vary during the lifetime of the well. Equally, the composition of the fluid may change between layers.
  • the composition of the fluid will affect the specific heat capacity of the fluid, and consequently the temperature changes. Therefore, by looking at how temperatures change, the composition of the fluid flowing into and along the well can be estimated, and thus provide data which may be used to increase the efficiency of extraction of fluid from the well.
  • the method may comprise: using the model to estimate a rate at which the fluid flows along the longitudinal axis of the annulus, whereby to estimate a rate at which fluid flows into the annulus at the first inflow location.
  • the method may comprise: identifying a temperature of fluid within the central tubing; and determining a temperature gradient between the fluid within the central tubing and the fluid within the annulus, whereby to estimate heat transfer from the central tubing to fluid flowing within the annulus.
  • the fluid in the central tubing and in the annulus will be at different temperatures, typically, the central tubing, in carrying fluid from lower down the well, will be at a higher temperature.
  • the central tubing will warm the fluid in the annulus as the fluid passes along the annulus.
  • the rate of flow along the annulus can be estimated.
  • identifying the temperature of the central tubing a more accurate estimate can be made.
  • the temperature of the fluid in the central tubing may be identified by direct measurement, i.e. by using a further downhole temperature sensor, or by inserting a probe into the central tubing at certain intervals.
  • direct measurement i.e. by using a further downhole temperature sensor, or by inserting a probe into the central tubing at certain intervals.
  • the temperature may be estimated based on temperature measurements taken in parts of the annulus upstream of the point in question. The fluid in these parts of the annulus will be assumed to have passed into the annulus at an inlet positioned upstream of the point in question.
  • the method may comprise identifying a change in temperature of fluid within the annulus between a point upstream of the first inflow location and a point downstream of the first inflow location; using a further model to estimate a change in temperature of the fluid in the annulus caused by fluid entering the annulus from the reservoir at the first inflow location; estimating a rate at which fluid flows into the annulus at the first inflow location on the basis of the identified change in temperature and the estimated change in temperature.
  • the method may comprise identifying a geothermal temperature at a depth corresponding to the first inflow location, whereby to estimate a temperature of fluid flowing into the annulus at the first inflow location, wherein the further model is configured to estimate the change in temperature of the fluid in the annulus based on the temperature of the fluid entering the annulus at the inflow location.
  • the fluid flowing from the reservoir will be at the geothermal temperature corresponding to the depth of the inflow location (within a given error margin). This geothermal temperature will be known from surveys etc.
  • the fluid In entering the annulus, the fluid will change the temperature of the fluid in the annulus, either by mixing with a flow of fluid within the annulus, or by displacing a stagnant portion of fluid.
  • the rate of flow of fluid into the annulus may be estimated using knowledge of the temperature of the fluid entering the annulus and from the temperature change in the fluid in the annulus.
  • the further model may be configured: such that fluid flowing within the annulus is assumed to mix with fluid entering the annulus at the first inflow location, and to associate the change in temperature of the fluid within the annulus with a rate of flow and a temperature of fluid flowing within the annulus upstream of the first inflow location and a rate of flow and a temperature of fluid flowing into the annulus at the first inflow location.
  • the method may comprise using a yet further model to estimate a change in temperature of fluid flowing into the annulus at the first inflow location, the yet further model taking account of Joule-Thompson expansion of fluid flowing into the annulus at the first inflow location.
  • One advantageous method by which the flow rate can be estimated is by looking at the Joule-Thompson effect on the fluid as it flows from the reservoir into the annulus. Joule-Thompson effect will change the temperature of the fluid, and thus enable the flow rate to be estimated.
  • the method may comprise using a said model to refine an estimate of a rate at which fluid flows into the annulus at the first inflow location generated by a further said model.
  • the method may comprise using a said model and/or a said further model whereby to estimate a rate at which fluid flows into the annulus at one or more second inflow locations.
  • the method may comprise using the model and/or further model used to estimate a rate at which fluid flows into the annulus at one or more second inflow locations whereby to refine the estimate of the rate at which fluid flows into the annulus at the first inflow location.
  • the rate at which fluid flows into the annulus at a given inflow location may affect the changes in temperature at locations downstream of the given inflow location.
  • an improved estimated of the rate at which fluid flows into the annulus at the first inflow location may be made by using further models used to estimate the rate at which fluid flows into the annulus at one or more second inflow locations.
  • the method may comprise estimating a set of values for rates at which fluid flows into the annulus at the first inflow location, each value being associated with data indicative of a composition of the fluid flowing into the annulus at the first inflow location.
  • a set of values for rates at which fluid flows into the annulus may be estimated, each value being associated with data indicative of a composition of the fluid flowing into the annulus at the first inflow location.
  • some of the values in this set may be subsequently excluded to refine the set.
  • the process may be iterative, that is, as more data is received, and more temperature changes identified, the sets may be progressively improved.
  • the annulus may be divided into a plurality of sections, each section having one or more inflow locations, and the central tubing has an inlet open to the annulus and located at the downstream end of each section
  • the method may comprise: estimating flow rates of fluid from the reservoir into a first said section; estimating a flow rate of fluid from the first section into the central tubing through a first said inlet from the flow rates of fluid from the reservoir into the first section; estimating a flow rate of fluid within the central tubing downstream of the first section based on the estimated flow rate of the fluid through the first inlet from the first section; estimating flow rates of fluid within a second said section using the estimated flow rate of fluid within the central tubing.
  • the annulus is divided up into sections.
  • fluid cannot pass from one section to the other, e.g. the sections are isolated (it will be understood that a small amount of fluid may pass the separations).
  • each section may be analysed substantially independently.
  • a determined flow rate in one section may be used to determine a flow rate along the central tubing, and thus in the
  • the process of estimating the flow rates starts with the section located at the upstream end of the well (e.g. at the deepest point), and result for each section is used in subsequent sections.
  • the method may comprise receiving data indicative or one or more of measurements of the temperature, composition and rate of flow of fluid in the central tubing, and using the measurement data to validate data generated by the models.
  • the temperature, composition and flow rate of fluid in the central tubing may be measured. This may be done at the surface, by taking a sample of the fluid produced by the well. The measured data may be used to estimate the flow rate in the production well. In some embodiments, such measured data may be used to modify a set of flow rate values to improve accuracy.
  • the method may comprise: receiving temperature data for fluid flowing into the annulus at the first inflow location at a plurality of points in time; and identifying a change over time in a temperature of the fluid flowing into the annulus at the first inflow location.
  • the method may comprise: identifying a flow rate of fluid entering the production well at the first inflow location at each of the plurality of points in time; identifying a geothermal gradient indicative of a change with depth in temperature of rock within and surrounding the reservoir; and determining a measure of the tilt of a layer of the reservoir based on the change over time in the temperature, geothermal gradient and flow rate.
  • the temperature of the fluid entering the well may change.
  • changes in temperature may be identified.
  • These temperature changes may be used to determine information about the reservoir.
  • the tilt of the reservoir may be determined form the evolution of the fluid temperature over time.
  • the 'tilt' of the reservoir indicates that the depth of the reservoir is not constant.
  • the temperature evolution is therefore caused by fluid passing along the reservoir from a deeper or shallower point to the inflow location.
  • the evolution may take many days, and possibly years, as the fluid takes time to flow to the inflow location.
  • the tilt of the reservoir can be determined, and thus the modelling and mapping of the reservoir may be improved.
  • a computer readable storage medium storing computer readable instructions thereon for execution on a computing system to implement a method for estimating flow of fluid into a production well extending into a reservoir comprising fluid, the well comprising a central tubing and an annulus surrounding the central tubing, the annulus being connected to the reservoir so as to receive fluid at one or more inflow locations, and the central tubing having at least one inlet, arranged to allow fluid to flow from the annulus into the central tubing, and being located downstream of the one or more inflow locations, the production well further comprising one or more devices arranged to measure a temperature of fluid within the annulus at a plurality of points along the length of the annulus, the set of instructions being configured to cause the computing system to perform the steps of: receiving temperature data from the one or more devices indicative of a temperature of fluid at a plurality of points along the length of the annulus; identifying a change in temperature of fluid flowing within the annulus on the basis of the received temperature data at the plurality of points; using
  • the set of instructions may be configured to cause the computing system to use the model to determine a specific heat capacity of the fluid and thence estimate a composition of the fluid flowing from the reservoir into the annulus at the first inflow location.
  • the set of instructions may be configured to cause the computing system to: use the model to estimate a rate at which the fluid flows along the longitudinal axis of the annulus, whereby to estimate a rate at which fluid flows into the annulus at the first inflow location.
  • the set of instructions may be configured to cause the computing system to: identify a change in temperature of fluid within the annulus between a point upstream of the first inflow location and a point downstream of the first inflow location; use a further model to estimate a change in temperature of the fluid in the annulus caused by fluid entering the annulus from the reservoir at the first inflow location; and estimate a rate at which fluid flows into the annulus at the first inflow location on the basis of the identified change in temperature and the estimated change in temperature.
  • the set of instructions may be configured to cause the computing system to: identify a geothermal temperature at a depth corresponding to the first inflow location, whereby to estimate a temperature of fluid flowing into the annulus at the first inflow location, wherein the further model is configured to estimate the change in temperature of the fluid in the annulus based on the temperature of the fluid entering the annulus at the inflow location.
  • the further model may be configured such that fluid flowing within the annulus is assumed to mix with fluid entering the annulus at the first inflow location, and to associate the change in temperature of the fluid within the annulus with a rate of flow and a temperature of fluid flowing within the annulus upstream of the first inflow location and a rate of flow and a temperature of fluid flowing into the annulus at the first inflow location.
  • a system for estimating flow of fluid into a production well extending into a reservoir comprising fluid
  • the well comprising a central tubing and an annulus surrounding the central tubing, the annulus being connected to the reservoir so as to receive fluid at one or more inflow locations, and the central tubing having at least one inlet, arranged to allow fluid to flow from the annulus into the central tubing, and being located downstream of the one or more inflow locations
  • the production well further comprising one or more devices arranged to measure a temperature of fluid within the annulus at a plurality of points along the length of the annulus
  • the system comprising: an interface arranged to receive temperature data, the temperature data having being collected by the one or more devices and being indicative of a temperature of fluid at a plurality of points along the length of the annulus; and a processor arranged to: identify a change in temperature of fluid flowing within the annulus on the basis of the received temperature data at the plurality of points; execute a model to estimate heat transfer from the central tubing to fluid flowing
  • the processor may be arranged to use the model to determine a specific heat capacity of the fluid and thence estimating a composition of the fluid flowing from the reservoir into the annulus at the first inflow location.
  • the processor may be arranged to use the model to estimate a rate at which the fluid flows along the longitudinal axis of the annulus, whereby to estimate a rate at which fluid flows into the annulus at the first inflow location.
  • the processor may be arranged to: identify a change in temperature of fluid within the annulus between a point upstream of the first inflow location and a point downstream of the first inflow location; execute a further model to estimate a change in temperature of the fluid in the annulus caused by fluid entering the annulus from the reservoir at the first inflow location; and estimate a rate at which fluid flows into the annulus at the first inflow location on the basis of the identified change in temperature and the estimated change in temperature.
  • the processor may be arranged to: identify a geothermal
  • the further model is configured to estimate the change in temperature of the fluid in the annulus based on the temperature of the fluid entering the annulus at the inflow location.
  • the further model may be configured such that fluid flowing within the annulus is assumed to mix with fluid entering the annulus at the first inflow location, and to associate the change in temperature of the fluid within the annulus with a rate of flow and a temperature of fluid flowing within the annulus upstream of the first inflow location and a rate of flow and a temperature of fluid flowing into the annulus at the first inflow location.
  • FIG. 1 is a schematic block diagram showing a simplified representation of a fluid recovery system 1 that comprises a multi-layer reservoir.
  • the reservoir comprises a series of interbedded permeable and impermeable layers.
  • the permeable layers bear fluid (such as oil, gas and water) in the pore spaces within the rock, and are referenced 2 and 4.
  • the impermeable layers are referenced 6, 8 and 10.
  • the composition of this layer 12 is not relevant to this example.
  • the permeable and impermeable layers make up the reservoir. Penetrating the reservoir is an injection well, comprising a control station 14 and a well bore 16, and a production well, comprising a control station 18 and a well bore 20.
  • the injection and production wells are separated by a distance L as shown. Typically there are many more wells than the two shown here; however two are shown in this exemplary embodiment for simplicity.
  • the injection well When used for a waterflood, the injection well injects water as an injection fluid under pressure into the reservoir.
  • the water flows along each of the permeable layers 2 and 4 as shown by the arrows.
  • the water pushes the oil in the reservoir ahead of it causing the oil to be displaced from the reservoir into the well bore of the production well (again shown by the arrows).
  • the pressure of the reservoir optionally aided by pumps located in the well bore of the production well, lifts the oil and water produced from the reservoir up to the surface where it can be stored and refined.
  • FIG 2 is a schematic diagram showing a simplified representation of a portion of a well bore 20 of a production well.
  • the well bore comprises an annulus 22 which opens onto the rock of the reservoir.
  • a central tubing 24 which conveys fluid to the surface.
  • the annulus is located between the central tubing 24 and the wellbore.
  • the wellbore may be an openface wellbore, i.e. one not lined with a casing.
  • the annulus is divided into sections, with section 26 being fully represented, and the surrounding sections 28 and 30 being partially represented in Figure 2. Separating the sections are separators (also known as 'packers') 32 (between sections 26 and 28) and 34 (between sections 26 and 30), which isolate a given section from adjacent sections.
  • separators also known as 'packers'
  • the packer 32 is referred to as the downstream packer for section 26
  • packer 34 is referred to as the upstream packer for section 26.
  • downstream and upstream are measured relative to the flow of fluid in the well, and thus the upstream packer is generally located at a greater depth than is the downstream packer.
  • DTS downhole temperature sensor
  • the DTS is able to measure the temperature of the fluid in the annulus at a plurality of points along its length.
  • the DTS may typically be a fibre optic sensor as is known in the art.
  • the annulus 22 is open to the rock of the reservoir, which means that fluid is able to flow into the annulus from the reservoir. While a small amount of fluid may enter the annulus along its entire length, the majority of the fluid will enter the annulus at a number of inflow locations, which are typically fissures in the rock which provide a low permeability path into the annulus and thus carry the majority of the fluid flowing from the reservoir into the annulus 22. Two such inflow locations (i.e. fissures) are shown by arrows 38 and 40.
  • Fluid having entered the annulus 22, may flow downstream along the annulus towards an inlet 50 in the central tubing. At the inlet, the fluid may enter the central tubing from the annulus. The fluid in the central tubing may thus be conveyed to the surface. This process will be described in more detail with reference to Figure 3.
  • Figure 3 shows a two-dimensional section of the well bore similar to Figure 2.
  • annulus 22 surrounds central tubing 24.
  • the annulus is divided by packers 32 and 34 into sections 26, 28 and 30, and a DTS 36 is provided along the longitudinal length of the annulus.
  • Fluid is shown flowing into the annulus at two inflow locations 38 and 40.
  • the first location 38 is at a greater depth than the second location 40, and is thus upstream of the second location 40. While only two inflow locations are shown, it will be apparent that many more may be present in any given section of the annulus. In addition, while the inflow locations are shown only on one side of the annulus, it will be understood that a fissure creating an inflow location may be present around some, or all, of the
  • Fluid flows from the reservoir into the annulus at the first inflow location 38.
  • the fluid then flows downstream (i.e. upwards) along the annulus, as represented by arrow 44.
  • the fluid flows to the downstream end of the annulus where, as represented by arrow 48, it flows into the central tubing via an inlet 50.
  • DTS 36 measures the temperature of the fluid in the annulus at a plurality of locations, referenced 37A..E. It will be understood that these points are purely exemplary, and the temperature may be measured at many other points in the annulus 22.
  • Point 37A corresponds to the point at which the fluid in the annulus is stagnant (i.e. flow 42).
  • Point 37B corresponds to a point just downstream of the first inflow 38.
  • Point 37C corresponds to the point just upstream of the second inflow 40.
  • Point 37D corresponds to a point just downstream of the second inflow 40.
  • point 37E corresponds to a point just upstream of the inlet 50.
  • Embodiments provide computer systems, and computer implemented methods which may be used to assist in the estimating of flow in a production well as described above.
  • embodiments may include a computer system running flow estimation (FE) software components which enable the system to estimate the flow into and within the production well.
  • FE flow estimation
  • the computer system may be located in a planning and control centre (which may be located a substantial distance from the reservoir, including in a different country).
  • the computer system may be part of the control systems of the reservoir, such as control stations 14 and 18 as shown in Figure 1.
  • the FE software components may comprise one or more applications as are known in the art, and/or may comprise one or more add-on modules for existing software.
  • the computer system 200 comprises a processing unit 202 having a processor, or CPU, 204 which is connected to a volatile memory (i.e. RAM) 206 and a non- volatile memory (such as a hard drive) 208.
  • the FE software components 209, carrying instructions for implementing embodiments, may be stored in the non-volatile memory 208.
  • CPU 204 is connected to a user interface 210 and a network interface 212.
  • the network interface 212 may be a wired or wireless interface and is connected to a network, represented by cloud 214.
  • the processing unit 202 may be connected with sensors, databases and other sources and receivers of data through the network 214.
  • the processor 204 retrieves and executes the FE software components 209 stored in the non-volatile memory 208. During the execution of the FE software components 209 (that is when the computer system is performing the actions described below) the processor may store data temporarily in the volatile memory 206. The processor 204 may also receive data (as described in more detail below), through user interface 210 and network interface 212, as required to implement embodiments. For example, data may be entered by a user through the user interface 210 and/or received from e.g. a downhole temperature sensor in a production well through the network 214 and/or may be retrieved from a remote database through the network 214.
  • data may be entered by a user through the user interface 210 and/or received from e.g. a downhole temperature sensor in a production well through the network 214 and/or may be retrieved from a remote database through the network 214.
  • diffusion coefficients may be determined in a laboratory from a core sample relating to the reservoir using well known processes. Once determined, this data may be actively sent to the processing unit 202, or stored in a database to be retrieved as required by the processing unit 202. Alternatives will be readily apparent to the skilled person.
  • the processor 204 may provide an output via either of the user interface 210 or the network interface 212. If required, the output may be transmitted over the network to remote stations, such as the control station for an injection well. Such processes will be readily apparent to the skilled person and will therefore not be described in detail.
  • the downhole temperature sensor (DTS) 36 in the annulus measures temperature along the annulus and in particular the following changes of temperature:
  • the nature of the fluid in the central tubing 24 passing to the next downstream section is known.
  • the process may be repeated for each section working downstream, with the fluid entering the annulus at any given section being mixed with the fluid in the central tubing 24 proceeding downstream from that section.
  • the composition, flow rate and temperature of the fluid in the central tubing 24 can be determined.
  • the temperature of the flow 52 in the central tubing 24 at the upstream packer 34 is denoted as T and the flow rate as Q. It will also be assumed that the flow 52 has a known composition (i.e. mix of oil, gas and water) and hence a specific heat capacity (which may be an average heat capacity of the mixed fluids).
  • the geothermal temperature of the reservoir is higher at greater depths. Therefore the fluid in the central tubing, having flowed from these greater depths, will be at a higher temperature than the fluid in the annulus.
  • the region 42 between the upstream packer and the first inflow location 38 is approximately stagnant and so will, in time, assume the temperature T of the central tubing.
  • This temperature may be measured by the DTS 36, once the flow in the well has stabilised, which is to say when the fluid in region 42 has had the chance to be warmed by the flow in the central tubing 24.
  • the temperature in the annulus will jump to the value Ti which is close to the geothermal temperature (TGi) at that depth, but may differ owing to the Joule-Thomson effect cooling the fluid as it flows from the rock of the reservoir into the annulus at the inflow location, and to a temperature drift in the geotherm.
  • This Joule- Thomson effect may cause a temperature change which may be represented in terms of a Joule-Thomson coefficient JT, this being a function of the composition of the fluid flowing into the annulus at the first inflow location 38.
  • JT Joule-Thomson coefficient
  • Tj is the temperature of the fluid at the first inflow location 38
  • TGi is the geothermal temperature at the depth of the first inflow location 38;
  • DTi represents a quantity of temperature drift (which will be discussed below);
  • JT is a Joule-Thomson coefficient for the composition of the fluid entering the annulus at the first inflow location 38, which may be determined from the composition of the fluid;
  • Qi represents the rate of flow of fluid into the annulus at the first inflow location 38.
  • the geothermal temperature TGj may be determined using methods known in the art; for example, it may be calculated from survey data or, since the geothermal temperature is relatively static, may be measured as the well is being drilled, or before the flow starts in the well. Therefore a range of values for JT, Qi and DTj which are consistent with T ⁇ to within a specified error tolerance, may be determined using the above formula. In the early stages of extraction of fluid from the reservoir, the flow into the annulus will likely be pure oil (possibly containing dissolved gases), therefore JT will be known;
  • the temperature change at the first inflow location 38 may be determined using, for example, the temperatures measured at points 37A and 37B by the DTS 36 as described above in Figure 3.
  • the flow 44 between the first and second inflow locations 38 and 40 may be analysed.
  • the fluid flowing within region 44 will initially start at temperature 7/ and will have a flow rate of Qj. However, as the temperature (7) in the central tubing 24 is greater than the temperature ( ;) in the annulus, there will be a transfer of heat from the central tubing to the annulus.
  • This transfer of heat may be modelled by, for example, considering the heat transfer per unit distance (Q pa ) along the tubing.
  • Q pa can be calculated using a formula such as: ⁇ ⁇ 1 aJ (2) where:
  • Q pa is the heat transfer per unit distance
  • r is the external radius of the central tubing 24
  • k is the thermal conductivity of the central tubing 24
  • ⁇ 5 is the thickness of the wall of the central tubing 24
  • T a is the temperature of the fluid in the annulus at a given point along the length of the annulus.
  • the temperature change of fluid in the annulus may be modelled using the following
  • Qp a is the heat transfer per unit distance (as calculated above using equation 2); p is the density of the fluid in the annulus 22;
  • M a is the volume flux in the annulus (i.e. the volume flux of e.g. flow 44 in Figure
  • Equations 2 and 3 above may be used to refine the value(s) of Qi calculated using equation 1 and also the composition of the fluid as determined according to the techniques described above.
  • fluid flows into the well with a flow rate of Q2, at a temperature T2, and having a certain composition.
  • 71 ⁇ 2 represents the temperature of the fluid entering the annulus at a location corresponding to the second inflow location 40, and thus takes into account the Joule-Thomson effect and geothermal drift at that location.
  • This fluid mixes with the fluid in the annulus, causing the temperature in the annulus to abruptly change.
  • the abrupt change in temperature ( ⁇ 2) associated with the second inflow location 40 can be modelled by:
  • Tj2 is the temperature of the fluid in the annulus at a point just upstream of the second inflow location 40;
  • ⁇ 2 is the abrupt change in temperature at the second inflow location 40
  • CP i is the specific heat capacity of the fluid upstream of the second inflow location 40, which may be calculated from the composition of the fluid at that upstream location;
  • CP 2 is the specific heat capacity of the fluid entering the annulus at the second inflow location 40, which may be calculated from the composition of the fluid;
  • Q 2 is the flow rate of the fluid entering the annulus at the second inflow location 40.
  • T2 is the temperature of the fluid entering the annulus at the second inflow location
  • a range of values for Q2, T2 and CP 2 may be estimated for fluid at the second inflow location 40. From CP 2 the composition of the fluid entering the annulus at the second inflow location 40 may also be estimated. The temperature change at the second inflow location 40 may be determined using, for example, the temperatures measured at points 37C and 37D by the DTS 36.
  • the flow upstream of the second inflow location 40 (i.e. between the second inflow location 40 and the inlet to the central tubing 50) will evolve in temperature as heat is transferred from the central tubing 24 to the fluid in the annulus 22.
  • This transfer of heat may be modelled, using equations 2 and 3 above, and used to refine the values for Qi and Q2 and for the composition of the fluid as calculated above.
  • the estimated flow rates into the annulus ⁇ Qi and Qi) may be used to determine the flow rate of fluid from the annulus 22 into the central tubing 24, while the temperature of the fluid flowing into the central tubing may be determined from measurements made by the DTS 36. These values may be combined with the flow rate Q and temperature T in the central tubing 24 to determine the flow rate and temperature of the fluid in the central tubing 24 downstream of the inlet 50. Therefore the flow rate and temperature of the fluid in the central tubing within the downstream sections may be determined. The steps described above may be repeated for each section of the annulus proceeding downstream, with the estimates of flow rates and temperature in a given section of the annulus being used to estimate the temperature and flow rate in the central tubing for downstream sections.
  • the temperature changes are dependent on the flow rate of the fluid into the central tubing 24, the composition of the fluid and on any geothermal drift. Therefore at each inflow location, or along the annulus between inflow locations, a range of values for flow rate, composition etc may be estimated. These ranges of values may be arranged in pairs, i.e. such that a certain composition is associated with a certain flow rate. These ranges of values may subsequently be refined using measurement data as will be described in more detail below.
  • the temperature at any location along the annulus is dependent on the flow rate and composition of fluid upstream of that location.
  • the temperature change at the second inflow location 40 is dependent, in part, on the flow rate and composition of the fluid entering the annulus at the first inflow location 38.
  • the calculations generated using data measured and estimated at any given location may be used to refine the range of values calculated further upstream of that given location.
  • the range for Qi may be modified to remove the inconsistent values. In practice, this may involve defining a set of values which Qi may take, and then selecting a subset of the values to ensure that only consistent values are maintained.
  • composition and flow rate into the well bore may be made and used to modify or improve the estimates for the composition and flow rate into the well bore.
  • surface measurements of total flow rate and overall composition from the well bore may be used to modify the flow rate and/or composition values calculated for a specific section or even inflow location.
  • an overall model for the overall flow in the annulus may be constructed based on the principles described above, and the input values into this model adjusted to achieve a best fit to the temperature data.
  • temperature data is received for a number of points in time, and may be used in a model to determine the evolving flow field conditions (i.e. flow rate and composition) in the well bore.
  • the changes may be used to refine current and historic values for the composition and flow rate and to identify gradual changes in, for example, the temperature of the fluid.
  • a method for estimating the flow of fluid from a reservoir into a section of an annulus (such as section 26 described above) performed by computer system 200, according to an embodiment, will now be described with reference to Figure 5.
  • the processor 204 receives temperature data from the DTS 36.
  • the temperature data comprises data indicative of the temperature of the fluid in the annulus 22 at a plurality of points within the annulus at a given point in time.
  • the points may include points 37A..E as described above in Figure 3.
  • the processor 204 uses the received temperature data to identify changes in the temperature of the fluid within the annulus 22 between the points, at any given point in time.
  • At least one such identified change may correspond to a change in temperature associated with fluid entering the annulus from the reservoir such as the change in temperature between points 37A and 37B, and/or between points 37C and 37D described above with reference to Figure 3.
  • At least a further such change may correspond to the transfer of heat from the central tubing to the fluid in the annulus, such as the change in temperature between points 37B and 37C, and/or between points 37D and 37E described above with reference to Figure 3.
  • the processor 204 selects an inflow location for modelling.
  • the selected first inflow location may correspond to the most upstream inflow location 38 of the section of the annulus 26.
  • the processor 204 may analyse the temperature data to look for locations (e.g. locations 37A and 37B) between which there is a relatively large change in temperature.
  • steps 60 to 66 may be repeated for a number of inflow locations. Therefore, these steps will be described below for a first and a second inflow location. It will be assumed that the first inflow location is the most upstream inflow location of the section of the annulus, i.e. inflow location 38, and that the second inflow location has at least one inflow location upstream of it, i.e. is inflow location 40.
  • step 60 the processor uses a model for the temperature change for fluid flowing into the annulus 22 at the selected inflow location.
  • the model may be configured to assume that the fluid flowing into the annulus (reference 38 in Figure 3) displaces the stagnant fluid within the annulus (reference 42 in Figure 3). Therefore the model may be configured to assume that the temperature of the fluid downstream of the selected inflow location is the temperature of the fluid flowing into the annulus allowing for any Joule- Thomson effect (this being caused by the fluid entering the annulus expanding as it leaves the rock of the reservoir). Therefore Equation 1 above may be used to associate the temperature of the fluid within the reservoir (i.e. the temperature measured at point 37B) with the flow rate Q] of the fluid entering the reservoir.
  • Equation 4 as described above may be used to associate the change in temperature (i.e. the change in temperature between point 37C and 37D) with the expected change in temperature caused by the mixing of the fluid in the annulus (which has a previously estimated flow rate Qi,
  • Equation 1 may be used in conjunction with Equation 4 to estimate any Joule-Thomson effect on the fluid flowing into the annulus.
  • step 62 the processor uses the model described above with reference to step 60 to estimate the flow Q n and composition for the flow into the annulus at the selected (n th ) inflow location based on the temperature change between points, identified in step 58 above, corresponding to a change in temperature associated with fluid entering the annulus from the reservoir.
  • the processor 204 uses a further model for the heat transfer from the central tubing to fluid in the annulus downstream of n th inflow location (i.e. between the n th inflow location and the next inflow location downstream, or the inlet to the central tubing, if applicable).
  • the model may be configured such that the heat transfer from the central tubing to the fluid in the annulus is assumed to be substantially constant along the length of the tubing. Preferably this involves using equations 2 and 3 as detailed above.
  • the processor 204 may use the further model to estimate and/or refine an estimate for the flow into the annulus at the first to n* inflow location (i.e. Qi. n) based on the temperature change between points, identified in step 58 above, corresponding to the transfer of heat from the central tubing to the fluid in the annulus and the modelled temperature change.
  • This step may involve estimating the flow rate Q tripod and estimating the composition of the fluid.
  • step 70 it is determined whether temperature data are available from other inflow locations, and if so, the processor 204 selects the next (i.e. n+1) inflow location and proceeds to perform the steps described above from step 60. If there are no more inflow locations, then the processor 204 may perform a similar analysis for other sections of the annulus, represented by the arrow returning to the start point.
  • the above method may be used iteratively to generate and refine estimates of the rate of flow of fluid into the well.
  • 60 for the first inflow location may be subsequently refined using the model for the heat transfer from the central tubing in step 64, since Q] and the composition of the fluid will be modelled in both steps.
  • a range of values for the composition and flow rate of the fluid may be estimated by the processor 204. This range may comprise a set of pairs of values, each pair being an estimate of flow rate and a corresponding composition. This range or set may be refined by excluding values which are inconsistent with values generated by subsequent iterations of the models.
  • measurements may be made of e.g. the temperature in the central tubing, a flow rate in the central tubing (measured by a flow meter) and or the composition of the fluid from the central tubing (e.g. measured from a sample taken at the surface). These measurements may be used to refine the estimates, or ranges of estimates provided by the steps described above.
  • a set of values generated in steps 60 and 62 above for the flow rate and composition of fluid flowing into the annulus at a given inflow location contains one or more pairs of values for the composition and the flow rate that are indicative of the fluid having a large proportion of water; and the fluid produced at the surface from the central tubing is almost pure oil (i.e. has a small proportion of water), then these pairs of values for the composition and flow rate may be excluded since they are incompatible with the surface measurements.
  • the temperature data may be collected for a plurality of points in time. From this data, previous flow rates may be refined, by e.g. assuming that all changes (in flow rate or composition) are gradual and continuous. Thus subsequent modelling steps may be used to refine previous models.
  • a series of temperature measurements may be made for a number of points in time. From these measurements, estimates for changes in the temperature of the fluid entering the well may be made. These changes were represented as factor DTi, namely temperature drift, in equation 1 above. In some embodiments, the changes in the temperature of the fluid entering the well may be determined by the processor 204 from the DTS data in conjunction with the determination of estimates for the flow rates in the annulus.
  • the changes in DTj may subsequently be used to estimate the tilt of the reservoir.
  • the layers of the reservoir may not be horizontal between the injection well and the production well.
  • layer 2 of the reservoir can be seen changing in depth.
  • Tilt in this context, is a measure of the gradient, or slope, in the depth of the reservoir relative to a horizontal line joining the injection well and the production well.
  • the fluid in the layers of the reservoir Prior to fluid being extracted from the reservoir, the fluid in the layers of the reservoir will be at the geothermal temperature (i.e. the fluid will, in its source position in the reservoir, have achieved thermal equilibrium with the surrounding rock). Since the geothermal temperature increases with depth, the temperature of fluid in a reservoir will change as the depth of the reservoir changes. It can therefore be expected that, in the example shown in Figure 1 , prior to extraction of fluid from the reservoir, the fluid in a portion of the layer 2 near the injection well 16 (which is at a greater depth) will be at a higher temperature than the fluid in a portion of the layer 2 near the production well 20 (which is at a shallower depth).
  • a difference in the temperature of the portions of fluid will be caused by a difference in the original temperature of the portions of the fluid, which in turn will have been caused by differences in the geothermal temperature at the source positions of the two portions of fluid. Therefore, a difference in depth for the source positions of the two portions of fluid may be determined from the difference in temperature.
  • the distance between the two positions, along the direction of flow of the fluid within the layer may be determined from the rate of flow of fluid into the reservoir. Consequently, for the two portions of fluid, a separation distance may be determined from the quantity of fluid flowing into the well during the period between the first portion of fluid flowing into the well and the second portion flowing into the well.
  • the reservoir will have a relatively continuous flow of fluid, and therefore the temperature will change progressively as the fluid enters the well. Therefore, instead of considering only two discrete portions of fluid, the flow rate of the fluid into the reservoir, and the rate of change over time in the temperature of the fluid entering the production well over time, may be used to determine an estimate of the tilt, i.e. the change in depth by distance.
  • a velocity of the fluid through the layer of the reservoir may be determined. This velocity is indicative of the distance moved, along the layer in the direction of flow of fluid within the layer, by a given portion of fluid in a given time.
  • Figure 6 shows an example graphical output depicting temperature against time for fluid entering a production well, such as production well 20 shown in Figure 1.
  • the temperature of the fluid gradually increases from approximately 71 °C to 72 °C over the course of approximately 2500 days (this temperature change and time period are purely exemplary).
  • the change in temperature has a trend, shown by line 71.
  • this is indicative of fluid entering the well at the early part of the reservoir life (i.e. from day 0) and originating at a depth corresponding to a geothermal temperature of approximately 71 °C.
  • this is indicative of the fluid originating at a depth corresponding to a geothermal temperature of approximately 72 °C.
  • a computer-implemented method for estimating a tilt of a layer of a reservoir there being a production well extending into the layer of the reservoir configured such that fluid flows from the layer into the production well, the production well further comprising one or more devices arranged to measure a temperature of fluid at one or more locations within the production well at a plurality of points in time
  • the method comprising: receiving temperature data from the one or more devices, the temperature data being indicative of a temperature of fluid entering the production well from the layer at each of a plurality of points during a period of time; identifying, using the temperature data, a trend indicative of a change in temperature of the fluid entering the production well during the period of time; identifying a velocity of fluid within the layer in a direction of flow of fluid within the layer during the period of time; determining using the identified trend and the identified velocity, an estimate of the change in temperature by distance for the fluid, the distance being in a direction of flow of fluid within the layer; identifying a geothermal gradient indicative of a
  • the temperature of the fluid entering the well may change.
  • changes in temperature may be identified.
  • These temperature changes may be used to determine information about the reservoir.
  • the tilt of the reservoir may be determined form the evolution of the fluid temperature over time.
  • the 'tilt' of the reservoir indicates that the depth of the reservoir is not constant.
  • the temperature evolution is therefore caused by fluid passing along the reservoir from a deeper or shallower point.
  • the evolution may take many days, and possibly years, as the fluid takes time to flow to the inflow location. Therefore from the change in temperature, the tilt of the reservoir can be determined, and thus the modelling and mapping of the reservoir may be improved.
  • the trend may be determined over a period greater than a month.
  • the method may comprise identifying a flow rate of fluid into the production well from the layer whereby to estimate the velocity of fluid within the layer.
  • the method may comprise: identifying a height of a permeable layer containing the fluid within the reservoir, whereby to estimate the velocity of fluid within the layer.
  • the method may comprise multiplying the flow rate by a predetermined constant, whereby to estimate the flow velocity, the predetermined constant being calculated in dependence on the arrangement of at least one injection well in relation to the production well.
  • the flow velocity of fluid within the reservoir may be used to relate the change in temperature over time to a change in temperature over distance.
  • the flow of fluid is not linear, since the fluid will enter the well from an arc (or full circle) surrounding the well.
  • a predetermined constant may be used to relate the inflow rate and the height to a velocity of fluid within the reservoir.
  • the method may comprise associating a change in temperature of the fluid entering the production well with a change in depth based on the geothermal gradient of the reservoir whereby to determine a measure of the tilt of the layer.
  • the change in temperature with length may be used to determine a change in depth with length, i.e. the tilt, of the reservoir.
  • a computer readable storage medium storing computer readable instructions thereon for execution on a computing system to implement a method for estimating a tilt of a layer of a reservoir, there being a production well extending into the layer of the reservoir configured such that fluid flows from the layer into the production well, the production well further comprising one or more devices arranged to measure a temperature of fluid at one or more locations within the production well at a plurality of points in time, the set of instructions are configured to cause the computing system to perform the steps of: receiving temperature data from the one or more devices, the temperature data being indicative of a temperature of fluid entering the production well from the layer at each of a plurality of points during a period of time; identifying, using the temperature data, a trend indicative of a change in temperature of the fluid entering the production well during the period of time; identifying a velocity of fluid within the layer in a direction of flow of fluid within the layer during the period of time; determining using the identified trend and the identified velocity, an estimate of the change in temperature by distance
  • a system for estimating a tilt of a layer of a reservoir there being a production well extending into the layer of the reservoir configured such that fluid flows from the layer into the production well, the production well further comprising one or more devices arranged to measure a temperature of fluid at one or more locations within the production well at a plurality of points in time
  • the system comprising: an interface arranged to receive temperature data, the temperature data having been collected by the one or more devices, the temperature data being indicative of a temperature of fluid entering the production well from the layer at each of a plurality of points during a period of time; and a processor arrange to: identify, using the temperature data, a trend indicative of a change in temperature of the fluid entering the production well during the period of time; identify a velocity of fluid within the layer in a direction of flow of fluid within the layer during the period of time; determine using the identified trend and the identified velocity, an estimate of the change in temperature by distance for the fluid, the distance being in a direction of flow of fluid within the layer; identify
  • step 72 the processor 204 receives temperature data from the DTS 36 for a plurality of points in time. This may, for example, be over the course of many days.
  • temperature data is collected for a period longer than a month, and may be collected for periods over a year in duration.
  • the DTS data may identify the temperature of fluid within the annulus 22, as described above in Figure 3, alternatively, direct measurement of the temperature of the fluid prior to it entering the annulus (i.e. by a DTS embedded in the reservoir), may be performed.
  • the temperature data may be associated with only a single inflow location as described above in Figures 2 and 3, however in some examples , the temperature data may be associated with multiple inflow locations.
  • the processor 204 identifies, from the DTS data, the temperature of the fluid in the reservoir prior to the fluid entering the annulus at each point in time. This may be done by analysing the temperature of the fluid in the annulus to determine the temperature of the fluid in the reservoir at its source position prior to the fluid flowing through the reservoir layer and entering the annulus, using, for example, the models described above. However, in the alternative, other methods (such as by using direct measurement of the temperature of the fluid in the reservoir prior to the fluid entering the annulus) may be used.
  • the processor 204 may identify the temperature of the fluid in the reservoir entering the annulus at only a single inflow location as described above in Figures 2 and 3. Alternatively, the processor 204 may determine temperatures for multiple inflow locations and average these temperatures. As shown in Figure 1, a reservoir may comprise multiple layers; therefore the processor 204 may average the temperatures for the fluid for a single, or for each, layer.
  • the processor 204 identifies any trend in the temperature data. This trend may be over many days, and typically over periods longer than a month. An example of such a trend is shown in Figure 6.
  • the processor 204 identifies the flow rate of fluid from the layer of the reservoir into the production well during this period. This flow rate may be determined by the processor 204, for example in accordance with
  • processor 204 may be received by the processor 204 from a further device, such as a flow rate sensor associated with the production well.
  • step 78 the processor 204 calculates an estimate of the tilt of the reservoir from the identified trend.
  • the tilt may be calculated using an equation such as:
  • Q is the flow rate of fluid from the layer into the production well identified by the processor in step 76;
  • L is the interwell spacing which may be determined from the known locations of the injection and production wells.
  • —— is the temperature change in the fluid in the direction of the well pair.
  • AQ/H represents an indication of the velocity of the fluid within the layer of the reservoir in the direction of flow of fluid within the layer.
  • the tilt of the reservoir may be subsequently calculated by assuming that the fluid was originally at, or near, the geothermal temperature, and comparing the geothermal temperature at known depths to the temperature change in the direction of the well pair.
  • the geothermal temperature may be determined using techniques known in the art from, for example, survey data.
  • the factor A can be determined from the arrangement of the wells in the reservoir.
  • One such arrangement will be described with reference to Figure 8.
  • a series of production wells are arranged approximately in line with one another, as represented by wells 80A, 80B and 80C. Spaced from, and parallel to, these production wells 80A, 80B and 80C are injection wells 82A, 82B and 82C.
  • the injection and production wells are arranged in respective lines approximately perpendicular to a gradient of the underlying reservoir.
  • the gradient of the reservoir is represented by the lines 84 (which represent the contours of the reservoir).
  • the flow between the wells does not always follow the direct path (i.e. the line of minimum distance between the injection well and production well) between the injection and production well, and thus the path length between the relevant wells may vary. Accordingly, using methods known in the art for calculating mean path length and the like, the factor A may be derived based on the locations of the injection and production wells. In this case, the factor A may have a value of 0.065.
  • the temperature of the fluid increases over time, this may not be the case; in other examples the temperature may decrease, for example in the event that the reservoir decreases in depth towards the production well.

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Abstract

La présente invention porte sur un procédé mis en œuvre par ordinateur pour estimer un écoulement de fluide dans un puits de production s'étendant dans un réservoir comprenant un fluide, le puits comprenant un tubage central et un annulaire entourant le tubage central. L'annulaire est relié au réservoir de manière à recevoir un fluide à une ou plusieurs positions de flux entrant. Le tubage central a au moins une entrée, agencée pour permettre à un fluide de s'écouler depuis l'annulaire dans le tubage central, et est située en aval de la ou des positions de flux entrant. Le puits de production comprend en outre un ou plusieurs dispositifs agencés pour mesurer une température de fluide dans l'annulaire à une pluralité de points le long de la longueur de l'annulaire. Le procédé comprend : la réception de données de température provenant du ou des dispositifs indicatives d'une température de fluide à une pluralité de points le long de la longueur de l'annulaire; l'identification d'un changement de température de fluide s'écoulant dans l'annulaire sur la base des données de température reçues à la pluralité de points; l'utilisation d'un modèle pour estimer un transfert thermique depuis le tubage central vers un fluide s'écoulant dans l'annulaire, ledit modèle étant configuré de telle sorte que le transfert thermique est supposé comme étant sensiblement constant le long de la longueur du tubage; et l'estimation d'un taux auquel un fluide s'écoule dans l'annulaire depuis le réservoir à une première position de flux entrant sur la base du changement identifié de température entre les points et du transfert thermique estimé.
PCT/EP2012/076479 2011-12-20 2012-12-20 Estimation de débits de multiples couches de réservoir d'hydrocarbure dans un puits de production WO2013092909A1 (fr)

Priority Applications (3)

Application Number Priority Date Filing Date Title
US14/366,939 US20140365130A1 (en) 2011-12-20 2012-12-20 Estimating flow rates from multiple hydrocarbon reservoir layers into a production well
GB1410602.5A GB2511019A (en) 2011-12-20 2012-12-20 Estimating flow rates from multiple hydrocarbon reservoir layers into a production well
NO20140899A NO20140899A1 (no) 2011-12-20 2014-07-16 Estimering av strømningshastigheter fra multiple hydrokarbonreservoarsjikter inn i en produksjonsbrønn

Applications Claiming Priority (2)

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US20140365130A1 (en) 2014-12-11
NO20140899A1 (no) 2014-09-17
GB2511019A (en) 2014-08-20

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