EP2005154A2 - System and method for estimating filtrate contamination in formation fluid samples using refractive index - Google Patents
System and method for estimating filtrate contamination in formation fluid samples using refractive indexInfo
- Publication number
- EP2005154A2 EP2005154A2 EP07754843A EP07754843A EP2005154A2 EP 2005154 A2 EP2005154 A2 EP 2005154A2 EP 07754843 A EP07754843 A EP 07754843A EP 07754843 A EP07754843 A EP 07754843A EP 2005154 A2 EP2005154 A2 EP 2005154A2
- Authority
- EP
- European Patent Office
- Prior art keywords
- fluid
- refractive index
- formation
- brine
- estimating
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Ceased
Links
Classifications
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N33/00—Investigating or analysing materials by specific methods not covered by groups G01N1/00 - G01N31/00
- G01N33/26—Oils; viscous liquids; paints; inks
- G01N33/28—Oils, i.e. hydrocarbon liquids
- G01N33/2823—Oils, i.e. hydrocarbon liquids raw oil, drilling fluid or polyphasic mixtures
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
- E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
- E21B49/087—Well testing, e.g. testing for reservoir productivity or formation parameters
- E21B49/0875—Well testing, e.g. testing for reservoir productivity or formation parameters determining specific fluid parameters
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N21/00—Investigating or analysing materials by the use of optical means, i.e. using sub-millimetre waves, infrared, visible or ultraviolet light
- G01N21/17—Systems in which incident light is modified in accordance with the properties of the material investigated
- G01N21/41—Refractivity; Phase-affecting properties, e.g. optical path length
- G01N21/4133—Refractometers, e.g. differential
Definitions
- TITLE SYSTEM AND METHOD FOR ESTIMATING FILTRATE
- This disclosure relates to an apparatus and a method for estimating a condition of formation fluid using an index of refraction during withdrawal of such fluid from the formation.
- Oil and gas wells are drilled while circulating drilling fluid (also referred to as "mud") in the wellbore.
- Drilling fluids are typically water-based or oil-based.
- fluid samples are often withdrawn from the subsurface formation at various wellbore depths to determine the characteristics of the fluid in order to determine the location and fraction or amount of hydrocarbons in the formation fluid and the condition of the reservoirs, etc.
- a majority of the wells are drilled under overbalanced conditions, that is, the wells are drilled wherein the pressure in the wellbore due to the weight of the drilling fluid is greater than the formation pressure.
- the drilling fluid invades or penetrates to varying depths in the formation, depending upon the physical conditions of the formation being drilled, such as porosity, permeability and other rock properties. This fluid penetration (also referred to as the fluid invasion) contaminates the connate or virgin fluid in the formation. Therefore, before obtaining a fluid sample downhole, a tool is set at the desired depth and the fluid is withdrawn or pumped from the formation into the wellbore until it is determined that the fluid being withdrawn is substantially free of the drilling fluid.
- Downhole tools referred to as "formation testers” are typically set at the desired depth in the wellbore to pump out the fluid and to withdraw the formation fluid samples.
- fluids that are withdrawn from the formation are often highly contaminated with filtrates of the drilling fluid used for drilling the wellbore.
- To obtain samples that are sufficiently clean (usually ⁇ 10% contamination) formation fluids are generally pumped from the formation into the wellbore for a period of time, typically 30-90 minutes, before collecting samples in sample chambers for laboratory analysis.
- Optical sensors are often used to monitor a contamination level in the withdrawn fluid. Optical absorption measurements have been used to estimate how long it might take before relatively clean fluid samples can be taken and to estimate the eventual purity or contamination levels if the fluid is pumped for a relatively long time period.
- Refractive index measurements have been taken downhole but have not been used to estimate purity or contamination levels for brine. Refractive index measurements can be much less sensitive to the passage of sand particles or other elements present in the formation fluid that may scatter light in the fluid being analyzed than optical absorption spectral measurements.
- a method for estimating a characteristic of brine present in the fluid obtained from a formation that has water-based mud invasion includes: estimating a refractive index of the connate brine from well log measurements; withdrawing the fluid from the formation; measuring a refractive index of the fluid a plurality of times during the withdrawal of the fluid from the formation; estimating the characteristic of the brine by comparing the estimated refractive index of the connate brine with a refractive index measured during the withdrawal of the formation.
- a method for estimating a characteristic of brine in a fluid obtained from a formation that has water-based mud invasion includes: estimating a refractive index of the connate brine from well log data; withdrawing the fluid from the formation; measuring a refractive index of the fluid a plurality of times during the withdrawal of the fluid; fitting a curve to data values that correspond to the plurality of refractive index measurements; and estimating the characteristic of the brine from the estimated refractive index of the connate brine and the fitted curve.
- a method for estimating a characteristic of a fluid obtained from a formation includes: withdrawing the fluid from a formation; measuring a refractive index of the fluid during the withdrawal of the formation fluid to obtain a plurality of refractive index values; obtaining a plurality of resistivity values corresponding to the plurality of refractive index values; fitting a curve through the plurality of resistivity values; estimating a terminal value of the resistivity values from the fitted curve; and estimating the characteristic of the fluid using a current resistivity value and the estimated terminal value.
- an apparatus for estimating a characteristic of brine in a fluid withdrawn from a formation includes a probe to withdraw the fluid from the formation; a refractometer that provides refractive index measurements of the fluid during the withdrawal of the fluid from the formation; and a storage device that has stored therein an estimated value of refractive index of connate brine in the formation that is obtained using well log data; and a processor that estimates the characteristic of the brine from the estimated value of the refractive index of the connate brine and refractive index measurements made during the withdrawal of the fluid from the formation.
- the apparatus includes a probe to withdraw the fluid from the formation; a refractometer that provides a plurality of refractive index measurements of the fluid during the withdrawal of the fluid from the formation; a storage device that has stored therein an estimated value of refractive index obtained from well log data; and a processor that: fits a curve to data values that correspond to the plurality of refractive index measurements; and estimates the characteristic of the brine in the withdrawn fluid from the estimated refractive index and the fitted curve.
- FIG. 1 is an elevation view of a wireline system according to one embodiment of the present disclosure
- FIG. 2 is a schematic diagram of a formation testing tool for use in the system of FIG. 1 according to one embodiment of the present disclosure
- FIG. 3 is a schematic of an optical refractometer suitable for use in a downhole tool of FIG. 2 for determining refractive index of fluid samples;
- FIG. 4 is a graph showing an example of refractive index measurements taken over a time period when the fluid withdrawn from a formation changes from water-based mud filtrate to mostly formation brine;
- FIG. 5 is a graph showing an example of refractive index measurements taken over a time period when the withdrawn fluid changes from oil-based mud filtrate to mostly formation crude oil;
- FIG. 6 is a graph showing an example of computed resistivity from refractive index.
- FIG. 1 shows a schematic diagram of a wireline system according to one embodiment of the present disclosure.
- a well 101 is shown traversing a formation 102.
- a wireline tool 103 supported by an armored cable 115 is disposed in the well 101 adjacent the formation 102.
- Extending from the tool 103 are optional grippers 112 and 114 for stabilizing the tool 103.
- Two expandable packers 104 and 106 disposed on the tool 103 are capable of separating the annulus of the borehole 101 into an upper annulus 130, a sealed intermediate annulus 132 and a lower annulus 134.
- a selectively extendable pad member 140 is disposed on the tool 103.
- the grippers 112, packers 104 and 106, and extendable pad element 140 are used to withdraw the fluid and are described in more detail in reference to FIG. 2.
- Telemetry for the wireline embodiment includes a downhole two-way communication unit 116 connected to a surface two-way communication unit 118 by one or more conductors 120 within the armored cable 115.
- the surface communication unit 118 is housed within a surface controller 150 that includes a processor, memory and an output device, collectively designated by numeral 152.
- a typical cable sheave 122 is used to guide the armored cable 115 into the borehole 101.
- the tool 103 includes a downhole controller 160 having a processor and memory 162 for controlling formation tests in accordance with methods described herein.
- the downhole tool 103 includes a plurality of sensors including an optical sensing module 170 and optional sample tanks 128.
- the optical sensing module 170 is used to measure refractive index of the fluid withdrawn from the formation over time at selected locations and at varying depths within the borehole 101.
- the tool 103 also included other sensors (generally denoted by number 125), such as pressure sensor, temperature sensor, flow meter, etc.
- FIG. 2 shows a schematic diagram of a portion of a formation testing tool 103 deployed in a wellbore for withdrawing the fluid from the formation and for taking refractive index measurements in-situ.
- Selectively extendable gripper elements 112 engage the borehole wall 204 to anchor a tubular member 206 of the tool 103.
- Packer elements 104 and 106 extend to engage the borehole wall 204.
- the extended packers separate the well annulus into three sections, an upper annulus 130, an intermediate annulus 132 and a lower annulus 134.
- the sealed annular section (or sealed section) 132 is adjacent a formation 218.
- Mounted on the tubular member 206 and extendable into the sealed section 132 is a selectively extendable pad sealing element 140.
- sensors 125 are included for determining pressure, temperature and flow rate of the formation fluid sample.
- Packers 104 and 106 sealingly urge against the wall 204 and have a sealed relationship between the wall 204 and extendable element 140. Reducing the pressure in the sealed section 132 prior to engaging the pad 140 initiates fluid flow from the formation into the sealed section 132.
- the extendable element 140 engages the wall, the fluid 208 from the formation flows into the tool via the 220.
- the extendable element 140 is set along a particular orientation.
- a sensor such as an accelerometer, may be used to sense the orientation of the extendable element 140. The extendable element 140 may then be oriented to the desired direction.
- a downhole controller 160 controls the withdrawal of the formation fluid 208.
- the controller 160 is connected to a system volume control device, such as pump 226.
- the pump 226 may be a progressive cavity pump or any suitable pump that can pump out formation fluid 208 from the formation 218.
- a flow meter is included to determine the fluid flow rate.
- a valve 230 for controlling fluid flow to the pump 226 is disposed in the fluid line 222 between the optical sensing module 170 and the pump 226.
- a test volume 205 is the volume below the retracting piston of the pump 226 and includes the fluid line 222.
- the optical sensing module 170 is used to determine the refractive index of the formation fluid within the test volume 205. Any suitable optical module or system for determining the refractive index may be used. In one aspect, the optical sensing module is configured to measure the refractive index using reflection-intensity at a window-fluid interface. The refractive index is computed by comparing the reflection intensity of an air filled cell to the reduced reflection intensity when some other fluid is in the cell and using the known refractive indices of the window (typically a sapphire window) and of air.
- the refractometer of the optical sensing module 170 in one aspect, may be configured to measure refractive index in-situ of any desired fluid, including that of oil, gas and brine.
- the optical sensing module 170 is connected to the controller 160 to provide the feedback data for a closed-loop control system.
- the feedback is used to adjust parameter settings such as detecting sample clean-up.
- Sample clean up refers to the transition from filtrate- contaminated formation fluid to connate or nearly pure formation fluid while pumping fluid at selected depths in the wellbore.
- the downhole controller 160 may incorporate a processor, such as a microprocessor, for processing the reflective index measurements.
- a storage device such as a memory device, may be used as a computer-readable medium to store data, computer programs and algorithms relating to the use by the apparatus described herein and to perform the various functions and methods relating to such apparatus.
- the withdrawn fluid is vented to the upper annulus 130 via line 219.
- a conduit 227 connecting the pump 226 to the line 219 includes a selectable internal valve 232. If fluid sampling is desired, the fluid may be diverted to optional sample reservoirs or tanks 228 by using the internal valves 232, 233a, and 233b rather than venting the fluid through the line 219. The fluid contained in the reservoirs 228 is retrieved from the well for analysis.
- the results of the data processed downhole may be sent to the surface for use and for further processing.
- the controller 160 passes the processed data to a two-way data communication system 116 disposed downhole.
- the communication system 116 transmits a data signal to a surface controller 150, which controller contains a processor 151 and memory storage device that stores computer programs, algorithms and data for use in the apparatus and methods described herein. Any suitable data communication system may be used for the purpose of this disclosure.
- the signals received at the surface are processed by the processor 151 associated with the surface controller 150, which converts and transfers the data to a suitable output and/or storage device 152.
- the surface controller 150 may also be used to send the test initiation commands to the downhole tool 103.
- FIG. 3 shows a schematic of a refractometer assembly 305 for use in the optical sensing module 170.
- a light source 310 comprising a light bulb and a collimitor lens provides collimated light beam.
- the collimated light beam in aspect, may be incident substantially perpendicular to the exterior surface of a first sapphire window 303.
- the light after interaction with the fluid exits from a second sapphire window 302.
- Sapphire windows 303 and 302 in one configuration may lie substantially perpendicular to the collimated beam of light and separated by a gap or channel 304, enabling formation fluid under analysis to flow between the windows.
- the refractometer assembly 305 diverts a portion of the incident collimated beam from source 310 and focuses it onto interface 307 between the first sapphire window 303 and the fluid in channel 304.
- the reflected light beam is split at beam splitter 317 between a refractometer (316, 318, and 320) and an attenuated reflectance spectrometer 621.
- FIG. 3 shows two optical transmission rods 300, 301 (which may be relay lenses, glass or sapphire rods) which are also referred to as the left rod 300 and the right rod 301 may be used for guiding light.
- the longitudinal axes of the two optical transmission rods lie in a plane perpendicular to the plane of both of the pressure containment plates comprising a first sapphire window 303 and a second sapphire window 302 and the channel 304.
- the two optical transmission rods 300, 301 may be placed side-by-side (and contacting each other where they meet at surface 303) and may also be in contact with the first sapphire plate 303.
- a high-temperature index matching gel may be applied to bridge the gap between transmission rods 300, 301 and first sapphire plate 303. Leaving the gap unfilled except for air does not change the refractive index measurement because it diminishes the light intensity measurements of both the unknown and the reference sample by the same factor.
- Such a system may be used to determine the refractive index of the formation fluid sample in channel 304 (Fig. 2). Details of the measurement and analysis techniques for determining the refractive index, are provided in U.S. Patent No. 6,683,681 B2 and U.S. Published Application 2004/0007665 Al.
- FIG. 4 is a graph 400 showing an example of in-situ measurements of refractive index taken over selected time period during pumping of a fluid from the formation.
- the drilling fluid used is water-based mud and the connate fluid is formation brine.
- the refractive index is shown along the y-axis 402 and the time is shown along the x-axis 404.
- the refractive index taken by the refractometer of the kind shown and described with respect to FIG. 3 shows a very stable and constant value, as indicated by constant value 408.
- the refractive index of the fluid being withdrawn changes and after a short period of time, starting at time indicated by arrow 410, starts to increase.
- the proportion of the filtrate (mud) in the fluid starts to decrease and that of the connate fluid starts to increase.
- the fluid undergoes a cleaning up process in which the purity of the sample increases as the filtrate is removed from the invaded zone of the formation.
- the fraction of the connate fluid or the fraction of purity "fp" starts to increase while the fraction of the contamination "fc" starts to decrease.
- the drilling fluid is water-based mud and the connate fluid is formation brine.
- the refractive index of water-based mud is lower than the refractive index of formation brine, the refractive index of the withdrawn fluid increases over time. This is because the density (and refractive index) of the water-based mud is less than the density of the formation brine. As shown in FIG. 4, the refractive index rises rapidly up to time indicated by arrow 414 and then starts to taper off, i.e., starts to increase relatively slowly over time. In the particular example of FIG. 4, the refractive index is shown to increase until the time of about 6500 seconds.
- a dynamic equilibrium is reached in which the fluid sample being withdrawn from the formation cleans up at the same rate as it is re-contaminated from adjacent zones, such as the zones above and below the zone from where the sample is being taken.
- the sample still not is at 100% purity.
- the dynamic equilibrium depends on various factors, such as the ratio of the vertical to horizontal permeability.
- the purity level that may be achieved after a very long period of time is referred to as the terminal purity, ftp, which is usually less than 100%.
- the corresponding terminal contamination (1-ftp) is designated as "ftc.”
- ftc The corresponding terminal contamination (1-ftp) is designated as "ftc.”
- line 450 indicates an estimated or computed value of the refractive index of the connate brine.
- a comparison of the estimated connate brine refractive index and the measured refractive index of the contaminated mixture provides the fraction of connate brine in the fluid mixture being withdrawn.
- the contamination level or the purity level may be computed from a comparison of the two refractive indices.
- the estimated value of the refractive index of the connate brine may be computed from prior data and knowledge of the rock properties of the formation from where the fluid is being withdrawn.
- the refractive index of the mud filtrate can be measured directly. Alternatively, it can be estimated from other properties such as resistivity in the case of water based muds.
- the comparisons made may include computing differences and using ratios of selected measurements or values.
- well logs may be used to estimate the connate brine's resistivity and, from that, the connate brine's refractive index.
- neutron logs may be used to estimate brine salinity.
- brine salinity may be obtained by solving for Sigma Brine in terms of typical neutron cross-sections for the formation of interest and the porosity as measured by neutron logs.
- brine's refractive index may be computed. The relationship between resistivity, pressure, temperature, and refractive index are discussed in U.S. 7,027,928.
- both end points from which to compute the percentage of contamination become known. That is, the refractive index of both the pure water-based mud filtrate (one endpoint) and the pure formation brine (the other endpoint) become known.
- the fraction of contamination may be computed as a linear interpolation between the two pure fluid endpoints.
- the refractive index of the fluid is known.
- the contamination or purity levels can be obtained. If the difference between the estimated value of line 450 and the terminal value of the data in FIG. 4 (described in more detail later) is greater than a selected value, then it may not be feasible to obtain a relatively clean sample even if the fluid is pumped from the formation for extended time period. In such a situation, the tool may be moved to different location in the wellbore for obtaining clean samples.
- the system, apparatus and methods described herein may be configured to provide both qualitative and quantitative measures of the current and terminal purity and contamination levels using a set of refractive index measurements taken over a selected time period.
- the present disclosure provides an indication or estimate in real time of the fraction of the pumping-time that has passed before formation fluid purity will reach a certain level from the changes in the refractive index. For example, the difference between the refractive index of highly-saline formation brine and that of a fairly fresh water-based mud is approximately 0.030.
- the system of the present disclosure can estimate the fraction of the contamination or the clean fluid in real time.
- the system of the present invention provides an estimate of the terminal purity or the contamination level by fitting a suitable curve to the refractive index data taken over a selected time period.
- a suitable curve fitting technique or algorithm may be used. Certain examples of curve fitting techniques that may be used for this invention are described later.
- a curve that may be fitted to the data of FIG. 4 is shown as the solid line 420.
- FIG. 5 is a graph showing an example of in-situ measurements of refractive index taken over a selected time period during pumping of the fluid from the formation wherein the drilling fluid used is an oil-based mud and the connate fluid is crude oil.
- the refractive index (rounded to the nearest 0.001) is shown on the y-axis 502 and the volume of the fluid pumped is shown along the x-axis 504.
- the example of FIG. 5 uses the volume pumped instead of the time used in FIG. 4.
- fluid volume pumped may be a more appropriate parameter, for example when the fluid pump rate is not substantially constant over the pumping time period.
- the refractive index measured by the refractometer of the kind shown and described with respect to FIG. 3 shows certain erratic measurements, such as indicated by numeral 515. Such measurements can occur due the erratic changes in the composition of the initial fluid pumped. As the volume pumped increases, the refractive index of the fluid beings to drop rapidly as shown by the initial part of the data generally represented by arrow 506 and then starts to decrease more gradually as shown by the data generally represented by arrow 508. For any particular pumping, the rate of change of the refractive index depends on the amount of the clean-up. In the particular example of FIG.
- the refractive index starts to decrease relatively slowly.
- the dynamic equilibrium or the terminal purity may be achieved beyond a much greater pumping volume, shown here to be beyond the volume of 14000 cc.
- the refractive index decreases as the fluid is pumped because the refractive index of oil-based mud is greater than that of the crude oil.
- the system of the present invention fits a suitable curve to the data and provides an estimate of the refractive index at terminal purity and the current purity (or contamination) of the withdrawn fluid.
- the percentage of purity or contamination can be determined by linear interpolation between these two endpoints.
- the system of the present invention in one aspect, provides an estimate of the refractive index at terminal purity or the current contamination level by fitting a suitable curve to the refractive index data taken over a selected time period.
- FIG. 6 is a graph 600 showing an example of computed resistivity from refractive index measured during clean-up.
- the refractive index increases as the clean-up continues. This is because the density of the formation brine is typically greater than the water-based mud.
- FIG. 6 represents an example where the resistivity computed or calculated from the refractive index decreases as the clean up continues.
- the computed resistivity is shown plotted along the y-axis 602 and the time is shown plotted along the x-axis 604.
- the computed resistivity is shown from the pumping start time, which in this particular case is shown to be at 8000 seconds and continues to a time of 10,000 seconds.
- the time prior to the pumping start time relates to performing other functions with the downhole tool, such as setting the tool, etc.
- the resistivity values over time are shown by the arrow 608.
- the refractive index data or the computed resistivity data from the refractive index may be used to estimates the terminal purity or the contamination level by a suitably curve fitting such data.
- any known relationship may be used. Such relationships are known and this not described herein.
- the relationships are stored in the memory either downhole or at surface and are used to compute resistivity from the measured refractive index values.
- the curve fitting may be done by a processor in the downhole tool or at the surface processor or a suitable combination thereof.
- the measured data such as shown in FIGS. 4 and 5, or computed data, such as shown in FIG.
- the processor 6 may be transmitted to a surface processor, where the processor using programmed instructions fits a curve for a certain number of data points and extrapolates the curve to determine the terminal purity or terminal contamination and the current purity or contamination levels.
- the programs may be stored in the memory downhole accessible to the downhole processor, wherein the downhole processor performs the curve fitting and provides the results to the surface via the telemetry system.
- any suitable curve fitting method may be used to fit a curve to the refractive index measurements or the computed resistivity. Examples of certain curve fitting methods are provided below.
- the method and apparatus of the present invention fit the measurement data to a non-asymptotic curve.
- a non-asymptotic curve is a curve that provides a fit to the data over a typical or selected pumping time, such as between 30 minutes to two hours, and then extrapolates the results to several times the pumping time, but which approaches plus or minus infinity at infinite times, such as a power series approximation.
- present invention fits a continuously-differentiable, non-asymptotic curve to the raw data. The fit can be to the elapsed time or to the volume of the fluid pumped.
- Ao is denoted to be the "terminal" refractive index, i.e. the refractive index at some very long time (e.g., 24 hours), which time is much longer than the time at which the pumping is normally terminated.
- both (Ao - A) and t (dA/dt) decrease, where A is the refractive index at time t. Assuming that both such values decrease at the same rate, then they are proportional to each other, which means (A 0 - A) — m t (dA/dt), where "m" is a constant.
- the present invention selects a raw data point at a selected time, t, (which may be the latest time, t) at which the actual data intersects (or gets closest to) the best fit line.
- the method then recursively applies this ⁇ A formula to forecast the refractive index at t + ⁇ t and then uses the newly-calculated refractive index to compute the refractive index at a slightly later time, t + 2 ⁇ t, and so on, for all future times. In this manner the method generates future forecasts for A(t).
- the present disclosure provides a method for estimating a characteristic or parameter of interest, such as a current, future or terminal purity or contamination of brine in the formation fluid being withdrawn or pumped at a selected location in the wellbore during the withdrawal of the fluid.
- the method may is for estimating a characteristic of brine in a fluid obtained from a formation that has water-based mud invasion.
- the method may include estimating a refractive index of a connate brine from well log measurements; withdrawing the fluid from the formation; measuring a refractive index of the fluid a plurality of times during the withdrawal of the fluid from the formation; and comparing the estimated refractive index with a refractive index measured during the withdrawal of the formation fluid to estimate the characteristic of the brine.
- the characteristic or property of interest may be the contamination level in the fluid sample or the purity of the brine in the fluid sample or fraction of pure or connate brine or that of contamination in the fluid sample.
- the method may estimate a characteristic of brine in a fluid obtained from a formation that has water-based mud invasion, wherein the method includes: estimating refractive index of connate brine from well log data, such as resistivity or other electrical logs; withdrawing the fluid from the formation; measuring refractive index of the fluid a plurality of times during the withdrawal of the fluid; fitting a curve to data values that correspond to the plurality of refractive index measurements; and estimating the characteristic of the brine from the estimated refractive index and the fitted curve.
- the method may further include estimating a terminal value of the data values and/or estimating a contamination level or purity level of the brine at a future time from the estimated refractive index and the fitted curve.
- the data values to which the curve is fitted may be the actual refractive index measured values or resistivity values that are derived from the measured refractive index values.
- the withdrawing of the fluid is terminated when the difference between the estimated refractive index and the terminal value is greater than a selected value.
- a formation fluid sample is collected when the purity of the brine is determined to be of an acceptable level.
- the estimated refractive index of connate brine is computed corresponding a selected temperature and pressure.
- a method for estimating a characteristic of a fluid during the withdrawal of the fluid from a formation includes: withdrawing the fluid from a formation; measuring a refractive index of the fluid during the withdrawal of the formation fluid to obtain a plurality of refractive index values; obtaining a plurality of resistivity values corresponding to the plurality of refractive index values; fitting a curve through the plurality of resistivity values; estimating a terminal value of the resistivity values from the fitted curve; and estimating the characteristic of the fluid using a current resistivity value and the estimated terminal value.
- the characteristic of the fluid may be a terminal value of contamination in the fluid; terminal value of purity of the fluid; terminal value of a hydrocarbon content in the fluid; fraction of contamination in the fluid; fraction of oil in the fluid; fraction of gas in the fluid; or fraction of water in the fluid.
- Any of the methods may estimate components of the fluid and display a visual image of the estimated components that may be a gray scale visual image or a color visual image and each such image may be a two-dimensional or a three- dimensional image.
- apparatus for estimating a characteristic of brine in a fluid withdrawn from a formation may include a: probe to withdraw the fluid from the formation; a refractometer that provides refractive index measurements of the fluid during the withdrawal of the fluid from the formation; a storage device that stores an estimated value of a refractive index of connate brine in the formation that is obtained using well log data; and a processor that estimates the characteristic of the brine from the estimated value of the refractive index of the connate brine and refractive index measurements made during the withdrawal of the fluid from the formation.
- a sample chamber may be used to collect a fluid sample.
- a pump may be used to pump the fluid from the formation into the sample chamber against hydrostatic pressure.
- Compressed gas in a chamber may be used to pressurize the fluid in the sample chamber.
- the processor may fit a curve to data values that correspond to the plurality of refractive index measurements and estimate the characteristic of the brine in the withdrawn fluid from the estimated refractive index of the connate brine and the fitted curve.
- the processor also may estimate a terminal value of the data values and estimate a contamination level or purity level of the brine in the withdrawn fluid at a future time from the estimated refractive index of the connate brine and the fitted curve.
- the data values used for fitting the curve may be the data values that correspond to measured values of the plurality of the refractive index measurements or resistivity values corresponding to the plurality of refractive index measurements.
- the processor may be configured to cause the taking of a sample of the fluid from the formation when a selected data value indicates that the purity level of brine or the contamination level in the brine is acceptable.
- a computer-readable medium that has embedded therein a computer program, which may include: a set of instructions to fit a curve to data corresponding a plurality of refractive index measurements of a fluid taken during withdrawal of the fluid from a formation; a set of instructions to estimate a terminal value of the refractive index from the fitted curve; and a set of instructions to estimate a characteristic of brine in the fluid from the fitted curve and an estimated value of connate brine computed from using well log data.
- the computer program may further include a set of instructions to fit the curve to the data values over a selected time and extrapolate the fitted curve to a multiple of the selected time that approaches plus or minus infinity at infinite time.
- the computer-readable medium may be a ROM, RAM, CD ROM, DVD, FLASH or any other computer-readable medium, now known or unknown, that, when executed, causes a computer such as, for example, a processor in downhole controller 418 and/or a processor in surface controller 412, to implement the methods of the present invention.
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Abstract
Description
Claims
Applications Claiming Priority (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US79065706P | 2006-04-10 | 2006-04-10 | |
US79061506P | 2006-04-10 | 2006-04-10 | |
US11/696,537 US7445934B2 (en) | 2006-04-10 | 2007-04-04 | System and method for estimating filtrate contamination in formation fluid samples using refractive index |
PCT/US2007/008392 WO2007120553A2 (en) | 2006-04-10 | 2007-04-05 | System and method for estimating filtrate contamination in formation fluid samples using refractive index |
Publications (2)
Publication Number | Publication Date |
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EP2005154A2 true EP2005154A2 (en) | 2008-12-24 |
EP2005154A4 EP2005154A4 (en) | 2012-02-22 |
Family
ID=38610081
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
EP07754843A Ceased EP2005154A4 (en) | 2006-04-10 | 2007-04-05 | System and method for estimating filtrate contamination in formation fluid samples using refractive index |
Country Status (4)
Country | Link |
---|---|
EP (1) | EP2005154A4 (en) |
BR (1) | BRPI0709988A2 (en) |
NO (1) | NO20084324L (en) |
WO (1) | WO2007120553A2 (en) |
Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2000050876A1 (en) * | 1999-02-23 | 2000-08-31 | Schlumberger Limited | Analysis of downhole formation fluid contaminated by oil-based mud |
US20030071988A1 (en) * | 2001-10-11 | 2003-04-17 | Baker Hughes Incorporated | Real-time on-line sensing and control of mineral scale deposition from formation fluids |
US20030163259A1 (en) * | 2002-02-27 | 2003-08-28 | Baker Hughes Incorporated | Method and apparatus for quantifying progress of sample clean up with curve fitting |
US20050262936A1 (en) * | 2004-05-26 | 2005-12-01 | Baker Hughes Incorporated | System and method for determining formation fluid parameters using refractive index |
Family Cites Families (5)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
GB9415962D0 (en) * | 1994-08-06 | 1994-09-28 | Schlumberger Ltd | Multiphase fluid component discrimination |
US6016191A (en) * | 1998-05-07 | 2000-01-18 | Schlumberger Technology Corporation | Apparatus and tool using tracers and singles point optical probes for measuring characteristics of fluid flow in a hydrocarbon well and methods of processing resulting signals |
US6683681B2 (en) * | 2002-04-10 | 2004-01-27 | Baker Hughes Incorporated | Method and apparatus for a downhole refractometer and attenuated reflectance spectrometer |
US6927846B2 (en) * | 2003-07-25 | 2005-08-09 | Baker Hughes Incorporated | Real-time on-line sensing and control of emulsions in formation fluids |
US7283220B2 (en) * | 2004-03-24 | 2007-10-16 | Fujitsu Limited | Methods and apparatuses for measuring the refractive index and other optical properties of liquids, gels, and solids |
-
2007
- 2007-04-05 BR BRPI0709988-6A patent/BRPI0709988A2/en not_active Application Discontinuation
- 2007-04-05 EP EP07754843A patent/EP2005154A4/en not_active Ceased
- 2007-04-05 WO PCT/US2007/008392 patent/WO2007120553A2/en active Application Filing
-
2008
- 2008-10-15 NO NO20084324A patent/NO20084324L/en not_active Application Discontinuation
Patent Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2000050876A1 (en) * | 1999-02-23 | 2000-08-31 | Schlumberger Limited | Analysis of downhole formation fluid contaminated by oil-based mud |
US20030071988A1 (en) * | 2001-10-11 | 2003-04-17 | Baker Hughes Incorporated | Real-time on-line sensing and control of mineral scale deposition from formation fluids |
US20030163259A1 (en) * | 2002-02-27 | 2003-08-28 | Baker Hughes Incorporated | Method and apparatus for quantifying progress of sample clean up with curve fitting |
US20050262936A1 (en) * | 2004-05-26 | 2005-12-01 | Baker Hughes Incorporated | System and method for determining formation fluid parameters using refractive index |
Non-Patent Citations (1)
Title |
---|
See also references of WO2007120553A2 * |
Also Published As
Publication number | Publication date |
---|---|
BRPI0709988A2 (en) | 2011-08-02 |
EP2005154A4 (en) | 2012-02-22 |
WO2007120553A3 (en) | 2008-09-18 |
WO2007120553A2 (en) | 2007-10-25 |
NO20084324L (en) | 2008-11-07 |
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