US20180245465A1 - Contamination estimation of formation samples - Google Patents

Contamination estimation of formation samples Download PDF

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Publication number
US20180245465A1
US20180245465A1 US15/565,592 US201615565592A US2018245465A1 US 20180245465 A1 US20180245465 A1 US 20180245465A1 US 201615565592 A US201615565592 A US 201615565592A US 2018245465 A1 US2018245465 A1 US 2018245465A1
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Prior art keywords
density
contamination
mud filtrate
formation fluid
sample
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US15/565,592
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English (en)
Inventor
Waqar Ahmad KHAN
Mehdi Azari
Abbas Sami Eyuboglu
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
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Assigned to HALLIBURTON ENERGY SERVICES, INC. reassignment HALLIBURTON ENERGY SERVICES, INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: EYUBOGLU, ABBAS SAMI, KHAN, Waqar Ahmad, AZARI, MEHDI
Publication of US20180245465A1 publication Critical patent/US20180245465A1/en
Abandoned legal-status Critical Current

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
    • E21B49/081—Obtaining fluid samples or testing fluids, in boreholes or wells with down-hole means for trapping a fluid sample
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/005—Testing the nature of borehole walls or the formation by using drilling mud or cutting data
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • 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
    • E21B49/086—Withdrawing samples at the surface
    • 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—Raw oil, drilling fluid or polyphasic mixtures
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N9/00—Investigating density or specific gravity of materials; Analysing materials by determining density or specific gravity
    • G01N9/32—Investigating density or specific gravity of materials; Analysing materials by determining density or specific gravity by using flow properties of fluids, e.g. flow through tubes or apertures
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N9/00—Investigating density or specific gravity of materials; Analysing materials by determining density or specific gravity
    • G01N9/36—Analysing materials by measuring the density or specific gravity, e.g. determining quantity of moisture
    • E21B2049/085—
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • 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

Definitions

  • the present disclosure relates generally to testing and evaluation of subterranean or subsea formation fluids or samples, and more specifically (although not necessarily exclusively), to systems and methods for improving the contamination estimation of samples using a formation tester.
  • a representative sample of the reservoir fluid may be captured for detailed analysis.
  • a sample of the reservoir fluid may be obtained by lowering a tool having a sampling chamber into the wellbore at a predetermined or sampling depth and fluid is allowed to flow into the sampling chamber. After the sample is collected, the tool may be withdrawn from the wellbore so that the sample of reservoir fluid may be analyzed.
  • Fluid analysis is possible using pump-out formation testers that provide downhole measurements of certain fluid properties and enable collection of a large number of representative samples stored at downhole conditions.
  • a wellbore is filled with a drilling fluid, for example, a mud.
  • the drilling fluid may be water-based or oil-based, is used as a lubricant and aids in the removal of cuttings from the wellbore.
  • the drilling fluid also is used to maintain a pressure.
  • Hydrocarbons contained in subterranean formations are usually at a high pressure. Standard overbalanced drilling techniques require that the hydrostatic pressure in the wellbore exceed the formation pressure, thereby preventing formation or reservoir fluids from flowing uncontrolled into the wellbore.
  • the hydrostatic pressure of the drilling fluid is greater than pressure of surrounding formation, a portion of the drilling fluid known commonly as the mud filtrate will tend to penetrate the surrounding formation.
  • the fluid in the formation close to the wellbore will be a mixture of this mud filtrate and the reservoir fluid or formation fluid.
  • the presence of the mud filtrate in the reservoir fluid can interfere with attempts to sample and analyze the reservoir fluid.
  • the first samples of reservoir fluid pumped may comprise primarily mud filtrate, with the amount of mud filtrate in the mixture typically decreasing as pumped volume increases.
  • pumping is continued for a period of time before the collection of the fluid sample. Obtaining representative reservoir fluid samples with minimum rig time to determine accurate reservoir fluid properties and contamination while sampling with a formation tester may result in a reduction of overall costs and conservation of resources.
  • FIG. 1 is a schematic diagram of an apparatus for transferring or retrieving material in a wellbore, according to one or more aspects of the present disclosure.
  • FIG. 2 is a diagram illustrating an example information handling system, according to one or more aspects of the present disclosure.
  • FIG. 3 is a flowchart of a method of contamination estimation, according to one or more aspects of the present disclosure.
  • FIG. 4 is a plot illustrating density of formation fluid versus time, according to one or more aspects of the present disclosure.
  • FIG. 5 is a plot illustrating pump rate versus time, according to one or more aspects of the present disclosure.
  • FIG. 6 is a plot illustrating density of the formation fluid versus exponential function of time, according to one or more aspects of the present disclosure.
  • FIG. 7 is a plot illustrating density of formation fluid versus time at a constant pump rate, according to one or more aspects of the present disclosure.
  • FIG. 8 is a plot illustrating constant pump rate versus time, according to one or more aspects of the present disclosure.
  • FIG. 9 is a plot illustrating density of the formation fluid versus exponential function of time filtered at a constant rate, according to one or more aspects of the present disclosure.
  • Certain aspects and features of the present disclosure relate to contamination estimation of reservoir samples collected via a formation tester.
  • Some methods of contamination estimation may inherently have numerous uncertainties. For example, the density of the formation fluid filtrate is not known. This may lead to inaccurate contamination estimation as errors may exceed 100% in contamination estimation. Also, the fitting of the trend curve may be user dependent which results in a variety of contamination estimates. By accurately estimating contamination, costs of a given operation may be reduced and resources at a well or job site may be conserved.
  • an information handling system may include any instrumentality or aggregate of instrumentalities operable to compute, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes.
  • an information handling system may be a personal computer, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price.
  • the information handling system may include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, ROM, and/or other types of nonvolatile memory.
  • Additional components of the information handling system may include one or more disk drives, one or more network ports for communication with external devices as well as various input and output (I/O) devices, such as a keyboard, a mouse, and a video display.
  • the information handling system may also include one or more buses operable to transmit communications between the various hardware components.
  • the information handling system may also include one or more interface units capable of transmitting one or more signals to a controller, actuator, or like device.
  • a non-transitory computer-readable media may include any instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a period of time.
  • Computer-readable media may include, for example, without limitation, storage media such as a direct access storage device (for example, a hard disk drive or floppy disk drive), a sequential access storage device (for example, a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory; as well as communications media such wires, optical fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or any combination of the foregoing.
  • storage media such as a direct access storage device (for example, a hard disk drive or floppy disk drive), a sequential access storage device (for example, a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory
  • FIG. 1 is a schematic diagram of an apparatus 10 for transferring or retrieving material in a wellbore 30 .
  • apparatus 10 illustrates a system for transferring material from a surface-located hydrocarbon well site 12 and retrieving material from a surface-located hydrocarbon well site 12 .
  • the well site 12 is located over a hydrocarbon bearing formation 14 comprising a hydrocarbon reservoir 52 , which is located below a ground surface 16 .
  • well site 12 is illustrated at a ground surface 16
  • the present disclosure contemplates any one or more embodiments implemented at a well site at any location, including, at sea above a subsea hydrocarbon bearing formation.
  • the wellbore 30 is formed through various earth strata including the formation 14 .
  • a pipe or casing 32 is insertable into the wellbore 30 and may be cemented within the wellbore 30 by cement 34 .
  • a pumping system 42 according to one or more aspects of the present disclosure is located at the well site 12 .
  • the pumping system 42 may be configured to transfer material, such as reservoir, formation or production fluid, out of the wellbore 30 from, for example, reservoir 52 .
  • a formation tester tool 50 is lowered into the wellbore 30 via a conveyance device 48 .
  • formation tester tool 50 or any other downhole tool may comprise one or more sensors 54 .
  • the one or more sensors 54 measure one or more properties of downhole fluid (such as formation fluid or drilling fluid) including, but not limited to, density, gas/oil ratio (GOR), condensate/gas ratio (CGR), capacitance, temperature, pressure, one or more gases (for example, methane (C1), ethane (C2), propane (C3), butane (C4), pentane (C5)), one or more hydrocarbon molecules (for example, C6+), resistivity, dielectric, viscosity, and optical sensor data.
  • Any one or more sensors 54 may be sensitive to different types of downhole fluids such as resistivity and dielectric for water-based mud (“WBM”) contamination, and density and T1 log mean for oil-based mud (“OBM”) contamination.
  • a formation tester tool 50 or any other downhole tool may comprise any one or more sensors 54 sensitive to any one or more different types of downhole fluids.
  • Conveyance device 48 may comprise a wireline, slickline, coiled tubing, jointed tubing or any other conveyance device or combination thereof.
  • Formation tester tool 50 may collect one or more formation fluid samples from wellbore 30 .
  • any one or more formation fluid samples collected may be analyzed by control system 44 utilizing any one or more embodiments or aspects of the present disclosure.
  • control system 44 may be located at the well site 12 (as illustrated) or remote from the well site 12 .
  • control system 44 may comprise one or more information handling systems comprising one or more programs or instructions, such as the information handling system 200 described with respect to FIG. 2 .
  • control system 44 controls the operation of formation tester tool 50 and may process data received from the formation tester tool 50 .
  • FIG. 2 is a diagram illustrating an example information handling system 200 , according to one or more aspects of the present disclosure.
  • the control system 44 may take a form similar to the information handling system 200 or include one or more components of information handling system 200 .
  • a processor or central processing unit (CPU) 201 of the information handling system 200 is communicatively coupled to a memory controller hub (MCH) or north bridge 202 .
  • the processor 201 may include, for example a microprocessor, microcontroller, digital signal processor (DSP), application specific integrated circuit (ASIC), or any other digital or analog circuitry configured to interpret and/or execute program instructions and/or process data.
  • DSP digital signal processor
  • ASIC application specific integrated circuit
  • Processor 201 may be configured to interpret and/or execute program instructions or other data retrieved and stored in any memory such as memory 203 or hard drive 207 .
  • Memory 203 may include read-only memory (ROM), random access memory (RAM), solid state memory, or disk-based memory.
  • Each memory module may include any system, device or apparatus configured to retain program instructions and/or data for a period of time (for example, computer-readable non-transitory media). For example, instructions from a software or application may be retrieved and stored in memory 203 , for example, a non-transitory memory, for execution by processor 201 .
  • FIG. 2 shows a particular configuration of components of information handling system 200 .
  • components of information handling system 200 may be implemented either as physical or logical components.
  • functionality associated with components of information handling system 200 may be implemented in special purpose circuits or components.
  • functionality associated with components of information handling system 200 may be implemented in configurable general purpose circuit or components.
  • components of information handling system 200 may be implemented by configured computer program instructions.
  • Memory controller hub 202 may include a memory controller for directing information to or from various system memory components within the information handling system 200 , such as memory 203 , storage element 206 , and hard drive 207 .
  • the memory controller hub 202 may be coupled to memory 203 and a graphics processing unit (GPU) 204 .
  • Memory controller hub 202 may also be coupled to an I/O controller hub (ICH) or south bridge 205 .
  • I/O controller hub 205 is coupled to storage elements of the information handling system 200 , including a storage element 206 , which may comprise a flash ROM that includes a basic input/output system (BIOS) of the computer system.
  • I/O controller hub 205 is also coupled to the hard drive 207 of the information handling system 200 .
  • I/O controller hub 205 may also be coupled to a Super I/O chip 208 , which is itself coupled to several of the I/O ports of the computer system, including keyboard 209 and mouse 210 .
  • control system 44 may comprise an information handling system 200 with at least a processor and a memory device coupled to the processor that contains a set of instructions that when executed cause the processor to perform certain actions.
  • the information handling system may include a non-transitory computer readable medium that stores one or more instructions where the one or more instructions when executed cause the processor to perform certain actions.
  • an information handling system may include any instrumentality or aggregate of instrumentalities operable to compute, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes.
  • an information handling system may be a computer terminal, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price.
  • the information handling system may include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, read only memory (ROM), and/or other types of nonvolatile memory.
  • Additional components of the information handling system may include one or more disk drives, one or more network ports for communication with external devices as well as various input and output (I/O) devices, such as a keyboard, a mouse, and a video display.
  • the information handling system may also include one or more buses operable to transmit communications between the various hardware components.
  • FIG. 3 is a flowchart of a method of contamination estimation, according to one or more aspects of the present disclosure. With respect to the description of FIG. 3 , references are made to one or more elements of FIGS. 1 and 2 .
  • a portion of the drilling fluid filtrate may penetrate into the formation or the reservoir 52 .
  • To properly evaluate a reservoir a representative sample of reservoir fluid is required. High overburden pressure may result in an invasion of drilling fluid into the reservoir which displaces the reservoir fluid. Collection of a representative reservoir fluid may require an estimation of a contamination of the reservoir (for example, contamination of the pumped reservoir fluid) before sampling.
  • formation fluid may comprise drilling fluid, reservoir fluid and any other downhole material or fluid.
  • the formation fluid may be pumped out until a sample of reservoir fluid may be collected.
  • the sample of reservoir fluid may be collected when a contamination of the formation fluid is at or below a threshold level.
  • a mud filtrate sample is collected.
  • the mud filtrate sample may be collected at any time during a well services or production operation at the well site 12 .
  • the mud filtrate sample is collected from a mixer, blender, container, tank or any other storage unit or dispenser of the drilling fluid at the surface 16 .
  • a filter press may be used to extract the mud filtrate sample from a collected drilling fluid sample.
  • the drilling fluid sample may be collected from a subsurface location and once retrieved to the surface 16 the mud filtrate sample may be extracted.
  • an information handling system may actuate collection of the mud filtrate sample, for example, by transmitting a signal to a device to cause the device to collect the mud filtrate sample.
  • the surface density of the mud filtrate sample is determined.
  • one or more characteristics of the mud filtrate sample are determined.
  • a mud filtrate characteristic may comprise any one or more of type of material (for example, any one or more of methane or any other gas, bentonite, oil, one or more synthetic fluids, water, potassium formate or any other material or combination thereof), temperature, density, viscosity, thickness, toughness, slickness or lubricity, permeability, or any other property.
  • the mud filtrate sample is processed by a gas chromatograph to determine a chemical composition of the mud filtrate sample.
  • the downhole density of the mud filtrate sample is estimated based, at least in part, on the one or more characteristics of the mud filtrate sample determined at step 306 and the surface density of the mud filtrate sample determined at step 304 .
  • equation of state modeling may be used to identify at a certain pressure and temperature how the mud filtrate will behave downhole, for example, the estimated density of the mud filtrate downhole.
  • correlation of the one or more characteristics may be used to estimate a downhole mud filtrate density for a given temperature and pressure downhole.
  • a downhole tool such as a formation tester tool 50
  • density of the formation fluid is determined.
  • density of the formation fluid may be determined as the formation fluid is pumped from the wellbore 30 .
  • the formation fluid density may be determined continuously, at any predetermined time interval, in real-time, or at any other time interval as the formation fluid is pumped from the wellbore 30 .
  • the formation fluid may comprise reservoir fluid (such as hydrocarbons), mud filtrate, water, any other type of formation fluid or material, or any combination thereof.
  • the density of the formation fluid may be determined based on one or more density measurements from one or more sensors 54 .
  • a control system 44 retrieves the one or more density measurements from the one or more sensors 54 , the formation tester tool 50 , any other downhole tool, or any combination thereof and determines the density of the formation fluid for a given instance of time.
  • an analysis may be performed or a plot may be generated of the formation fluid density measurements versus exponential time.
  • density of the formation fluid is plotted for intervals of time according to one or more aspects of the present disclosure.
  • the y-axis or vertical axis indicates the determined density of the formation fluid in grams per cubic centimeter (g/cc) and the x-axis or horizontal axis (labeled “time (hr)”) indicates time associated with the determined density in hours ranging from 0 to 2.6 hours.
  • a constant pump rate is determined.
  • a correlation may be made between the determined pump rate at each interval of time to determine the constant pumping rate for a given operation, snapshot of time or predetermined timed interval.
  • the pumping rate may be determined using any one or more formulas or methods known in the field of art or as provided in material or instructions associated with a given pump.
  • FIG. 5 illustrates a plot of determined pumping rates versus time according to one or more aspects of the present disclosure.
  • the y-axis or vertical axis indicates the rate of pumping of the formation fluid from the wellbore 30 cubic centimeters per second (cc/s) and the x-axis or horizontal axis (labeled “time (hr)”) indicates time in hours associated with the determined pump rate ranging from 0 to 2.6 hours.
  • FIG. 6 illustrates the density of the formation fluid versus exponential function of time.
  • the y-axis or vertical axis (labeled “Fluid Density”) indicates the density of formation fluid and the x-axis or horizontal axis (labeled “Exp Function”) indicates an exponential function of time.
  • the constant pumping rate may be determined by determining a pumping rate at which a plurality of pumping rates associated with a predetermined time interval are within a range of deviation of each other. For example, as illustrated in FIG. 5 , if the range of deviation is five for an interval of time of 2.5 hours then the pumping rate is a range between 1 and 45 during time at or about 0.4 hours to at or about 2.5 hours.
  • the constant pumping rate may then be determined by using any analysis or modeling including, but not limited to, mean, median, average or any other mathematical model, or combination thereof.
  • the constant pumping rate may be determined to be 42.5 when the pumping rate is within a range of 40 to 45.
  • FIG. 7 is a plot illustrating density of formation fluid versus time at a constant pump rate, according to one or more aspects of the present disclosure.
  • FIG. 7 illustrates a range of determined density versus time from FIG. 4 at a finer scale on the y-axis so that deviations in the determined densities associated with the range of time correlating to the determined constant pump rate are highlighted.
  • FIG. 7 illustrates a trend over time as opposed to a determination of exact fluid density values.
  • FIG. 8 is a plot illustrating constant pumping rate versus time, according to one or more aspects of the present disclosure.
  • FIG. 8 illustrates a range of pumping rates versus time from FIG. 5 at a finer scale on the y-axis so that deviations in the determined pumping rates associated with the range of time correlating to the determined constant pump rate are highlighted.
  • FIG. 8 illustrates a trend over time as opposed to a determination of exact pump rate.
  • a plot is generated or an analysis is performed of the determined plurality of fluid densities associated with the determined constant pumping rate versus an exponential function of time corresponding to the constant pumping rate.
  • a best fit linear regression is determined.
  • FIG. 9 illustrates a plot of determined fluid density versus the exponential function of time corresponding to the constant pumping rate.
  • a best fit linear regression line is indicated at 910 .
  • a clean fluid density is determined based, at least in part, on the determined density of the formation fluid at the constant pumping rate for an interval of time. For example, a linear regression is extrapolated for the determined density of the formation fluid versus exponential time corresponding to the constant pumping rate.
  • the linear regression is extrapolated, for example, for a time “t” where “t” approaches infinity.
  • the clean fluid density where the exponential function of time approaches or is zero correlates to a density of at or about 0.756.
  • the contamination of the formation fluid is estimated based, at least in part, on the clean fluid density.
  • an estimated pump-out time may be determined based, at least in part, on the estimated contamination and a trend of the estimated contamination.
  • a contamination threshold may be indicative of or correspond to 0.20 (20%), 0.05 (5%) or any other value above or below.
  • a reservoir fluid sample may be collected.
  • one or more production operations or a well servicing operation may be altered based, at least in part, on the collected reservoir fluid sample.
  • the collected reservoir sample may be compared to another reservoir fluid sample from a nearby well to determine likelihood that the two wells are connected.
  • one or more of the facilities design (for example, one or more of separate design, flow line design, injection program for well for asphalt treatment, general design of the wellbore surface facilities, or any other parameter of facilities design), flow assurance or reserve estimation may be altered based, at least in part, on the collected reservoir fluid sample.
  • another well may be drilled based, at least in part, on the collected reservoir fluid sample.
  • the reservoir fluid sample may be sent to a laboratory for further testing or evaluation.
  • any one or more steps of FIG. 3 may not be implemented or may be implemented in any order.
  • any one or more measurements from any one or more sensors positioned on or deployed within formation tester tool 50 may be utilized to determine the contamination estimation in lieu of the downhole density.
  • a method for contamination estimation comprises collecting a mud filtrate sample, determining a surface density of the mud filtrate sample, estimating downhole density of the mud filtrate sample based, at least in part, on the surface density, determining a plurality of formation fluid densities for a period of time, determining the constant pumping rate, filtering the determined formation fluid density based, at least in part, on the constant pumping rate, determining a clean fluid density based, at least in part, on a linear regression of the filtered determined formation fluid density versus an exponential function of time, estimating a contamination based, at least in part, on the clean fluid density, comparing the estimated contamination to a contamination threshold and collecting a reservoir fluid sample based, at least in part, on the comparison.
  • the method of contamination estimation comprises receiving one or more formation fluid density measurements from one or more sensors, wherein the determined formation fluid density is based on the one or more formation fluid density measurements. In one or more embodiments, the method of contamination estimation further comprises positioning a formation tester tool within a wellbore, wherein the formation tester tool collects the reservoir fluid sample. In one or more embodiments, the method of contamination estimation further comprises determining one or more mud filtrate characteristics of the mud filtrate sample, wherein the estimated downhole density of the mud filtrate sample is based, at least in part, on at least one of the one or more mud filtrate characteristics.
  • determining the constant pumping rate comprises determining a pumping rate at which a plurality of pumping rates associated with a predetermined interval of time are within a range of deviation.
  • the clean fluid density is determined based, at least in part, on extrapolation of the linear regression for a time that approaches infinity.
  • estimating the contamination comprises calculating a first calculated density, calculating a second calculated density and dividing the first calculated density by the second calculated density, wherein calculating the first calculated density comprises subtracting from a real-time formation fluid density measurement the clean fluid density, and wherein calculating the second calculated density comprises subtracting from the estimated mud filtrated density the clean fluid density.
  • the intensifier comprises a plurality of intensifiers, and wherein distribution of the hydraulic fluid to each of the plurality of intensifiers is based, at least in part, on a fuel map.
  • non-transitory computer-readable medium storing one or more executable instructions that, when executed, cause one or more processors to actuate collection of a mud filtrate sample, determine a surface density of the mud filtrate sample, estimate downhole density of the mud filtrate sample based, at least in part, on the surface density, determine a plurality of formation fluid densities for a period of time, determining a constant pumping rate, filter the determined formation fluid density based, at least in part, on the constant pumping rate, determine a clean fluid density based, at least in part, on a linear regression of the filtered determined formation fluid density versus an exponential function of time, estimate a contamination based, at least in part, on the clean fluid density, compare the estimated contamination to a contamination threshold, and collect a reservoir fluid sample based, at least in part, on the comparison.
  • the one or more executable instructions that, when executed, further cause the one or more processors to determine one or more mud filtrate characteristics of the mud filtrate sample, wherein the estimated downhole density of the mud filtrate sample is based, at least in part, on at least one of the one or mud filtrate characteristics.
  • determining a constant pumping rate comprises determining a pumping rate at which a plurality of pumping rates associated with a predetermined interval of time are within a range of deviation.
  • the clean fluid density is determined based, at least in part, on extrapolation of the linear regression for a time that approaches infinity.
  • estimating the contamination comprises calculating a first calculated density, calculating a second calculated density and dividing the first calculated density by the second calculated density, wherein calculating the first calculated density comprises subtracting from a real-time formation fluid density measurement the clean fluid density, and wherein calculating the second calculated density comprises subtracting from the estimated mud filtrated density the clean fluid density.
  • the intensifier comprises a plurality of intensifiers, and wherein distribution of the hydraulic fluid to each of the plurality of intensifiers is based, at least in part, on a fuel map. In one or more embodiments, the intensifier comprises a plurality of intensifiers, and wherein distribution of the hydraulic fluid to each of the plurality of intensifiers is based, at least in part, on a fuel map.
  • a system for contamination estimation comprises a mud filtrate sample, a processor, a non-transitory memory coupled to the processor, the non-transitory memory comprising one or more instructions that, when executed by the processor, cause the processor to determine a surface density of the mud filtrate sample, estimate downhole density of the mud filtrate sample based, at least in part, on the surface density, determine a plurality of formation fluid densities for a period of time, determine a constant pumping rate, filter the determined formation fluid density based, at least in part, on the constant pumping rate, determine a clean fluid density based, at least in part, on a linear regression of the filtered determined formation fluid density versus an exponential function of time, estimate a contamination based, at least in part, on the clean fluid density, compare the estimated contamination to a contamination threshold and collect a reservoir fluid sample based, at least in part, on the comparison.
  • estimating the contamination comprises calculating a first calculated density, calculating a second calculated density and dividing the first calculated density by the second calculated density, wherein calculating the first calculated density comprises subtracting from a real-time formation fluid density measurement the clean fluid density, and wherein calculating the second calculated density comprises subtracting from the estimated mud filtrated density the clean fluid density.

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