Schlumberger Technology Corporation

Abdel Kharrat

Farshid Mostowfi

Yuesheng Cheng

Marc Schneider

Kentaro Indo

Shahnawaz Hossain Molla

Ahmed Hammami

Vincent Joseph Sieben

Philip Homewood

Joseph Samuel Baddeley

Oliver Clinton Mullins

Christopher Harrison

Robert Freedman

Matthew T Sullivan

Krishnamurthy Ganesan

Chengli Dong

Soraya Sofia Betancourt

Elizabeth Jennings Smythe

Michael O'Keefe

John Ratulowski

Francois Xavier Dubost

Simon Ivar Andersen

Moin Muhammad

Youxiang (Julian) Zuo

Jinglin Gao

Hussein Alboudwarej

Mohammed I Zougari

Jiasen Tan

A method and system are provided for detecting the wax appearance temperature (WAT) of a hydrocarbon fluid sample. The hydrocarbon fluid sample is run through a microfluidic channel at controlled temperatures while sensing the pressure drop across the channel. The WAT is determined by finding a temperature at which the pressure (drop) across the microfluidic channel caused by a temperature reduction of the hydrocarbon fluid sample does not stabilize over a given time interval, thereby establishing the WAT as being at that temperature or between that temperature and a previous higher temperature where the pressure (drop) stabilized over time.

Microfluidic determination of wax appearance temperature

A method and apparatus for analyzing solubility of asphaltenes of a hydrocarbon fluid sample involves a sequence of operations including: i) performing microfluidic mixing operations that form a mixture that includes the hydrocarbon fluid sample, a solvent that dissolves asphaltenes and a precipitant that precipitates asphaltenes; ii) using microfluidic processes that result in precipitation of asphaltenes from the mixture resulting from i); iii) performing microfluidic filtering operations that remove precipitated asphaltenes resulting from ii) and passes permeate; and iv) performing optical spectroscopy on the permeate resulting from iii). The operations of i)-iv) can be repeated over iterations that vary the amount of solvent relative to the precipitant in the mixture. These iterations can cause varying fractional precipitation of asphaltenes in each given iteration.

Automated method and apparatus to characterize solubility of asphaltenes of a hydrocarbon fluid sample utilizing microfluidics

A method for measuring saturate, aromatic, and resin fractions of a hydrocarbon fluid includes separating maltenes from the hydrocarbon fluid and separating saturate, aromatic, and resin fractions from the maltenes. The method further includes determining an optical density of each of the saturate, aromatic, and resin fractions at a predetermined wavelength and correlating the optical density of each of the saturate, aromatic, and resin fractions to predetermined data to determine each of the saturate, aromatic, and resin fractions.

Method for measuring fractions of hydrocarbon fluids using optical spectroscopy

A system for measuring asphaltene content of crude oil, includes a microfluidic chip, the microfluidic chip having a crude oil sample inlet port, a solvent port, a mixer and reactor section in fluid communication with the crude oil sample inlet port and the solvent port, and a filter in fluid communication with the mixer and reactor section, the filter having an inlet side and an outlet side, a waste port in fluid communication with the inlet side of the filter, and a product port in fluid communication with the outlet side of the filter. The system further includes an optical cell in fluid communication with the product port.

Microfluidic chip for measuring asphaltene content of crude oil

Apparatus and system for measuring asphaltene content of crude oil

An apparatus and a method including exposing a first fluid to a pre-filter, observing the first fluid, introducing a second fluid to the first fluid, exposing the first and second fluids to a filter, and observing the first and second fluids wherein the observing the first fluid and observing the first and second fluids comprise optical measurements and the first fluid comprises material from a subterranean formation. Some embodiments may compare the optical measurements of the first fluid and the first and second fluids and/or estimate the first fluid's likelihood of forming precipitants with other fluids and/or the first fluid's asphaltene content.

Apparatus and methods for determining commingling compatibility of fluids from different formation zones

A method for determining an asphaltene yield curve and an asphaltene flocculation point includes obtaining a crude oil sample and measuring an optical spectrum of the crude oil sample. A titrant is then mixed with the crude oil sample at different concentrations. At each concentration, precipitated asphaltenes are filtered from the mixture and the optical spectrum of the filtrate is measured. The optical spectrum of the filtrate is then subtracted from the optical spectrum of the crude oil sample. A fractional asphaltene precipitation is determined for each concentration of titrant. A flocculation point is determined corresponding to an inflection point in the fractional asphaltene precipitation for each concentration of titrant.

Method and apparatus for determining asphaltene yield and flocculation point of crude oil

A system for characterizing crude oil fractions includes a maltenes sample reservoir, a first solvent reservoir, a second solvent reservoir, and a third solvent reservoir. The system further includes a valve in fluid communication with the first solvent reservoir, the second solvent reservoir, and the third solvent reservoir and a pump in fluid communication with the valve. The system further includes a packed bed in fluid communication with the maltenes sample reservoir and the pump, a flowthrough cell in fluid communication with the packed bed, a spectrometer operably associated with the flowthrough cell, and a computer operably associated with the spectrometer. A method for characterizing crude oil fractions includes providing a maltene sample, eluting saturates, aromatics, and resins of the maltene sample, determining an optical density of each, and determining a concentration of each of the saturates, aromatics, and resins based upon optical densities over time for each.

System and method for characterizing crude oil fractions

A system for determining the asphaltene content of crude oil includes a first optical flow cell, a first spectrometer operably associated with the first optical flow cell, and a mixer in fluid communication with the first optical flow cell. The system further includes a crude oil injection/metering device configured to receive the crude oil, the crude oil injection/metering device being in fluid communication with the first optical flow cell; a titrant injection/metering device in fluid communication with the mixer, the titrant injection/metering device configured to receive a titrant; and a filtration unit in fluid communication with the mixer. The system further includes a second optical flow cell in fluid communication with the filtration unit, and a second spectrometer operably associated with the second optical flow cell.

System and method for determining the asphaltene content of crude oil

The viscosity &#x3b7; (in centipoise) of a heavy oil sample is determined according to an equation of the form ln where T is the temperature of the heavy oil, Tis the logarithmic mean of the Tdistribution of the sample obtainable from nuclear magnetic resonance (NMR) measurements, c'=1.0&#xb1;0.05, c&#x2033;=1.0&#xb1;0.04, &#x3b7;is the glass transition temperature viscosity of the heavy oil and a function of T, and C1 is a variable which is a constant for the heavy oil and is a function of T. Both C1 and &#x3b7;are considered functions of certain NMR values associated with the heavy oil sample, with &#x3b7;and C1 preferably estimated by empirically fitting data to the equations ln T=a&#x2032;+b&#x2032; ln &#x3b7;and ln T=a&#x2033;+b&#x2033;C1, where a&#x2032;, b&#x2032;, a&#x2033; and b&#x2033; are constants.

Methods for determining in situ the viscosity of heavy oil using nuclear magnetic resonance relaxation time measurements

A method and system for characterizing asphaltene gradients of a reservoir of interest and analyzing properties of the reservoir of interest based upon such asphaltene gradients. The analysis employs a correlation that relates insoluble asphaltene concentration to spectrophotometry measurement data measured at depth.

Methods and apparatus for analysis of downhole asphaltene gradients and applications thereof

Viscosity of heavy oil is determined in situ in a formation by making nuclear magnetic resonance (NMR) measurements in the formation, and then calculating viscosity according to an equation of the form where T is the temperature of the heavy oil sample, &#x3b7; is the viscosity, Tis the logarithmic mean of the Tdistribution spectrum of the sample, and a, b, and c are non-zero constants. Typically, constant b has a value between 5 and 7 and constant c has a value between &#x2212;0.7 and &#x2212;0.5.

Methods for determining in situ the viscosity of heavy oil

Compositions and methods of using same are described for negating asphaltene deposition in a formation, wellbore, near wellbore region, and production tubing. Compositions of the invention comprise an asphaltene solvent and a viscosity reducing agent, the asphaltene solvent and viscosity reducing agent present in a ratio so as to substantially reduce viscosity of an asphaltene-containing material while substantially negating deposition of asphaltenes either in a reservoir, in production tubing, or both when mixed or otherwise contacting the asphaltene-containing material. Methods of the invention comprise forcing a composition comprising an asphaltene solvent and a viscosity reducing agent to contact an asphaltene-containing hydrocarbon in an underground geologic formation, and producing from the formation a production composition comprising at least some of the treatment composition and at least some of the asphaltene-containing hydrocarbon under conditions sufficient to substantially negate deposition of asphaltenes in the formation.

Compositions and methods of using same in producing heavy oil and bitumen

A method for determining a wax appearance temperature of a fluid includes obtaining nuclear magnetic resonance (NMR) measurements of the fluid at a plurality of temperatures; deriving a NMR parameter from each of the NMR measurements; and determining the wax appearance temperature by analyzing the NMR parameter as a function of temperature. An apparatus for detecting wax appearance in a fluid includes a sample cell for holding a fluid for nuclear magnetic resonance (NMR) measurements at a plurality of temperatures; a temperature measuring device disposed proximate the sample cell; a magnet for polarizing molecules in the fluid in the sample cell; at least one radiofrequency (RF) coil for generating pulses of magnetic field and for detecting NMR signals; and circuitry for controlling and measuring the temperature of the fluid in the sample cell and for obtaining NMR measurements.

NMR measurement of wax appearance in fluids

A method for estimating a concentration of a substance in a test sample of formation fluid, comprising measuring an NMR parameter of a first sample of formation fluid to obtain a first measurement, adding a known quantity of the substance to the first sample to produce a modified sample, measuring the NMR parameter of the modified sample to obtain a second measurement; and determining a relation between the concentration of the substance and a function of the NMR parameter using the first and second measurements and the NMR parameter of the substance.

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Edmonton, Canada

Abdel Kharrat