Method and system for measurement of reservoir fluid properties

Patent metadata

Field	Value
Publication number	US-9546959-B2
Application number	US-201113234621-A
Country	US
Kind code	B2
Filing date	Sep 16, 2011
Priority date	Sep 16, 2011
Publication date	Jan 17, 2017
Grant date	Jan 17, 2017

Abstract

A method and system that characterizes hydrogen sulfide in petroleum fluid employs a tool that includes a fluid analyzer for performing fluid analysis (including optical density (OD) for measuring carbon dioxide concentration) of a live oil sample, and a storage chamber for an analytical reagent fluidly coupled to a measurement chamber. An emulsion from fluid of the sample and the reagent is produced into the measurement chamber. The reagent changes color due to pH changes arising from chemical reactions between components of the sample and the reagent in the measurement chamber. The tool includes an optical sensor system that measures OD of a water phase of the emulsion at one or more determined wavelengths. The pH of the water phase is derived from such OD measurements. The pH of the water phase and the carbon dioxide concentration in the sample is used to calculate hydrogen sulfide concentration in the sample.

First claim

What is claimed is:

1. A method of characterizing hydrogen sulfide in petroleum fluid of a reservoir traversed by a subterranean wellbore, the method comprising:
(a) locating a downhole apparatus within the subterranean wellbore, the downhole apparatus including a fluid admitting assembly for acquiring a live oil sample of the petroleum fluid of the reservoir and a fluid analyzer for performing downhole fluid analysis of the live oil sample, wherein the fluid analyzer comprises a storage chamber fluidly coupled to a measurement chamber, wherein the storage chamber stores an analytical reagent that can be supplied to the measurement chamber, and a flowline that holds the live oil sample, wherein the flowline is fluidly coupled to the measurement chamber;
(b) using the fluid admitting assembly to acquire a live oil sample of the petroleum fluid of the reservoir;
(c) using the fluid analyzer to perform downhole fluid analysis of the live oil sample to determine properties of the live oil sample, the properties including concentration of carbon dioxide in the live oil sample;
(d) producing an oil-water emulsion in the measurement chamber by mixing the fluid of the live oil sample and the analytical reagent using a fluid agitator positioned in the measurement chamber, wherein the oil-water emulsion includes fluid of the live oil sample and the analytical reagent supplied from the storage chamber, wherein the analytical reagent changes color due to changes of pH that arise from chemical reactions between components of the live oil sample and the analytical reagent in the measurement chamber;
(e) allowing for separation of the oil-water emulsion into an oil phase and a water phase, the oil phase including the fluid of the live oil sample, and the water phase including the analytical reagent;
(f) providing an optical sensor that measures optical density of the water phase at one or more determined wavelengths, wherein the optical sensor is disposed about a portion of the measurement chamber that holds the water phase, and wherein a bottom portion of the measurement chamber holds the water phase;
(g) determining via a data processing system a measurement of pH of the water phase based upon the optical density measured in (f);
(h) selecting via the data processing system a thermodynamic model that includes terms for pH of the water phase, concentrations of carbon dioxide components, and hydrogen sulfide components that are dissolved in the water phase, wherein contribution of the carbon dioxide components to the pH of the water phase is determined from the concentration of carbon dioxide in the live oil sample as measured in (c); and
(i) calculating via the data processing system a concentration of hydrogen sulfide in the live oil sample using the measurement of pH of the water phase of (g), the concentration of carbon dioxide in the live oil sample of (c), and the selected thermodynamic model.

2. A method according to claim 1 , wherein:
the concentration of hydrogen sulfide in the live oil sample is derived from partial pressure of hydrogen sulfide in the oil phase and the total pressure of the oil phase, and wherein the partial pressure of hydrogen sulfide in the oil phase is calculated from the concentration of hydrogen sulfide in the water phase and Henry's constant for hydrogen sulfide.

3. A method according to claim 1 , wherein:
the thermodynamic model utilizes equilibrium constants to calculate the contribution of carbon dioxide components and hydrogen sulfide components to ion concentration in the water phase, wherein the equilibrium constants are defined as a function of temperature.

4. A method according to claim 1 , wherein:
the concentration of hydrogen sulfide in the live oil sample is represented by a unit of measure selected from the group consisting of: mole fraction, mole percentage, mass fraction, weight percentage, ppm, and mol/unit volume.

5. A method according to claim 1 , further comprising measuring temperature and pressure of the water phase for use in calculations of the thermodynamic model.

6. A method according to claim 1 , wherein the oil phase and water phase of the oil-water emulsion separate in the measurement chamber with the water phase filling the bottom portion of the measurement chamber.

7. A method according to claim 1 , wherein:
a first valve is fluidly coupled between the measurement chamber and the flowline, and a second valve is fluidly coupled between the measurement chamber and the storage chamber, wherein the first and second valves are operated to isolate a volume of the measurement chamber for producing the oil-water emulsion in the measurement chamber.

8. A method according to claim 1 , wherein the storage chamber employs a displaceable piston operable to inject the analytical reagent from the storage chamber into the measurement chamber.

9. A method according to claim 8 , wherein the displaceable piston is further operable to draw fluids from the live oil sample into the measurement chamber.

10. A method according to claim 1 , wherein the fluid analyzer includes a spectrometer for measuring optical density of the live oil sample at a plurality of predetermined wavelengths, and for determining the concentration of carbon dioxide in the live oil sample based upon the optical density of the live oil sample at one or more of the predetermined wavelengths.

11. A method according to claim 1 , wherein the downhole apparatus is a downhole tool positionable at multiple stations with the subterranean wellbore.

12. A method according to claim 1 , wherein the downhole apparatus is a sensor disposed at a fixed position within the subterranean wellbore.

13. A method of characterizing hydrogen sulfide in petroleum fluid of a reservoir, the method comprising:
(a) acquiring a live oil sample of the petroleum fluid of the reservoir;
(b) using a fluid analyzer to perform fluid analysis of the live oil sample to determine properties of the live oil sample, the properties including concentration of carbon dioxide in the live oil sample, wherein the fluid analyzer comprises a storage chamber fluidly coupled to a measurement chamber, and a flowline that holds the live oil sample;
(c) producing an oil-water emulsion in the measurement chamber fluidly coupled to the flowline and the storage chamber that stores an analytical reagent that can be supplied to the measurement chamber by mixing the fluid of the live oil sample and the analytical reagent using a fluid agitator positioned in the measurement chamber, wherein the oil-water emulsion includes fluid of the live oil sample and the analytical reagent supplied from the storage chamber, wherein the analytical reagent changes color due to changes of pH that arise from chemical reactions between components of the live oil sample and the analytical reagent in the measurement chamber;
(d) allowing for separation of the oil-water emulsion into an oil phase and a water phase, the oil phase including the fluid of the live oil sample, and the water phase including the analytical reagent;
(e) providing an optical sensor that measures optical density of the water phase at one or more determined wavelengths, wherein the optical sensor is disposed about a portion of the measurement chamber that holds the water phase, and wherein a bottom portion of the measurement chamber holds the water phase;
(f) determining via a data processing system a measurement of pH of the water phase based upon the optical density measured in (e);
(g) selecting via the data processing system a thermodynamic model that includes terms for pH of the water phase, concentrations of carbon dioxide components, and hydrogen s

Assignees

• Indo Kentaro
• Toribio Michael M
• Pan Shu
• Schlumberger Technology Corp

Inventors

• Indo Kentaro
• Toribio Michael M
• Pan Shu

Classifications

• G01N33/287

  Sulfur content · CPC title

• G01N21/80 Primary

  Indicating pH value · CPC title

• E21B49/10

  using side-wall fluid samplers or testers · CPC title

• E21B49/0875

  determining specific fluid parameters · CPC title

• E21B2049/085

  Fixed Constructions · mapped topic