Methods and apparatus for determining a viscosity of oil in a mixture

Methods and apparatus for determining a viscosity of oil in a mixture are disclosed herein. An example method includes determining water fractions of a mixture flowing into a downhole tool and determining viscosities of the mixture. The mixture includes water and oil. The example method also includes determining a viscosity of the oil based on the water fractions and the viscosities.

FIELD OF THE DISCLOSURE

This disclosure relates generally to mixtures and, more particularly, to methods and apparatus for determining a viscosity of oil in a mixture.

BACKGROUND OF THE DISCLOSURE

Formation fluid flowing from a subterranean formation into a downhole tool is often a mixture of oil and water. Generally, the mixture is unstable and, therefore, the oil and the water separate over time if the mixture is static. Generally, to determine a viscosity of the oil in the formation fluid, a sample of the formation fluid is stored in a container until the oil separates from the water, or a chemical demulsifier may be added to the mixture to cause the oil and the water to separate. The oil may then be removed from the container, and a viscosity of the oil may be determined.

SUMMARY

An example method disclosed herein includes determining water fractions of a mixture flowing into a downhole tool and determining viscosities of the mixture. The mixture includes water and oil. The example method also includes determining a viscosity of the oil based on the water fractions and the viscosities.

Another example method disclosed herein includes determining a viscosity of a flowing mixture as a function of a fraction of a dispersed phase of the mixture and extrapolating the fraction of the dispersed phase to zero.

DETAILED DESCRIPTION

One or more aspects of the present disclosure relate to determining a viscosity of oil in a mixture. In some examples, apparatus and methods disclosed herein are implemented in a downhole tool and/or wireline-conveyed tools such as a Modular Formation Dynamics Tester (MDT) of Schlumberger Ltd.

Example methods disclosed herein may include determining water fractions of a mixture flowing into a downhole tool and determining viscosities of the mixture. The mixture may include water and oil. In some examples, formation fluid in a subterranean formation may be a mixture including oil and water (i.e., a suspension and/or dispersion of water in oil or oil in water). As the formation fluid flows into the downhole or wireline-conveyed tool, water fractions of the formation fluid may decrease monotonically. The water fractions of the mixture may be determined by determining optical densities of the mixture. The viscosities of the mixture may be determined by increasing a stability or emulsification of the mixture (e.g., by agitating the mixture) and using a vibrating wire viscometer. The example methods may also include determining a viscosity of the oil based on the water fractions and the viscosities. The viscosity of the oil may be determined by determining a viscosity of the mixture as a function of the water fraction of the mixture and extrapolating the water fraction of the mixture to zero.

FIG. 1illustrates a wellsite system in which the present invention can be employed. The wellsite can be onshore or offshore. In this example system, a borehole11is formed in subsurface formations by rotary drilling in a manner that is well known. Embodiments can also use directional drilling, as will be described hereinafter.

A drill string12is suspended within the borehole11and has a bottom hole assembly100which includes a drill bit105at its lower end. The surface system includes platform and derrick assembly10positioned over the borehole11. The assembly10includes a rotary table16, kelly17, hook18and rotary swivel19. The drill string12is rotated by the rotary table16, energized by means not shown, which engages the kelly17at the upper end of the drill string12. The drill string12is suspended from the hook18, attached to a traveling block (also not shown), through the kelly17and the rotary swivel19, which permits rotation of the drill string12relative to the hook18. As is well known, a top drive system could alternatively be used.

In the example of this embodiment, the surface system further includes drilling fluid or mud26stored in a pit27formed at the well site. A pump29delivers the drilling fluid26to the interior of the drill string12via a port in the swivel19, causing the drilling fluid26to flow downwardly through the drill string12as indicated by the directional arrow8. The drilling fluid26exits the drill string12via ports in the drill bit105, and then circulates upwardly through the annulus region between the outside of the drill string and the wall of the borehole, as indicated by the directional arrows9. In this well known manner, the drilling fluid26lubricates the drill bit105and carries formation cuttings up to the surface as it is returned to the pit27for recirculation.

The bottom hole assembly100of the illustrated embodiment includes a logging-while-drilling (LWD) module120, a measuring-while-drilling (MWD) module130, a roto-steerable system and motor150, and drill bit105.

The LWD module120is housed in a special type of drill collar, as is known in the art, and can contain one or a plurality of known types of logging tools. It will also be understood that more than one LWD and/or MWD module can be employed, e.g. as represented at120A. (References, throughout, to a module at the position of120can alternatively mean a module at the position of120A as well.) The LWD module120includes capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment. In the present embodiment, the LWD module120includes a fluid sampling device.

The MWD module130is also housed in a special type of drill collar, as is known in the art, and can contain one or more devices for measuring characteristics of the drill string12and drill bit105. The MWD tool further includes an apparatus (not shown) for generating electrical power to the downhole system. This may include a mud turbine generator powered by the flow of the drilling fluid, it being understood that other power and/or battery systems may be employed. In the present embodiment, the MWD module130includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.

FIG. 2is a simplified diagram of a sampling-while-drilling logging device of a type described in U.S. Pat. No. 7,114,562, incorporated herein by reference in its entirety, utilized as the LWD tool120or part of an LWD tool suite120A. The LWD tool120is provided with a probe6for establishing fluid communication with a formation F and drawing fluid21into the tool, as indicated by the arrows. The probe6may be positioned in a stabilizer blade23of the LWD tool and extended therefrom to engage the borehole wall. The stabilizer blade23comprises one or more blades that are in contact with the borehole wall. Fluid drawn into the downhole tool using the probe6may be measured to determine, for example, pretest and/or pressure parameters. Additionally, the LWD tool120may be provided with devices, such as sample chambers, for collecting fluid samples for retrieval at the surface. Backup pistons81may also be provided to assist in applying force to push the drilling tool and/or the probe6against the borehole wall.

Referring toFIG. 3, shown is an example wireline tool300that may be another environment in which aspects of the present disclosure may be implemented. The example wireline tool300is suspended in a wellbore302from the lower end of a multiconductor cable304that is spooled on a winch (not shown) at the Earth's surface. At the surface, the cable304is communicatively coupled to an electronics and processing system306. The example wireline tool300includes an elongated body308that includes a formation tester314having a selectively extendable probe assembly316and a selectively extendable tool anchoring member318that are arranged on opposite sides of the elongated body308. Additional components (e.g.,310) may also be included in the tool300.

The extendable probe assembly316may be configured to selectively seal off or isolate selected portions of the wall of the wellbore302to fluidly couple to an adjacent formation F and/or to draw fluid samples from the formation F. Accordingly, the extendable probe assembly316may be provided with a probe having an embedded plate, as described above. The formation fluid may be expelled through a port (not shown) or it may be sent to one or more fluid collecting chambers326and328. In the illustrated example, the electronics and processing system306and/or a downhole control system are configured to control the extendable probe assembly316and/or the drawing of a fluid sample from the formation F.

FIG. 4illustrates a portion of an example downhole tool400that may be used to determine a viscosity of oil in a mixture. The example downhole tool400is a Modular Formation Dynamics Tester (MDT) of Schlumberger Ltd. The example downhole tool400includes a flowline402to receive formation fluid from a subterranean formation. The flowline402extends through a first fluid analyzer module404, a pump-out module (MRPO)406, and a second fluid analyzer module408. The MRPO406includes a pump (not shown) to extract the formation fluid from the subterranean formation and/or pump the formation fluid through the flowline402. In the illustrated example, the MRPO406includes at least one fluid agitator410(e.g., a check valve, a pump, a mixer, a flow area restriction, etc.) disposed along the flowline402. In the illustrated example, the fluid agitator410is a check valve.

The first fluid analyzer module404and/or the second fluid analyzer module408include one or more optical tools412and414(e.g., a In Situ Fluid Analyzer (IFA) of Schlumberger Ltd., a Live Fluid Analyzer (LFA) of Schlumberger Ltd., a Composition Fluid Analyzer (CFA) of Schlumberger Ltd., and/or any other suitable optical tool) disposed along the flowline402to determine a variety of characteristics (e.g., hydrocarbon composition, gas/oil ratio, live-oil density, pH of water, fluid color, etc.) and/or fluid concentrations (e.g., concentrations of methane, ethane-propane-butane-pentane, water, carbon dioxide, and/or other fluids) of the formation fluid flowing through the flowline402. In some examples, the optical tools412and414are disposed along the flowline402upstream and/or downstream of the fluid agitator410. In the illustrated example, the optical tools412and414are disposed upstream and downstream of the fluid agitator410along the flowline402. The optical tools412and414include one or more sensors (not shown) to determine water fractions of the formation fluid by determining optical densities of the formation fluid.

The second fluid analyzer module408also includes at least one viscometer416such as, for example, a vibrating wire viscometer, a vibrating rod viscometer, and/or any other suitable viscometer. The viscometer416is disposed along the flowline402downstream of the fluid agitator410and the optical tools412and414to determine viscosities of the formation fluid.

During operation, the formation fluid flows from the subterranean formation into the downhole tool400. The formation fluid is a mixture including oil and water (i.e., a suspension and/or dispersion of oil in water or water in oil). In some examples, water-based drilling fluid or oil-based drilling fluid is colloidally suspended and/or dispersed in the formation fluid flowing into the downhole tool400. The formation fluid flows into the flowline402and through the first fluid analyzer module404, the MRPO406, and the second fluid analyzer module408. As the formation fluid flows through the flowline402, the first optical tool412and/or the second optical tool414determine water fractions of the formation fluid by determining optical densities of the formation fluid.

After the formation fluid flows through the first fluid analyzer module404, the formation fluid flows through the fluid agitator410disposed in the MRPO406. The formation fluid is agitated (i.e., sheared) via the fluid agitator410to cause droplets of the water (i.e., the dispersed phase) in the formation fluid to decrease in size. In some examples, the fluid agitator410is to cause the water droplets to disperse substantially uniformly throughout a continuous phase (e.g., oil) of the formation fluid. As a result, a stability and/or an emulsification of the formation fluid is increased (i.e., the mixture tightens and/or emulsifies). After the formation fluid is agitated via the fluid agitator410, the viscometer416determines viscosities of the formation fluid. In some examples, the viscosities of the formation fluid are determined based on a shear rate of the viscometer416. As described in greater detail below, based on the viscosities and the water fractions, the viscosity of only the oil in the formation fluid is determined.

FIG. 5is a chart that plots the water fraction of the formation fluid over time. An example curve500is plotted based on the water fractions determined by the one or more of the optical tools412and414. As the formation fluid is flowed into the example downhole tool400, the water fractions of the formation fluid may decrease over time. In the illustrated example, the water fractions of the formation fluid flowing into the example downhole tool400are decreasing monotonically from about 12,500 seconds to about 16,000 seconds. However, the water fractions of the formation fluid are greater than zero during that time.

FIG. 6is a chart that plots viscosities of the formation fluid over time. An example curve600is plotted based on the viscosities determined by the viscometer416. The viscosities decrease over the time as illustrated by the example curve600. The viscosities of the formation fluid are determined when the water fractions of the formation fluid are decreasing monotonically. For example, the viscosities of the formation fluid flowing into the example downhole tool400are determined from about 12,500 seconds to about 16,000 seconds.

FIG. 7is a chart that plots the viscosities of the formation fluid as a function of the water fractions of the formation fluid. An example curve700depicted inFIG. 7is plotted using the example curves500and600ofFIGS. 5 and 6. For example, the x-axes of the example charts ofFIGS. 5 and 6are both represent time (e.g., seconds). Thus, by combining the curves500and600ofFIGS. 5 and 6, the viscosities over the water fractions are plotted as the example curve700and, thus, a viscosity of the formation fluid (i.e., the mixture of oil and water) as a function of the water fractions of the formation fluid is determined. In the illustrated example, the viscosities of the formation fluid increase as the water fractions increase such that the example curve700is fit using a second order polynomial equation such as, for example, Equation 1 below.
Viscositymixture=A+B(Water Fraction)+C(Water Fraction)2.  Equation (1)
In Equation 1, A is the viscosity of the oil in units of centipoise (cP) and B and C are constants in units of centipoise (cP). The water fraction is unitless. The viscosity of the oil in the formation fluid is determined by extrapolating the water fraction of the formation fluid to zero. For example, using values from the curve700ofFIG. 7and Equation 1, values of A, B, and C are determined and, thus, the viscosity of only the oil (i.e., A) in the formation fluid is determined.

FIG. 8depicts an example flow diagram representative of processes that may be implemented using, for example, computer readable instructions. The example process ofFIG. 8may be performed using a processor, a controller and/or any other suitable processing device. For example, the example processes ofFIG. 8may be implemented using coded instructions (e.g., computer readable instructions) stored on a tangible computer readable medium such as a flash memory, a read-only memory (ROM), and/or a random-access memory (RAM). As used herein, the term tangible computer readable medium is expressly defined to include any type of computer readable storage and to exclude propagating signals. Additionally or alternatively, the example process ofFIG. 8may be implemented using coded instructions (e.g., computer readable instructions) stored on a non-transitory computer readable medium such as a flash memory, a read-only memory (ROM), a random-access memory (RAM), a cache, or any other storage media in which information is stored for any duration (e.g., for extended time periods, permanently, brief instances, for temporarily buffering, and/or for caching of the information). As used herein, the term non-transitory computer readable medium is expressly defined to include any type of computer readable medium and to exclude propagating signals.

Alternatively, some or all of the example process ofFIG. 8may be implemented using any combination(s) of application specific integrated circuit(s) (ASIC(s)), programmable logic device(s) (PLD(s)), field programmable logic device(s) (FPLD(s)), discrete logic, hardware, firmware, etc. Also, one or more operations depicted inFIG. 8may be implemented manually or as any combination(s) of any of the foregoing techniques, for example, any combination of firmware, software, discrete logic and/or hardware. In some examples, the example process ofFIG. 8may be implemented using the electronics and processing system306, a logging and control system at the surface, and/or a downhole control system. Further, one or more operations depicted inFIG. 8may be implemented at the surface and/or downhole.

Further, although the example process ofFIG. 8is described with reference to the flow diagram ofFIG. 8, other methods of implementing the process ofFIG. 8may be employed. For example, the order of execution of the blocks may be changed, and/or some of the blocks described may be changed, eliminated, sub-divided, or combined. Additionally, one or more of the operations depicted inFIG. 8may be performed sequentially and/or in parallel by, for example, separate processing threads, processors, devices, discrete logic, circuits, etc.

FIG. 8depicts an example process800that may be used with one of the example downhole tools ofFIGS. 1-4. The example process begins by flowing a mixture into the downhole tool400(block802). In some examples, a continuous phase of the mixture is oil, and a dispersed phase of the mixture is aqueous (e.g., water). The MRPO406may pump the formation fluid from the subterranean formation into the downhole tool400and/or through the flowline402. At block804, fractions of the dispersed phase of the mixture are determined. For example, the first optical tool412and/or the second optical tool414(e.g., the IFA, LFA, CFA, etc.) determine fractions of the dispersed phase of the mixture by determining optical densities of the mixture. As the mixture is flowed from the subterranean formation into the downhole tool400, the fractions of the dispersed phase of the mixture may decrease over time. In some examples, the fractions of the dispersed phase decrease monotonically over a portion of the time.

At block806, the stability or emulsification of the mixture is increased. For example, the mixture is agitated via the fluid agitator410to decrease sizes of droplets of the dispersed phase of the mixture and/or substantially uniformly disperse the droplets throughout the continuous phase. The fractions of the dispersed phase of the mixture are determined before and/or after the stability of the mixture is increased. At block808, viscosities of the mixture are determined. For example, the viscometer416(e.g., a vibrating wire viscometer, a vibrating rod viscometer, etc.) determines the viscosities of the mixture. The viscosities are determined when the fractions of the dispersed phase of the mixture are decreasing monotonically.

At block810, a viscosity of the mixture as a function of the fraction of the dispersed phase of the mixture is determined. For example, the viscosity of the mixture as a function of the fraction of the dispersed phase may be determined by using the viscosities and the fractions of the dispersed phase determined when the water fractions are decreasing monotically. At block812, the water fraction of the dispersed phase of the mixture is extrapolated to zero. For example, the water fraction of the dispersed phase may be extrapolated to zero using a second order polynomial equation representing the viscosity of the mixture as a function of the fraction of the dispersed phase such as, for example, Equation 1. Thus, at block814, a viscosity of the continuous phase (i.e., the oil) of the mixture is determined.