Abstract: A method for “tagging” proppants so that they can be tracked and monitored in a downhole environment, based on the use of composite proppant compositions comprising a particulate substrate coated by a material whose electromagnetic properties change at a detectable level under a mechanical stress such as the closure stress of a fracture. In another aspect, the invention relates to composite proppant compositions comprising coatings whose electromagnetic properties change under a mechanical stress such as the closure stress of a fracture. The substantially spherical composite proppants may comprise a thermoset nanocomposite particulate substrate where the matrix material comprises a terpolymer of styrene, ethylvinylbenzene and divinylbenzene, and carbon black particles possessing a length that is less than 0.

Abstract: In one aspect, the invention relates to a method for “tagging” proppants so that they can be tracked and monitored in a downhole environment, based on the use of composite proppant compositions containing dispersed fillers whose electromagnetic properties change at a detectable level under a mechanical stress such as the closure stress of a fracture. In another aspect, the invention relates to composite proppant compositions containing dispersed fillers whose electromagnetic properties change under a mechanical stress such as the closure stress of a fracture. The currently preferred embodiments use substantially spherical thermoset nanocomposite particles where the matrix comprises a terpolymer of styrene, ethylvinylbenzene and divinylbenzene, a PZT alloy manifesting a strong piezoelectric effect or Terfenol-D manifesting giant magnetostrictive behavior is incorporated to provide the ability to track in a downhole environment, and carbon black particles possessing a length that is less than 0.

Abstract: Delivery of a substance to a subterranean location is achieved by suspending the substance as nanoparticles in a carrier fluid in which the substance is insoluble. The procedure may start by forming a dispersible powder composition, which is done by dissolving the substance in a solvent, emulsifying the resulting solution as the dispersed phase of an emulsion, and freeze-drying the emulsion to a powder. On mixing the powder with a fluid in which the substance is insoluble, any soluble constituents of the powder dissolve and the insoluble substance becomes a dispersion of nanoparticles of the substance. Then, the fluid containing the dispersed substance is pumped to the subterranean location. The dispersion of nanoparticles has surprising stability, facilitating transport to the subterranean location.

Abstract: A proppant composition comprises a non-radioactive, detectable tracer at least partially embedded in a ceramic composition. The composition may be prepared by agglomerating granules of the ceramic material and granules of the non-radioactive, detectable material to produce the particle by compression. Backflow of proppants in a fractured subterranean formation into which a plurality of particles of the proppant composition have been introduced may be tracked by analyzing a sample of the backflow by detecting for presence of the tracer in the sample.

Abstract: Dual-function nano-sized particles or nanoparticles may be effective at fixating or reducing fines migration and they may facilitate identification of a particular zone in a well having more than one zone. In some embodiments the dual-function nanoparticles are tagged with a detectable material that is distinguishable from the composition of the primary nanoparticle component. In these embodiments, the taggant material rather than the primary component of the nanoparticles may be used to enable identification of a particular zone. The nanoparticles (with or without taggant) may be added to a treatment fluid containing carrier particles such as proppant. The treatment fluid is pumped downhole to one of the zones; each zone receiving its own unique or uniquely-tagged nanoparticles. Should one of the zones fail, the composition of the nanoparticles (or its taggant) produced on the carrier particles may be correlated to the zone from which it was received, and hence produced.

Abstract: A process for hydraulic fracturing of a subterranean reservoir formation penetrated by a wellbore includes pumping a fracturing fluid or other aqueous fluid which is an aqueous suspension of particles which each comprise an oilfield chemical distributed within an encapsulating matrix of water-insoluble carrier_material from the surface via the wellbore and into the reservoir. The encapsulating matrix is chosen so as to provide a delayed release of the oilfield chemical from the particles into surrounding fluid, such that oilfield chemical is liberated from the particles after they have entered the fracture. The encapsulating matrix may be a polymer which is at least partially amorphous, with a glass transition temperature below the reservoir temperature.

Abstract: A process of making observations of a subterranean reservoir penetrated by a wellbore uses distinguishable sets of tracer particles and comprises steps of: (i) delivering a plurality of sets of tracer particles to respective subterranean locations via the wellbore, the particles in each set comprising a tracer substance which distinguishes that set form the other sets; (ii) causing or allowing the tracer substances to flow out from the tracer particles whilst the particles are at the respective subterranean locations; (iii) causing or allowing production of fluid out of said reservoir via the wellbore; and (iv) detecting the presence or absence of the tracer substances in the produced fluid. The tracer substances are sufficiently distinguishable from each other to enable a tracer substance detected in the produced fluid to identify the set of tracer particles from which it has come and hence identify the location from which it has come.

Abstract: Apparatus and methods for collecting a downhole sample are provided. The method may include introducing a flowable sealant to a borehole wall portion, modifying a formation system mobility using the flowable sealant, and receiving the downhole sample using a sample receiving port positioned proximate the borehole wall portion. An apparatus includes a formation sampling member having a sample receiving port for receiving the downhole sample, and an inhibitor that includes one or more of an activator and an injector.

Abstract: Systems and methods are provided for swellable material activation and monitoring in a subterranean well. A sensor system for use in a subterranean well includes a swellable material, and at least one sensor which is displaced to a wellbore surface in response to swelling of the swellable material. Another sensor system includes a sensor which detects swelling of a swellable material. A swellable well tool system includes a base pipe, a swellable material on an exterior of the base pipe, and eccentric weighting for inducing rotation of the swellable material about a longitudinal axis of the base pipe.

Abstract: There is provided an apparatus for injecting a tracer within a groundwater observation well, which is capable of sequentially performing a tracer test by depth by injecting the tracer to a predetermined depth within the groundwater observation well. More particularly, the present invention relates to an apparatus and method for instantaneously injecting a tracer to a groundwater well, whereby opening and closing of a container receiving the tracer is controlled by using a pneumatic cylinder and the tracer on the ground is supplied to the container, so that the tracer is repeatedly carried and injected to a specific depth in a well.

Abstract: A system and method for releasing a marker within a wellbore is provided. The system and method includes a sensor that detects movement or a position of the marker within the wellbore. The marker may be released in drilling fluid, for example, and may travel from the surface to the drill bit and return to the surface with cuttings. As an example, the markers are used to determine the flow of cuttings within the wellbore.

Abstract: A downhole tool for use in coiled tubing well operations. The tool includes a gamma ray detector for determining well location information for an associated coiled tubing application. The well location information may relate to well depth and/or the locating and identifying of a particular side branch or lateral leg of the well. Additionally, the gamma ray detector may be utilized to monitor dynamic well conditions in real-time such as the flow of injected fluids or the effectiveness of clean out applications via the coiled tubing.

Abstract: A tool system for monitoring a flow of liquid within a borehole. The tool system comprises a plurality of tools disposed on a longitudinal axis of the tool system. The plurality of tools comprises at least a first injector tool for ejecting in the borehole a tracer and a detector tool to detect the ejected tracer. The tool system further comprises a standard digital bus traversing at least a portion of each tool of the plurality of tools. The standard digital bus allows a communication between each tool of the plurality of tools.

Abstract: A downhole abrading tools has a body with a first end for connection with a rotating component of a drill string, and a cutting end for rotation in unison with the body, the cutting end having an abrading matrix containing an abrasive material for rotating engagement with an object within the well. The downhole abrading tool also includes a passage through the tool for circulating a drilling fluid. The abrading matrix includes at least one taggant embedded within the abrading matrix capable of being released by the abrading matrix into the downhole location due to wear on the abrasive material and transported to the surface location along with the drilling fluid for detection. When the taggant is released due to excessive wear, the taggant is carried from the downhole location in the well to the surface of the well where it can be detected by the operator of the tool.

Abstract: A tool system for monitoring a flow of liquid within a borehole. The tool system comprises a plurality of tools disposed on a longitudinal axis of the tool system. The plurality of tools comprises at least a first injector tool for ejecting in the borehole a tracer and a detector tool to detect the ejected tracer. The tool system further comprises a standard digital bus traversing at least a portion of each tool of the plurality of tools. The standard digital bus allows a communication between each tool of the plurality of tools.

Abstract: A fluid can be tracked in a wellbore utilizing at least one WID tag, such as an LW tag or an RFID tag, entrained in the fluid. A WID tag reader can be disposed and/or displaced in the wellbore, for example, on a drill string or a casing string. A reader can be utilized to locate the at least one WID tag in the wellbore. A reader can be housed in a drill string sub. A fluid entrained with at least one WID tag can be utilized as a tracer fluid. A WID tag can be entrained in cement or a drilling or fracture fluid.

Abstract: A downhole abrading tools has a body with a first end for connection with a rotating component of a drill string and a cutting end for rotation in unison with the body. The downhole abrading tool also includes a passage through the tool for circulating a drilling fluid. Disposed within the drilling fluid passageway is a taggant injection assembly having one or more taggants disposed therein that facilitates injection of taggants into the drilling fluid upon the cutting end experience excessive wear. The taggants are then transported to the surface location along with the drilling fluid for detection by the operator of the downhole abrading tool.

Abstract: A downhole abrading tools has a body with a first end for connection with a rotating component of a drill string, and a cutting end for rotation in unison with the body, the cutting end having an abrading matrix containing an abrasive material for rotating engagement with an object within the well. The downhole abrading tool also includes a passage through the tool for circulating a drilling fluid. The abrading matrix includes at least one taggant embedded within the abrading matrix capable of being released by the abrading matrix into the downhole location due to wear on the abrasive material and transported to the surface location along with the drilling fluid for detection. When the taggant is released due to excessive wear, the taggant is carried from the downhole location in the well to the surface of the well where it can be detected by the operator of the tool.

Abstract: Methods and related apparatuses and mixtures are described for detecting hydrogen sulfide in a formation fluid downhole. A detection mixture is combined with the formation fluid downhole. The detection mixture includes metal ions for reacting with hydrogen sulfide forming a metal sulfide, and charged nanoparticles sized so as to inhibit significant aggregation of the metal sulfide so as to enable spectroscopic detection of the metal sulfide downhole. The combined mixture and formation fluid is then spectroscopically interrogated so as to detect the presence of the metal sulfide thereby indicating the presence of hydrogen sulfide in the formation fluid. The mixture also includes chelating ligands for sustaining thermal endurance of the mixture under downhole conditions.

Abstract: A downhole abrading tool having a body with a first end for connection to a drill string, a cutting end, a drilling fluid passageway, a restrictor disposed within drilling fluid passageway, and an indicator chamber is disclosed. Upon exposure of the indicator chamber to a well environment due to excessive wear on the cutting end, the restrictor is actuated. Actuation of the restrictor restricts the flow of drilling fluid from the drilling fluid passageway into the well environment. The restriction of flow of drilling fluid from the drilling fluid passageway causes a pressure increase in the drilling fluid flowing through the well that can detected by an operator of the downhole abrading tool. The pressure increase provides an indication to the operator of excessive wear on the cutting end of the downhole abrading tool so that the downhole abrading tool can be removed from the well and replaced.

Abstract: A method of localizing the source of a particulate produced with a fluid through a wellbore is provided, the method comprising the steps of: (A) providing marking composition comprising at least one marker that: (i) is capable of binding with a particulate; and (ii) has a detectable property distinguishable from the particulate; (B) introducing the marking composition: (i) through a wellbore; and (ii) into contact with at least a portion of a subterranean formation penetrated by the wellbore; (C) obtaining a fluid produced through the wellbore; and (D) analyzing a particulate produced with the produced fluid for the presence of the marker.

Abstract: Methods that include a method of determining one or more approximate properties of a subterranean formation and/or a fracture therein comprising: obtaining fluid identity data for a plurality of flowback fluid samples; and using a reservoir model, with the fluid identity data and one or more subterranean formation properties as inputs thereto, to estimate one or more properties in a subterranean formation. Additional methods are provided.

Abstract: A downhole abrading tools has a body with a first end for connection with a rotating component of a drill string, and a cutting end for rotation in unison with the body, the cutting end having an abrading matrix containing an abrasive material for rotating engagement with an object within the well. The downhole abrading tool also includes a passage through the tool for circulating a drilling fluid. The abrading matrix includes at least one taggant embedded within the abrading matrix capable of being released by the abrading matrix into the downhole location due to wear on the abrasive material and transported to the surface location along with the drilling fluid for detection. When the taggant is released due to excessive wear, the taggant is carried from the downhole location in the well to the surface of the well where it can be detected by the operator of the tool.

Abstract: Disclosed herein is a method of determining the fracture geometry of a subterranean fracture comprising introducing into the fracture a target particle and/or proppant; transmitting into the fracture electromagnetic radiation having a frequency of about 300 megahertz to about 100 gigahertz; and analyzing a reflected signal from the target particle to determine fracture geometry. Disclosed herein too is a method of determining the fracture geometry of a subterranean fracture comprising introducing into the fracture a target particle and/or proppant; wherein the target particle and/or proppant comprises a high dielectric constant ceramic having a dielectric constant of greater than or equal to about 2; transmitting into the fracture electromagnetic radiation having a frequency of less than or equal to about 3 gigahertz; and analyzing a reflected signal from the target particle and/or proppant to determine fracture geometry.

Abstract: A method of localizing the source of a particulate produced with a fluid through a wellbore is provided, the method comprising the steps of: (A) providing marking composition comprising at least one marker that: (i) is capable of binding with a particulate; and (ii) has a detectable property distinguishable from the particulate; (B) introducing the marking composition: (i) through a wellbore; and (ii) into contact with at least a portion of a subterranean formation penetrated by the wellbore; (C) obtaining a fluid produced through the wellbore; and (D) analyzing a particulate produced with the produced fluid for the presence of the marker.

Abstract: The extent of invasion of a water-based drilling fluid into a formation may be determined using at least two tracers where one is deuterium oxide and the other is a water-soluble tracer. One such method includes introducing a drilling fluid having an aqueous phase and known concentrations of a water-soluble tracer and deuterium oxide into a well drilled into a fluid-producing formation; obtaining a sample of the fluid from the fluid-producing formation at a location adjacent to the well; determining the concentrations of the deuterium oxide and water-soluble tracer in the sample; and calculating the deuterium oxide concentration within the fluid producing formation based on the known and determined concentrations of the water-soluble tracer and deuterium oxide in the drilling fluid and in the sample.

Abstract: Methods and systems for reverse-circulation cementing in subterranean formations are provided. An example of a method is a method of cementing casing in a subterranean well bore, comprising inserting a casing into the well bore, the casing comprising a casing shoe; equipping the casing with a well head, and a casing inner diameter pressure indicator; flowing an equilibrium fluid into the well bore; flowing a cement composition into the well bore after the equilibrium fluid; determining from the well-bore pressure indicator when the well bore pressure has reached a desired value; discontinuing the flow of cement composition into the well bore upon determining that the well bore pressure has reached a desired value; and permitting the cement composition to set in the subterranean formation. Examples of systems include systems for cementing casing in a well bore.

Abstract: Methods and systems for reverse-circulation cementing in subterranean formations are provided. An example of a method is a method of cementing casing in a subterranean well bore, comprising inserting a casing into the well bore, the casing comprising a casing shoe; equipping the casing with a well head, and a casing inner diameter pressure indicator; flowing an equilibrium fluid into the well bore; flowing a cement composition into the well bore after the equilibrium fluid; determining from the well-bore pressure indicator when the well bore pressure has reached a desired value; discontinuing the flow of cement composition into the well bore upon determining that the well bore pressure has reached a desired value; and permitting the cement composition to set in the subterranean formation. Examples of systems include systems for cementing casing in a well bore.

Abstract: Methods that include a method of determining one or more approximate properties of a subterranean formation and/or a fracture therein comprising: obtaining fluid identity data for a plurality of flowback fluid samples; and using a reservoir model, with the fluid identity data and one or more subterranean formation properties as inputs thereto, to estimate one or more properties in a subterranean formation. Additional methods are provided.

Abstract: A method for determining the extent of recovery of materials injected or otherwise introduced into oil wells or subsurface formations is practiced using a portable device. The portable device can also be used to determiner the occurrence of a predetermined condition in an oil well such as water break through in a production zone, or the opening or closing of a sliding sleeve. When, for example, water breakthrough is detected, the zone producing too much water can be plugged, using, for example, a flow-through bridge plug, if there are other producing zones further downhole.

Abstract: A downhole abrading tools has a body with a first end for connection with a rotating component of a drill string, and a cutting end for rotation in unison with the body, the cutting end having an abrading matrix containing an abrasive material for rotating engagement with an object within the well. The downhole abrading tool also includes a passage through the tool for circulating a drilling fluid. The abrading matrix includes at least one taggant embedded within the abrading matrix capable of being released by the abrading matrix into the downhole location due to wear on the abrasive material and transported to the surface location along with the drilling fluid for detection. When the taggant is released due to excessive wear, the taggant is carried from the downhole location in the well to the surface of the well where it can be detected by the operator of the tool.

Abstract: Improved well fluids that include hollow particles, and methods of using such improved well fluids in subterranean cementing operations are provided. Also provided are methods of cementing, methods of reducing annular pressure, and well fluid compositions. While the compositions and methods of the present invention are useful in a variety of subterranean applications, they may be particularly useful in deepwater offshore cementing operations.

Abstract: In embodiments, methods of determining a size of an annulus in a wellbore include: (a) displacing a fluid comprising reflective particles downhole and up through the annulus, wherein the reflective particles make a front end of the fluid visible as it exits the wellbore; (b) determining a total volume of the fluid displaced into the wellbore by detecting the reflective particles exiting the wellbore; and (c) calculating the size of the annulus based on that total volume of the fluid. The fluid may include a drilling fluid, a cement slurry, a spacer fluid, or combinations thereof. The reflective particles may include polymeric beads. In additional embodiments, drilling fluids, spacer fluids, cement slurries and combinations thereof comprise an effective amount of reflective particles to ensure that the fluids are visible when they exit a wellbore.

Abstract: The present invention relates to improved well fluids that include hollow particles, and to methods of using such improved well fluids in subterranean cementing operations. The present invention provides methods of cementing, methods of reducing annular pressure, and well fluid compositions. While the compositions and methods of the present invention are useful in a variety of subterranean applications, they may be particularly useful in deepwater offshore cementing operations.

Abstract: A method is described for inhibiting migration of fluids into and/or out of a treatment area undergoing an in situ conversion process. Barriers in the formation proximate a treatment area may be used to inhibit migration of fluids. Inhibition of migration of fluids may occur before, during, and/or after an in situ treatment process. For example, migration of fluids may be inhibited while heat is provided from heaters to at least a portion of the treatment area. Barriers may include naturally occurring portions (e.g., overburden, and/or underburden) and/or installed portions.

Abstract: Some embodiments provide methods of obtaining data from a portion of a subterranean formation comprising providing proppant particulates wherein at least a portion of the proppant particulates are coated with an electroconductive resin that comprises a resin and a conductive material; placing the proppant particulates into a portion of a fracture so as to form an electroconductive proppant pack; providing a transmitter capable of sending an electric current into the electroconductive proppant pack; sending an electric current into the electroconductive proppant pack with the transmitter; providing a receiver capable of deflecting a reflected or conducted electric signal from the electroconductive proppant pack; and, receiving a reflected electric signal with the receiver.

Abstract: An apparatus for use in circulating cement in a casing in a wellbore is described having a first component such as a sensor disposed on the casing and a second component such as a detectable device disposed at a fluid interface formed between the cement and a fluid. The sensor may be a sensor coil mounted on the perimeter of the lower end of the casing, while the detectable device may be a transponder capable of emitting Radio Frequency Identification signals to the sensor to signal its arrival at the lower end of the casing. The transponder may be encased in a protective covering. Also described is a method of cementing a casing utilizing a first component such as a sensor disposed on the casing and a second component such as a detectable device disposed in the cement.

Abstract: An oil shale formation may be treated using an in situ thermal process. Fluid migration into and/or out of a treatment area in the formation may be inhibited. In some embodiments, a barrier may be used to inhibit migration of fluids into and/or out of the treatment area. Heat may be provided to the treatment area and subsequently, hydrocarbons, H2, and/or other formation fluids may be produced from the formation.

Abstract: Disclosed is a method of determining the extent of recovery of materials injected into oil wells or subsurface formations. The method includes injection of one or more tracers into an oil well or into a formation. Included in the method are the steps of introducing a material of interest into the oil well or into the subsurface formation associated with the bore of the oil well; introducing a tracer into the oil well or into the subsurface formation associated with the bore of the oil well; recovering from the oil well a production fluid, analyzing the production fluid for a concentration of the chemical tracer present in the production fluid; and calculating the amount of material of interest recovered from the oil well using the concentration of the chemical tracer present in the production fluid as a basis for the calculation.

Abstract: Water-based mud filtrate concentration in a downhole fluid sample drawn from the borehole of an oil well is assessed. To measure water-based mud filtrate concentration, a water-based mud having a water-soluble fluorescent dye tracer is pumped into the borehole; sample fluid from a selected downhole location is pumped through a downhole flow line having a window; sample fluid flowing in an excitation region of the downhole flow line is illuminated through the window with fluorescence excitation light; and fluorescence emission from the excitation region is measured to produce a measured value. The measured value represents the fraction of water-based mud filtrate in the sample fluid. A calibration value is determined representing 100% water-based mud filtrate. A method for validating a sample of connate water as having an acceptably low WBM filtrate contamination tests for validation downhole, in real time.

Abstract: A method and apparatus for internal data conveyance within a well from the surface to a downhole tool or apparatus and for returning downhole tool data to the surface, without necessitating the provision of control cables and other conventional conductors within the well. One embodiment involves sending telemetry elements such as tagged drop balls or a fluid having specific chemical characteristics from surface to a downhole tool as a form of telemetry. The telemetry element or elements are provided with identification and instruction data, which may be in the form of data tags, such as RF tags or a detectable chemical constituent. The downhole tool or apparatus is provided with a detector and microcomputer and is capable of recognizing the telemetry element and communicating with it or carrying out instructions that are provided in the telemetry data thereof.

Abstract: A method for retrieving a formation fluid sample through a cased borehole utilizing a sampling tool. Sampling tool straddle packers are set about a first set of perforations and annular fluid is drained from the isolated zone, through a central conduit in the tool and discharged above or below the packers. Formation fluid is induced to flow into the central conduit and into sample chambers. The packers are unset, the tool moved to the next set of perforations that are azimuthally offset from the first set of perforations and the sampling process repeated, with subsequent samples being placed in separate sample chambers.

Abstract: A petroleum well having a well casing, a production tubing, a source of time-varying current, a downhole tracer injection device, and a downhole induction choke. The casing extends within a wellbore of the well. The tubing extends within the casing. The current source is located at the surface. The current source is electrically connected to, and adapted to output a time-varying current into, the tubing and/or the casing, which act as electrical conductors for providing downhole power and/or communications to the injection device. The injection device having a communications and control module, a tracer material reservoir, and an electrically controllable tracer injector.

Abstract: An apparatus for use in circulating cement in a casing in a wellbore is described having a first component such as a sensor disposed on the casing and a second component such as a detectable device disposed at a fluid interface formed between the cement and a fluid. The sensor may be a sensor coil mounted on the perimeter of the lower end of the casing, while the detectable device may be a transponder capable of emitting Radio Frequency Identification signals to the sensor to signal its arrival at the lower end of the casing. The transponder may be encased in a protective covering. Also described is a method of cementing a casing utilizing a first component such as a sensor disposed on the casing and a second component such as a detectable device disposed in the cement.

Abstract: A tracer release method for monitoring fluid flow in a well utilizes a deformable container having a liquid tracer material which container has an outlet which debouches into the neck portion of a venturi in a well conduit. The container has a wall which is at least partly exposed to the fluid pressure at the relatively wide in- or outlet of the venturi, so that an amount of tracer is injected continuously or discontinuously into the well effluents which is proportional to the pressure difference p across the venturi, which pressure difference p is indicative of the fluid density &rgr; and squared fluid velocity &ugr;.

Abstract: A technique that is usable with a subterranean well includes communicating a fluid into a region of the well and monitoring a level of the fluid communicated via a downhole sensor. The communication is controlled in response to the monitoring.

Abstract: Disclosed is a method of determining the extent of recovery of materials injected into oil wells or subsurface formations. The method includes injection of one or more tracers into an oil well or into a formation. Included in the method are the steps of introducing a material of interest into the oil well or into the subsurface formation associated with the bore of the oil well; introducing a tracer into the oil well or into the subsurface formation associated with the bore of the oil well; recovering from the oil well a production fluid, analyzing the production fluid for a concentration of the chemical tracer present in the production fluid; and calculating the amount of material of interest recovered from the oil well using the concentration of the chemical tracer present in the production fluid as a basis for the calculation.

Abstract: Compositions and methods for tracking the transport of particulate solids during the production of hydrocarbons from a subterranean formation.

Abstract: Disclosed is a method of determining the extent of recovery of materials injected into a oil well comprising the steps of: a) preparing a material to be injected into an oil well; b) admixing therewith a chemical tracer compound at a predetermined concentration; c) injecting the admixture into an oil well; d) recovering from the oil well a production fluid; e) analyzing the production fluid for the concentration of the chemical tracer present in the production fluid; and f) calculating the amount of admixture recovered from the oil well using the concentration of the chemical tracer present in the production fluid as a basis for the calculation. Fluorinated benzoic acids are disclosed as a preferred tracer.

Abstract: The invention relates to a method for use in sampling, flow measuring, quantity gauging, or possibly other analysis performed in reservoir fluid found in a ground formation. An object of the invention is to perform the sampling, flow measuring and quantity gauging or the remaining analyses in situ on stabilized reservoir fluid that contains a negligible amount drill fluid. Analysis is possible by sealing off an area of the well at the hydrocarbon carrying layer and passing a volume of reservoir fluid into a drill string for analysis by accessories located in the drill string. After the analyses are performed, the reservoir fluid is returned to the hydrocarbon carrying layer.