Dual temperature tracer method for determining fluid saturations in petroleum reservoirs

Claim 1

A METHOD FOR MEASURING THE RELATIVE AMOUNT OF IMMISCIBLE FLUID PHASES PRESENT IN A SUBTERRANEAN FORMATION PENETRATED BY A WELL IN COMMUNICATION THEREWITH AND CONTAINING AT LEAST ONE MOBILE FLUID PHASE, WHICH COMPRISES: INJECTING A HEAT EXCHANGE FLUID AT A TEMPERATURE SUBSTANTIALLY DIFFERENT THAN THE TEMPERATURE OF THE FORMATION TO ADJUST THE TEMPERATURE OF THE STRATA TO BE TESTED TO ABOUT THAT OF THE INJECTED FLUIDS; THEREAFTER INJECTING A CARRIER FLUID THROUGH SAID WELL AND INTO SAID FORMATION AT THE TEMPERATURE OF THE INJECTED HEAT EXCHANGE FLUID, SAID CARRIER FLUID BEING MISCIBLE WITH SAID MOBILE FLUID AND CONTAINING A LOW CONCENTRATION OF (1) AT LEAST ONE FIRST TRACER MATERIAL THAT PARTITIONS BETWEEN ONE OF THE FLUID PHASES IN THE FORMATION AND THE CARRIER FLUID TO A DEGREE THAT VARIES WITH TEMPERATURE AND (2) AT LEAST ONE SECOND TRACER MATERIAL HAVING A PORTION COEFFICIENT THAT IS INDEPENDENT OF TEMPERATURE; SHUTTING IN SAID WELL FOR A TIME PERIOD SUFFICIENT FOR THE INJECTED FLUIDS TO COME TO TEMPERATURE EQUILIBRIUM WITH THE FORMATION; PRODUCING SAID WELL TO RECOVER FLUIDS FROM SAID FORMATION; ANALYZING SAID RECOVERED FLUIDS TO DETERMINE THE PEAK CONCENTRATIONS OF SAID TRACER MATERIALS IN SAID FLUIDS; AND APPLYING CHROMATOGRAPHIC PRINCIPLES TO DETERMINE THE RELATIVE SATURATION OF FLUID PHASES PRESENT IN SAID FORMATION.

Claim 2

A METHOD FOR MEASURING THE RELATIVE AMOUNT OF IMMISCIBLE FLUID PHASES PRESENT IN A SUBTERRANEAN FORMATION PENETRATED BY A WELL IN COMMUNICATION THEREWITH AND CONTAINING AT LEAST ONE MOBILE FLUID PHASE, WHICH COMPRISES: INJECTING A HEAT EXCHANGE FLUID AT A TEMPERATURE SUBSTANTIALLY DIFFERENT THAN THE TEMPERATURE OF THE FORMATION TO ADJUST THE TEMPERATURE OF THE STRATA TO BE TESTED TO ABOUT THAT OF THE INJECTED FLUIDS; THEREAFTER INJECTING A CARRIER FLUID THROUGH SAID WELL AND INTO SAID FORMATION AT THE TEMPERATURE OF THE INJECTED HEAT EXCHANGE FLUID, SAID CARRIER FLUID BEING MISCIBLE WITH SAID MOBILE FLUID AND CONTAINING A LOW CONCENTRATION OF (1) AT LEAST ONE FIRST TRACER MATERIAL THAT PARTITIONS BETWEEN ONE OF THE FLUID PHASES IN THE FORMATION AND THE CARRIER FLUID TO A DEGREE THAT VARIES WITH TEMPERATURE AND (2) AT LEAST ONE SECOND TRACER MATERIAL HAVING A PORTION COEFFICIENT THAT IS INDEPENDENT OF TEMPERATURE; SHUTTING IN SAID WELL FOR A TIME PERIOD SUFFICIENT FOR THE INJECTED FLUIDS TO COME TO TEMPERATURE EQUILIBRIUM WITH THE FORMATION; PRODUCING SAID WELL TO RECOVER FLUIDS FROM SAID FORMATION; ANALYZING SAID RECOVERED FLUIDS TO DETERMINE THE PEAK CONCENTRATIONS OF SAID TRACER MATERIALS IN SAID FLUIDS; AND APPLYING CHROMATOGRAPHIC PRINCIPLES TO DETERMINE THE RELATIVE SATURATION OF FLUID PHASES PRESENT IN SAID FORMATION.

Claim 6

A method for measuring the relative saturations of oil and water present in a subterranean formation penetrated by a well in communication therewith and containing at least one mobile oil or water phase, which comprises: injecting a heat exchange fluid through the well and into the formation at a temperature at least about 50* F. different than the temperature of the formation and in an amount sufficient to adjust the temperature of that region of the formation to be tested to about the temperature of the injected fluid; next injecting a carrier fluid through said well and into said formation at the same temperature as said heat exchange fluid, said carrier fluid being miscible with said mobile fluid and containing a low concentration of (1) at least one first tracer material that partitions between one of the fluid phases in the formation and the carrier fluid to a degree that varies with temperature and (2) at least one second tracer material having a partition coefficient that is independent of temperature; displacing said carrier fluid into said formation away from the well by injecting through the well and into the formation a displacing fluid miscible with said carrier fluid and at the same temperature as said carrier fluid; shutting in said well for a time period sufficient for the injected fluids to come to temperature equilibrium with the formation; producing said well to recover fluids from said formation; analyzing said recovered fluids to determine the peak concentrations of said tracer materials in said fluids; and applying chromatographic principles to determine the relative saturation of fluid phases present in said formation.

Claim 7

A method for measuring the relative saturations of oil and water present in a subterranean formation penetrated by a well in communication therewith and containing at least one mobile oil or water phase, which comprises: injecting a heat exchange fluid through the well and into the formation at a temperature at least about 50* F. different than the temperature of the formation and in an amount sufficient to adjust the temperature of that region of the formation to be tested to about the temperature of the injected fluid; next injecting a carrier fluid through said well and into said formation at the same temperature as said heat exchange fluid, said carrier fluid being miscible with said mobile fluid and containing a low concentration of (1) at least one first tracer material that partitions between one of the fluid phases in the formation and the carrier fluid to a degree that varies with temperature and (2) at least one second tracer material having a partition coefficient that is independent of temperature; displacing said carrier fluid into said formation away from the well by injecting through the well and into the formation a displacing fluid miscible with said carrier fluid and at the same temperature as said carrier fluid; shutting in said well for a time period sufficient for the injected fluids to come to temperature equilibrium with the formation; producing said well to recover fluids from said formation; analyzing said recovered fluids to determine the peak concentrations of said tracer materials in said fluids; and applying chromatographic principles to determine the relative saturation of fluid phases present in said formation.

Claim 13

A method for measuring the relative saturations of oil and water present in a subterranean formation penetrated by a well in communication therewith and containing a mobile water phase and an immobile oil phase, which comprises: injecting an aquEous liquid heat exchange fluid through the well and into the formation at a temperature at least about 50* F. different than the temperature of the formation and in an amount sufficient to adjust the temperature of that region of the formation to be tested to about the temperature of the injected fluid; next injecting an aqueous liquid carrier fluid through said well and into said formation at the same temperature as said heat exchange fluid, said carrier fluid being miscible with said mobile fluid and containing a low concentration of (1) at least one first tracer material that partitions between one of the fluid phases in the formation and the carrier fluid to a degree that varies with temperature and (2) at least one second tracer material having a partition coefficient that is independent of temperature; displacing said carrier fluid into said formation away from the well by injecting an aqueous liquid displacing fluid through said well and into the formation at the same temperature as the heat exchange fluid; shutting in said well for a time period sufficient for the injected fluids to come to temperature equilibrium with the formation; producing said well to recover water from said formation; analyzing the produced water to determine the peak concentrations of said first and said second tracer materials in said produced water; and applying chromatographic principles to determine the relative saturation of oil and water present in said formation.

Claim 14

A method for measuring the relative saturations of oil and water present in a subterranean formation penetrated by a well in communication therewith and containing a mobile water phase and an immobile oil phase, which comprises: injecting an aquEous liquid heat exchange fluid through the well and into the formation at a temperature at least about 50* F. different than the temperature of the formation and in an amount sufficient to adjust the temperature of that region of the formation to be tested to about the temperature of the injected fluid; next injecting an aqueous liquid carrier fluid through said well and into said formation at the same temperature as said heat exchange fluid, said carrier fluid being miscible with said mobile fluid and containing a low concentration of (1) at least one first tracer material that partitions between one of the fluid phases in the formation and the carrier fluid to a degree that varies with temperature and (2) at least one second tracer material having a partition coefficient that is independent of temperature; displacing said carrier fluid into said formation away from the well by injecting an aqueous liquid displacing fluid through said well and into the formation at the same temperature as the heat exchange fluid; shutting in said well for a time period sufficient for the injected fluids to come to temperature equilibrium with the formation; producing said well to recover water from said formation; analyzing the produced water to determine the peak concentrations of said first and said second tracer materials in said produced water; and applying chromatographic principles to determine the relative saturation of oil and water present in said formation.

Claim 16

A method for measuring the relative amounts of immiscible fluid phases present in a subterranean formation penetrated by a well in communication therewith and containing at least one mobile fluid phase, which comprises: injecting a carrier fluid through said well and placing said carrier fluid in said formation at a temperature at least 50* F. different than the temperature of the formation, said carrier fluid being miscible with said mobile fluid and containing a low concentration of (1) at least one first tracer material that partitions between one of the fluid phases in the formation and the carrier fluid to a degree that varies with temperature and (2) at least one second tracer material having a partition coefficient that is independent of temperature; shutting in said well for a time period sufficient for the injected fluids to come to temperature equilibrium with the formation; producing said well to recover fluids from said formation; analyzing said recovered fluids to determine the peak concentrations of said tracer materials in said fluids; and applying chromatographic principles to determine the relative saturation of fluid phases present in said formation.

Claim 17

A method for measuring the relative amounts of immiscible fluid phases present in a subterranean formation penetrated by a well in communication therewith and containing at least one mobile fluid phase, which comprises: injecting a carrier fluid through said well and placing said carrier fluid in said formation at a temperature at least 50* F. different than the temperature of the formation, said carrier fluid being miscible with said mobile fluid and containing a low concentration of (1) at least one first tracer material that partitions between one of the fluid phases in the formation and the carrier fluid to a degree that varies with temperature and (2) at least one second tracer material having a partition coefficient that is independent of temperature; shutting in said well for a time period sufficient for the injected fluids to come to temperature equilibrium with the formation; producing said well to recover fluids from said formation; analyzing said recovered fluids to determine the peak concentrations of said tracer materials in said fluids; and applying chromatographic principles to determine the relative saturation of fluid phases present in said formation.

Claim 21

A method for measuring the relative amounts of immiscible fluid phases present in a subterranean formation penetrated by a well in communication therewith and containing at least one mobile fluid phase, which comprises: injecting a heat exchange fluid through the well and into the formation at a temperature at least about 50* F. different than the temperature of the formation and in an amount sufficient to adjust the temperature of that region of the formation to be tested to about the tEmperature of the injected fluid; next injecting a carrier fluid through said well and into said formation at the same temperature as said heat exchange fluid, said carrier fluid being miscible with said mobile fluid and containing a low concentration of (1) at least one first tracer material that partitions between one of the fluid phases in the formation and the carrier fluid to a degree that varies with temperature and (2) at least one second tracer material having a partition coefficient that is independent of temperature, the concentration of each tracer material being between about 100 ppm and 10,000 ppm if nonradioactive and if radioactive such as to provide between about 0.1 to 2 Curies of radiation; injecting a displacement fluid through said well and into said formation to displace said carrier fluid into said formation an average distance of about 5 to 50 feet from said well; shutting in said well for a time period sufficient for the injected fluids to come to temperature equilibrium with the formation; producing said well to recover fluids from said formation; analyzing said recovered fluids to determine the peak concentrations of said tracer materials in said fluids; and applying chromatographic principles to determine the relative saturation of fluid phases present in said formation.

Claim 22

A method for measuring the relative amounts of immiscible fluid phases present in a subterranean formation penetrated by a well in communication therewith and containing at least one mobile fluid phase, which comprises: injecting a heat exchange fluid through the well and into the formation at a temperature at least about 50* F. different than the temperature of the formation and in an amount sufficient to adjust the temperature of that region of the formation to be tested to about the tEmperature of the injected fluid; next injecting a carrier fluid through said well and into said formation at the same temperature as said heat exchange fluid, said carrier fluid being miscible with said mobile fluid and containing a low concentration of (1) at least one first tracer material that partitions between one of the fluid phases in the formation and the carrier fluid to a degree that varies with temperature and (2) at least one second tracer material having a partition coefficient that is independent of temperature, the concentration of each tracer material being between about 100 ppm and 10,000 ppm if nonradioactive and if radioactive such as to provide between about 0.1 to 2 Curies of radiation; injecting a displacement fluid through said well and into said formation to displace said carrier fluid into said formation an average distance of about 5 to 50 feet from said well; shutting in said well for a time period sufficient for the injected fluids to come to temperature equilibrium with the formation; producing said well to recover fluids from said formation; analyzing said recovered fluids to determine the peak concentrations of said tracer materials in said fluids; and applying chromatographic principles to determine the relative saturation of fluid phases present in said formation.