Abstract: A device for continuous water pressure measurement in a hydrocarbon reservoir comprising a pressure sensor, a hydrophilic membrane positioned between a reservoir formation and the pressure sensor, the hydrophilic membrane having a surface area A, and a biasing device pushing the hydrophilic membrane against the reservoir formation with a force equal to, or larger than, the pressure difference between a hydrocarbon phase Po in the reservoir and the water (Po-Pw) multiplied with the probe membrane contact area. Methods of installing the device in a hydrocarbon reservoir are also disclosed.

Abstract: A method for modeling hydrocarbon recovery workflow is disclosed. The method involves obtaining, by a computer processor, stimulation data and reservoir data regarding a region of interest, wherein the stimulation data describe a water flooding process performed in the reservoir region of interest by one or more enhanced-recovery wells. The method may include determining, by the computer processor, a multi-phase Darcy model for the reservoir region of interest using the reservoir data and the stimulation data. The multi-phase Darcy model determines a fluid phase flow rate using a pressure gradient, an absolute permeability value, and a relative permeability value. The method may include determining, by the computer processor, a plurality of relative permeability values for the reservoir region of interest based on a plurality of fluid-fluid interface correlations and an interpolating parameter.

Abstract: The present disclosure provides methods for determining surfactant retention values in subterranean reservoirs. In particular, the methods comprise conducting at least one single well chemical tracer test and performing a straight line analysis on a saturation profile of the subterranean reservoir.

Abstract: A method for determining an oil-gas-water interface based on the formation pressure equivalent density. The method comprising: determining working parameters of the wireline modular formation tester based on the acquired conventional logging data of a block to be studied; acquiring a series of formation pressure and corresponding depth data based on the working parameter; computing formation pressure equivalent densities at different depths based on the formation pressure and the corresponding depth data; drawing a crossplot of the formation pressure equivalent density and the depth according to the formation pressure equivalent density and the corresponding depth data at the different depths; and determining the oil-gas-water interface according to the position of breaking point of the formation pressure equivalent density on the crossplot of the formation pressure equivalent density and the depth.

Abstract: The present disclosure relates to systems and methods for determining a fluid characteristic of a fluid flowing within a flow region.

Abstract: In-line viscosity measurement systems and related methods may be useful in measuring the viscosity of a fluid in a flow path and, more specifically, in-line measuring the viscosity of a drilling fluid when integrated with drilling systems. For example, a method may include drilling a wellbore penetrating a subterranean formation while circulating a drilling fluid through the wellbore; measuring the viscosity of the drilling fluid with an in-line viscometer system after the drilling fluid has circulated through the wellbore, the in-line viscometer systems comprising either: (1) a two coaxial cylinder configuration, (2) a parallel plates configuration, or (3) a combination thereof positioned to allow for the drilling fluid to flow between the coaxial cylinders or parallel plates.

Abstract: A system and method are provided for operating a dual telemetry measurement while drilling (MWD) system. The method includes sending a downlink command to a downhole system to switch between a first telemetry mode and a second telemetry mode, one of the first and second telemetry modes comprising mud pulse telemetry, and the other of the first and second telemetry modes comprising electromagnetic (EM) telemetry.

Abstract: The present disclosure relates to a method of fracturing and sampling an isolated interval within a wellbore. The method includes deploying a plurality of packers to isolate the interval and initiating a fracture at the isolated interval. The method further includes directing a motive fluid into a proppant injection chamber to direct a proppant stored within the proppant injection chamber into the isolated interval. Sampling also may be performed at the isolated interval.

Abstract: Apparatus having a fiber optic tether disposed in coiled tubing for communicating information between downhole tools and sensors and surface equipment and methods of operating such equipment. Wellbore operations performed using the fiber optic enabled coiled tubing apparatus includes transmitting control signals from the surface equipment to the downhole equipment over the fiber optic tether, transmitting information gathered from at least one downhole sensor to the surface equipment over the fiber optic tether, or collecting information by measuring an optical property observed on the fiber optic tether. The downhole tools or sensors connected to the fiber optic tether may either include devices that manipulate or respond to optical signal directly or tools or sensors that operate according to conventional principles.

Abstract: An apparatus may be used to test the ability of a first fluid to remove a second fluid from a surface. The apparatus comprises a reservoir that contains the first fluid and a testing cell that contains the second fluid. The testing cell also contains a rotor within. The first fluid is pumped into the testing cell, thereby displacing the second fluid. The displaced second fluid flows to a collection vessel. The apparatus is particularly useful for determining the ability of a chemical wash or a spacer fluid to remove non-aqueous drilling fluids from a metallic surface.

Abstract: A cable connection system for connecting a metal jacketed electrical cable with a primary housing, including a socket electrical connector contained within a primary housing bore, a pin electrical connector connected with the cable, a rigid electrical insulating sleeve extending between the pin electrical connector and the metal jacket, and a primary housing compression fitting for mechanically connecting the cable with the primary housing. The cable connection system may further include a secondary housing mechanically connected with the primary housing and a secondary housing compression fitting for mechanically connecting the cable with the secondary housing.

Abstract: A method for testing a loss control material, the method including filling a testing environment in a testing system with a first fluid, injecting a loss control material in a second fluid into the testing environment from a first end of the testing system, thereby displacing the first fluid across the testing environment to a second end of the testing system, and monitoring a formation of a barrier created by the loss control material.

Abstract: A fluid monitoring apparatus includes a housing and a tracer sensor attached to an exterior of the housing. The housing has at least one flow passage for a fluid sample and a port for the tracer sensor to monitor the fluid sample in the housing. In one example, the monitoring apparatus may include a plurality of tracer sensors attached to the housing, wherein the tracer sensors are interchangeably attached to the housing. In one embodiment, the monitoring apparatus may be attached to a first well for detecting the presence of a tracer in the first well, wherein the tracer is supplied from a second well.

Abstract: A methodology and system promote hydrocarbon production from a reservoir using steam assisted gravity drainage. The technique comprises deploying sensors in a subsurface environment containing the reservoir. The sensors are used to obtain data on properties related to a steam assisted gravity drainage region of the reservoir. Based on the data collected from the sensors, the amount of steam injected into areas of the reservoir may be adjusted to facilitate, e.g., optimize, production of hydrocarbons.

Abstract: Systems and methods are described for calculating pore pressure in a porous formation such as shale gas having substantially disconnected pore spaces. In some described examples, an NMR logging tool with at least two depths of investigation (DOIs) is used. The deeper DOI can be used to sample the shale gas that has not been perturbed by the drilling process, for example, and contains the gas at connate pressure. The shallow DOI can be used to sample shale gas that has been perturbed, and has lost at least part of its gas content. The micro cracks that have been formed in the shallow location (closer to the borehole) allow for injection of gas into the formation at known pressures while measuring the NMR response. The connate pore pressure can then be calculated for the deeper location based on the NMR response to the known pressure increase.

Abstract: A method for estimating properties of a subterranean formation penetrated by a wellbore provides for injecting a fluid with the plurality of tracer agents wherein each tracer agent is an object of submicron scale, into the wellbore and formation, flowing the fluid back from the subterranean formation and determining the properties of the formation. The properties are determined by analyzing changes in the tracers size and type distribution function between the injection fluid and produced fluid.

Abstract: Disclosed is a method of testing liquids at a test pressure. A first fluid is placed in a first chamber of a test system. The first fluid is brought to the test pressure. A volume is calculated of a second fluid to inject into the first chamber from a second chamber of the test system via a first portion connecting the first chamber and the second chamber. The first portion includes a fluid interface between the first fluid and the second fluid located in the first portion. The volume of the second fluid is injected into the first chamber, displacing an equivalent volume of fluid into a third chamber of the test system via a second portion connecting the first chamber and the third chamber in fluid communication with each other. The volume of the second fluid in the first chamber is mixed with a remaining volume of the first fluid in the first chamber to create a combination fluid. The combination fluid is tested.

Abstract: The present invention relates to a method for testing the tightness of cavities, which are already filled with a stored gas, by charging the with a test gas. At least the following steps are provided: overlayering the stored gas situated in the cavity with a test gas of a predefined amount, in such a manner that a barrier layer forms between the stored gas and the test gas, wherein the test gas has a lower density than the stored gas, releasing the test gas after a predetermined time, and balancing the amount of the test gas. A further aspect is providing a device for decreasing the convection and diffusion flow between a stored gas situated in a cavity and a test gas.

Abstract: A method for optimizing drilling fluids by creating a proper particle size analysis and distribution curve of particle sizing within drilling fluid. The particle size distribution curve is maintained with a maximum particle sizing of 6 microns so as to not allow for coarser drilled solids to degrade beyond the point of mechanical separation to prevent a build-up of low gravity solids that can no longer be removed from the drilling fluid during the drilling operation due to their size. An optimal drilling system requires that drilling fluids be modified through the following process to attain the appropriate particle sizing distribution to: make the most efficient use of the drilling operation, reduce the amount to drilling fluids utilized, and reduce formation damage. The method generates corrective actions to modify the drilling fluids or adjust solids control equipment parameters, to obtain a unique particle size distribution throughout the drilling process.

Abstract: Example methods and apparatus for determining downhole parameters are disclosed herein. An example method includes pumping a fluid in a first direction to substantially fill a first area of a fluid flow passageway with the fluid and determining a fluid parameter via a sensor disposed in a second area adjacent the first area. The sensor includes a heater and a temperature sensor. The example method also includes determining if the first fluid has flowed in a second direction into the second area based on the fluid parameter.

Abstract: An apparatus and method of measuring a parameter characteristic of a rock formation in an oil well is provided with a device for generating a sensing field within a volume of the rock formation and a device for causing a flow through the volume in the presence of the sensing field, further including sensors responsive to changes in the volume, wherein a sensor response is indicative of the amounts of fluid, particularly hydrocarbon and water saturations and irreducible hydrocarbon and water saturations. Measurements can be made before the flow affects the measuring volume and after onset of the flow through the measuring volume.

Abstract: A simple, applicable in the field, and extra-equipment free method is provided for determining steam dryness directly in a thermal recovery of high-viscosity oil. A non-condensable gas is added into a saturated steam being injected into a well. The presence of non-condensable gas changes partial steam pressure. Correspondingly the steam condensation temperature also changes. The borehole temperature or pressure measurements can be used to evaluate the steam dryness.

Abstract: A method for estimating properties of a subterranean formation penetrated by a wellbore provides for injecting a fluid with the plurality of tracer agents wherein each tracer agent is an object of submicron scale, into the wellbore and formation, flowing the fluid back from the subterranean formation and determining the properties of the formation. The properties are determined by analyzing changes in the tracers size and type distribution function between the injection fluid and produced fluid.

Abstract: A well passing through a geological formation is fitted with a tube, open at its bottom end, that is filled with a fluid. Another fluid is in the annular space between the tube and the wall of the well, the two fluids exhibiting an interface situated in the annular space. A hydraulic balance of the fluids of the well is disturbed and the trend of certain quantities is measured. These measurements are moreover simulated by computer by using different sets of values for the physical parameters, and efforts are made to estimate the geological formation. A comparison of the measurements with the simulation results makes it possible to identify an optimum set of values for the parameters.

Abstract: The present invention relates an Integral analysis method of inter-well tracer tests, which integrates and performs continuous feedback to each of the major stage (design, operation and interpretation) allowing quantitative interpretation of these tests. It is presented as a tool to investigate the behavior of injection fluids for recovery of hydrocarbons, as well as for the dynamic characterization of reservoirs. The main advantage of this invention is that it allows a greater certainty in the tracer response and a marked improvement in the sensitivity and quantitative analysis of the test results, since the curves fit both with mathematical models and numerical models. Another outstanding attraction of this invention is the reduction in the costs of testing such applications.

Abstract: A method for monitoring production from a methane hydrate reservoir includes obtaining a plurality of temperature measurements in a wellbore connected with the methane hydrate reservoir; and deriving a parameter relating to conversion of methane hydrate to carbon dioxide (CO2) hydrate by injection of liquid CO2, wherein the deriving uses a modeling program and the plurality of temperature measurements, wherein the modeling program uses at least one parameter relating to a thermodynamic properties that are substantially different between methane and CO2. The at least one parameter relating to thermodynamic properties may include Joule-Thomson coefficients of methane and CO2. The parameter relating to the conversion of methane hydrate to CO2 hydrate may include a ratio of methane and CO2 in a mixed fluid.

Abstract: A method and system of locating discontinuities in a reservoir are provided. The method includes identifying a plurality of injection and production sites in the reservoir, injecting fluid into selected injection sites in accordance with an injection schedule, monitoring an output at the production sites, determining a time delay between the injection sites and the production sites based on the monitored output, and determining a location of discontinuities based on the determined time delay.

Abstract: A method comprising: estimating a change in a characteristic of a subterranean formation into which a fluid has been injected via a well extending into the subterranean formation; building a multi-dimensional model balancing mass of the injected fluid, wherein the model is based on the estimated characteristic change; utilizing the model to determine the sensitivity of a borehole gravity tool in the well; measuring gravity with the borehole gravity tool at a plurality of stations along the well; and utilizing the model and the gravity measurements to locate the injected fluid in the subterranean formation.

Abstract: A machine, computer program product, and method to enable scalable parallel reservoir simulations for a variety of simulation model sizes are described herein. Some embodiments of the disclosed invention include a machine, methods, and implemented software for performing parallel processing of a grid defining a reservoir or oil/gas field using a plurality of sub-domains for the reservoir simulation, a parallel process of re-ordering a local cell index for each of the plurality of cells using characteristics of the cell and location within the at least one sub-domain and a parallel process of simulating at least one production characteristic of the reservoir.

Abstract: A method for performing fluid influx tests in a wellbore comprises inserting a well test device into the wellbore such that it separates a well test section from other sections of the wellbore; performing a first fluid influx test during which fluid pressure in the test section is reduced, pore fluid is induced to flow into the test section and fluid influx into the test section is monitored; injecting a completion fluid into the test section, and inducing the completion fluid to flow into the formation; performing a second fluid influx test during which fluid pressure within the test section is reduced, completion and pore fluids are induced to flow into the test section, and fluid influx into the test section is monitored; comparing fluid influx monitoring data acquired during the fluid influx tests to determine any effects of the completion fluid on formation pore fluid influx into the test section.

Abstract: The present invention relates to the development of tracer fluids, more generally, that of aqueous liquids, intended to be injected under pressure in an oil reservoir, for example from an injection well up to a production well. The object of the invention is to propose a new method of study of a solid medium, i.e. an oil reservoir, by diffusion of a liquid (i.e. injection waters) containing tracers, through said solid medium, which is simple to implement and economical and which remedies the drawbacks of the known tracers for injection waters of oil reservoirs.

Abstract: This invention relates to a process utilizing natural carbon-13 isotope for identification of early breakthrough of injection water in oil wells. All natural water sources are labeled by unique ratios of carbon isotopes (13C/12C). Following the requirements of the invention, the carbon isotope ratio for oil bearing formation water and for local aquifer water which is to be injected in to the oil reservoir rock is determined. The carbon isotope ratio of the produced water from the selected oil wells is then monitored periodically. When the carbon isotope ratio of the produced (oil well) water shows deviation from the formation water value and tends towards injection water value, then the early breakthrough phenomenon of injection water is identified. Thus the contrast in natural carbon isotope ratios of injection water, formation water and produced water from selected oil wells serve as tracer in the identification of “Early Breakthrough” phenomenon of injection water and its movement.

Abstract: A wireline logging tool and method for fluid monitoring and flow characterization in individual zones of controlled salinity is disclosed. The tool and method advantageously facilitate zone-specific testing. Sets of packers are used to create hydraulically distinct zones proximate to the tool. Coiled tubing and isolation valves are used to selectively introduce and remove an electrically conductive fluid such as brine to and from a selected zone. Individual sensors are disposed near each zone to make zone-specific measurements while fluid properties are changed, e.g. while salinity is changed to cause salinity fronts in the formation.

Abstract: Testing process for testing hydrocarbon wells at zero emissions in order to obtain general information on a reservoir. The process includes injecting into the reservoir a suitable liquid or gaseous fluid, compatible with the hydrocarbons of the reservoir and with the formation rock, at a constant flow-rate or with constant flow rate steps, and substantially measuring, in continuous, the flow-rate and injection pressure at the well bottom. Then, the well is closed and the pressure is measured during the fall-off period (pressure fall-off). The measured fall-off data is interpreted in order to evaluate the average static pressure of the fluids (Pav) and the reservoir properties including actual permeability (k), transmissivity (kh), areal heterogeneity or permeability barriers and real Skin factor (S). Then, well productivity is calculated.

Abstract: An apparatus and method of measuring a parameter characteristic of a rock formation in an oil well is provided with a device for generating a sensing field within a volume of the rock formation and a device for causing a flow through the volume in the presence of the sensing field, further including sensors responsive to changes in the volume, wherein a sensor response is indicative of the amounts of fluid, particularly hydrocarbon and water saturations and irreducible hydrocarbon and water saturations. Measurements can be made before the flow affects the measuring volume and after onset of the flow through the measuring volume.

Abstract: Systems and methods for determining at least one parameter of a fluid in a well are provided. The system has a downhole system deployable into the well, and sensor elements to measure fluid parameter(s) of the fluid in the well. Each of the sensor elements is provided with a base and sensors. The base is positionable on the coiled tubing system about the injection port. The sensors are positionable in the base. Each of the sensors are thermally isolated from each other, and are capable of operating as both a heater to heat the fluid, and as a temperature sensor for measuring a temperature of the fluid. The sensors are operatively interchangeable such that the sensors may selectively heat and measure the temperature of the fluid whereby fluid parameters of the fluid are determined.

Abstract: A system for testing a wellbore fluid includes a test chamber having first and second platens therein. The chamber is in a thermally insulating enclosure. The enclosure includes a heating element. The platens simulate response of the wellbore fluid through an hydraulically induced fracture in subsurface rock formation. The system includes means to control a distance between the platens. A pump introduces the wellbore fluid into a space between the platens and another pump introduces a pressure test fluid into contact with the wellbore fluid. A respectve pressure sensor is in fluid communication with a discharge side of each pump, and a sensor is included to measure a parameter related to the position of the second platen or the space between the platens. A data acquisition and control device is configured to detect signals from the respective pressure transducers and the sensor.

Abstract: Solvent-dominated hydrocarbon recovery processes use chemical solvent(s), rather than a heat-transfer agent, as the principal means to achieve hydrocarbon viscosity reduction. Such processes are fundamentally different from thermally-dominated recovery processes and have unique challenges. Field measurements described herein, such as the rate of solvent production, can be used to manage solvent-dominated hydrocarbon recovery processes, for instance for improving hydrocarbon recovery or solvent efficiency.

Abstract: Methods and related systems are described for making measurements at multiple locations in an annular region of a cased sequestration well. A first tool module is positionable within the well and adapted to directly or indirectly measure changing pressure at a first location in the annular region of the well. A pressure change is induced at the first location in the annular region. A second tool module is positionable within the well and adapted to directly or indirectly measure changing pressure at a second location in the annular region. The measured pressure changes at the second location are in response to the induced pressure change at the first location.

Abstract: A method of analyzing a subterranean formation. The method includes specifying a volume of interest in the subterranean formation, specifying an injector wellsite that penetrates the volume of interest, specifying a first producer wellsite and a second producer wellsite, each of which penetrates the volume of interest, calculating a first Injectivity-Productivity Index (IPI) for a first injector-producer wellsite pair which includes the injector wellsite and the first producer wellsite, calculating a second IPI for a second injector-producer wellsite pair which includes the injector wellsite and the second producer wellsite, determining whether the first IPI is substantially equal to the second IPI to obtain an analysis result, and adjusting a wellsite operation based on the analysis result.

Abstract: A method of retrieving a formation fluid from a formation adjacent a borehole wall includes estimating at least one of a permeability of the formation and a viscosity of the formation fluid. A first tool is selected based on the estimation, the first tool being selected from one of a heating and sampling tool, an injection and sampling tool, and a coring tool. An attempt to retrieve a formation fluid sample from the formation is then made with the first tool, and a formation fluid sample is retrieved from the formation. A second retrieval process may then be initiated, in which the second retrieval process includes increasing the mobility of the formation fluid.

Abstract: A method for performing fluid influx tests in a wellbore (3) traversing a permeable formation (4) to test the compatibility of one or more completion fluids comprises: a) inserting a well test device (1) comprising a straddle packer assembly (6A,6B) into the wellbore (3) such that the straddle packer assembly (6A,6B) separates a well test section (13) from other sections of the wellbore; b) performing a first fluid influx test during which the fluid pressure the test section (13) is reduced, pore fluid is induced to flow from the pores of the permeable formation (4) into the test section (13) and fluid influx into the test section (13) is monitored; c) injecting a completion fluid into the test section (13), thereby increasing the fluid pressure within the test section and inducing the completion fluid to flow into the pores of the surrounding formation (4); d) performing a second fluid influx test during which the fluid pressure within the test section (13) is reduced, the completion fluid and pore fluid are

Abstract: A method of testing the response of a subterranean formation to a formation treatment is described including the injection of a treatment fluid and the production of formation fluids from two separate boreholes or two boreholes from a single well such that the treatment fluid sweeps the formation between the two boreholes, and the use of downhole monitoring devices to determine a volume swept by the treatment fluid.

Abstract: The present invention relates to a sensor assembly for downhole use in a wellbore. This invention also relates to a new pack-off assembly housing the sensor. The new pack-off assembly protects the sensor from the environment and from impact damage. Additionally, the new pack-off assembly allows for the testing of the sensor immediately prior to insertion into the wellbore.

Abstract: A method of detecting a lateral boundary of a compacting or expanding region in a subsurface formation, which method comprises determining non-vertical deformation of the earth' s surface above the subsurface formation over a period of time; identifying at least on contraction area and at least one adjacent dilatation area of the earth' s surface from the non-vertical deformation over the period of time; and using the contraction area and the adjacent dilatation area as an indication of a lateral boundary of the compacting or expanding region; and a method for producing hydrocarbons.

Abstract: A method of retrieving a formation fluid from a formation adjacent a borehole wall includes estimating at least one of a permeability of the formation and a viscosity of the formation fluid. A first tool is selected based on the estimation, the first tool being selected from one of a heating and sampling tool, an injection and sampling tool, and a coring tool. An attempt to retrieve a formation fluid sample from the formation is then made with the first tool, and a formation fluid sample is retrieved from the formation. A second retrieval process may then be initiated, in which the second retrieval process includes increasing the mobility of the formation fluid.

Abstract: This invention relates to a process utilizing natural carbon-13 isotope for identification of early breakthrough of injection water in oil wells. All natural water sources are labeled by unique ratios of carbon isotopes (13C/12C). Following the requirements of the invention, the carbon isotope ratio for oil bearing formation water and for local aquifer water which is to be injected in to the oil reservoir rock is determined. The carbon isotope ratio of the produced water from the selected oil wells is then monitored periodically. When the carbon isotope ratio of the produced (oil well) water shows deviation from the formation water value and tends towards injection water value, then the early breakthrough phenomenon of injection water is identified. Thus the contrast in natural carbon isotope ratios of injection water, formation water and produced water from selected oil wells serve as tracer in the identification of “Early Breakthrough” phenomenon of injection water and its movement.

Abstract: Although the methods have been described here for, and are most typically used for, hydrocarbon production, fluid diversion measurement systems and methods are described. One method includes inserting a tubular tubing having one more fluid injection ports into a wellbore, injecting a treatment fluid through the injection port, and determining differential flow of the treatment fluid at one or more wellbore based on measuring the concentration of at least one particular component of a wellbore fluid located in the annulus formed between the wellbore and tubular; and using the measured parameters in realtime to monitor, control, or both monitor and control diversion of the fluid.

Abstract: Methods for performing downhole fluid compatibility tests include obtaining an downhole fluid sample, mixing it with a test fluid, and detecting a reaction between the fluids. Tools for performing downhole fluid compatibility tests include a plurality of fluid chambers, a reversible pump and one or more sensors capable of detecting a reaction between the fluids.

Abstract: A method of testing the response of a subterranean formation to a formation treatment is described including the injection of a treatment fluid and the production of formation fluids from two separate boreholes or two boreholes from a single well such that the treatment fluid sweeps the formation between the two boreholes, and the use of downhole monitoring devices to determine a volume swept by the treatment fluid.