Baker Hughes Oilfield Operations LLC

Baker Hughes, a Ge Compnay, LLC

Saudi Arabian Oil Company

Guodong Jin

Hasan Kesserwan

Salah Mohammed Al-Ofi

Syed Shujath Ali

Shouxiang Mark Ma

Jilin Jay Zhang

Jinhong Chen

Elton Frost, Jr

Baoyan Li

Julio Roberto Arro

Terrence H Quinn

Holger Thern

Fei Le

Umesh Prasad

Alberto Mezzatesta

Glen Murrell

Ali Al Dhamen

Ryan Antle

Bilal Saad

Seehong Ong

A method of analyzing a downhole fluid includes performing measurements of a dielectric property of the downhole fluid, the downhole fluid including a mixture of a filtrate fluid circulated through a borehole and a connate fluid. The measurements include a first measurement of the downhole fluid, and one or more additional measurements, each additional measurement performed after an amount of the filtrate fluid is injected into the downhole fluid to change the volume ratio, each additional measurement performed when the downhole fluid has a different volume ratio. The method also includes acquiring a plurality of reference profiles of respective reference mixtures, the respective reference mixtures including a first fluid and a reference fluid, comparing the measurements to each reference profile, and estimating a value of the dielectric property of the connate fluid based on the comparing.

Estimation of dielectric properties of a downhole fluid

Methods and systems include using downhole data to determine a static bulk modulus of dry rock or rock frame in a porous formation and determine a static bulk modulus of grain minerals in the porous formation. Biot's coefficient for the porous formation can be determined based on the static bulk modulus of dry rock or rock frame and the static bulk modulus of grain minerals. Effective stress of the porous formation can be determined based on Biot's coefficient. Effective stress of the porous formation is used in geomechanical applications, including hydraulic fracturing, wellbore stability analysis, and reservoir integrity assessments.

Geomechanical applications using Biots coefficient based on advanced downhole logging measurements

A system for analysis of isolated and connected porosities of a porous formation using permittivity is disclosed. An electrical subsystem can provide electrical signals for one or more of the porous formation or a representation of the porous formation; and the system can determine one or more of a rate of permittivity change (RPC) or permittivity ratio (PR) from a first estimation model that relates permittivity measurements and frequencies that are associated with the electrical signals, so that the system can generate a second estimation model using one or more of the RPC or the PR, associated with the isolated and connected porosities, where the second estimation model can be used with a total porosity of the porous formation to estimate or predict an isolated porosity and a connected porosity of a production porous formation.

System and method for estimating porosity of porous formations using permittivity measurements

Examples described herein provide a computer-implemented method for deriving textural properties of a reservoir formation. The method includes acquiring multi-frequency dielectric data (ε). The method further includes applying a dielectric mixing model between different fluid phases to generate an effective fluid permittivity (ε) by mixing the permittivity of water and hydrocarbon fluids. The method further includes applying the dielectric mixing model between the effective fluid permittivity (ε) and a matrix permittivity (ε). The method further includes minimizing a difference between a measured dielectric response and the dielectric mixing model by optimizing model parameters. The method further includes computing a cementation exponent (m) and a saturation exponent (n) from the multi-frequency dielectric data (ε). The method further includes estimating a formation property based at least in part on the cementation exponent (m) and the saturation exponent (n). A wellbore operation is controlled based at least in part on the formation property.

Determine a formation's textural parameters using advancing logging data

Systems and methods to evaluate a formation by analyzing drill cuttings involve a multi-frequency dielectric coaxial probe to obtain a reflected voltage from a medium under test based on a reference voltage over a frequency range. The medium under test includes the drill cuttings. The system includes a processor to compute an effective permittivity of the drill cuttings over the frequency range based on a reflection coefficient, which is a ratio of the reflected voltage to the reference voltage over the frequency range, and to determine one or more parameters from the effective permittivity. The one or more parameters are used to make decisions about subsequent drilling in the formation.

Multi-frequency dielectric coaxial probe for formation analysis

A method of estimating a material mechanical property of a porous material, for an application or objective with a specific application frequency and application strain amplitude, includes estimating an application frequency and an application strain amplitude for use in a targeted application or objective, and constructing a frequency transfer function relating the material mechanical property to measurement frequencies, the measurement frequency range including a measurement frequency different from the application frequency. The method also includes constructing a strain amplitude transfer function relating the material mechanical property at the measurement strain amplitude and the material mechanical property at the application strain amplitude, the measurement strain amplitude different from the application strain amplitude, deriving the material mechanical property from the frequency transfer function using the application frequency, and predicting the material mechanical property from the strain amplitude transformation function using the derived material mechanical property.

Estimation of objective driven porous material mechanical properties

A method of estimating properties of a resource bearing formation includes receiving, by a processor, a measured echo train generated by a nuclear magnetic resonance (NMR) measurement device deployed in a region of interest, and a measured noise of the measured echo train, and calculating a Tdistribution subject to a nonlinear equality constraint, the nonlinear equality constraint dependent on the measured noise and a fitting error between the measured echo train and a modeled echo train. Calculating the Tdistribution includes estimating a solution for the Tdistribution that is closest to satisfying the nonlinear equality constraint.

Inversion of NMR echo trains using a supplementary nonlinear equality constraint

A method for transforming an earth formation and/or production equipment based on correcting nuclear magnetic resonance (NMR) data to account for partially water-saturated rock includes: receiving NMR logging data having echo-trains for an earth formation; inverting the echo-trains to provide transverse relaxation time constant (T) distributions for various components of fluid in the earth formation; substituting a Tdistribution for mobile water of fully water-saturated rock for a Tdistribution for mobile water of partially water-saturated rock based on values of the mobile water Tdistribution of partially water-saturated rock and a total porosity constraint; summing the Tdistribution for mobile water of fully water-saturated rock and a Tdistribution for an immobile water component of the fluid to provide a T, distribution for fully water-saturated rock; and transforming the earth formation and/or the production equipment based on a parameter derived from the Tdistribution for fully water-saturated rock.

Fluid substitution method for T2 distributions of reservoir rocks

An apparatus is disclosed for identifying a fluid and locations of the fluid in a formation of shale having porous kerogen material and an inorganic matrix defining pores and micro-fractures. The apparatus includes: a carrier configured to be conveyed through a borehole penetrating the shale; a nuclear magnetic resonance (NMR) tool disposed at the carrier and configured to perform NMR measurements on the shale, the NMR measurements include a spectrum of transverse relaxation times; and a processor configured to receive NMR measurements on the shale performed by the NMR tool and to identify the fluid and locations of the fluid in the shale using the spectrum of transverse relaxation times.

Hydrocarbon determination in unconventional shale

Methods and apparatus for evaluation of an earth formation including evaluating a core sample obtained from the formation. Methods include using a change in measurements of at least one stress parameter of the core sample, such as radial strain, axial stress, and acoustic emission counts, over time responsive to an applied stress to estimate imminent rock failure in the core sample. This may include estimating the imminent rock failure using differences between portions of a curve generated based on the measurements. A method employing calculating a rate of change between a plurality of measurements of at least one stress parameter of the core sample over time responsive to an applied stress; and determining a point of imminent failure using the rate of change in the plurality of measurements of the at least one stress parameter is also included.

Determining the imminent rock failure state for improving multi-stage triaxial compression tests

An apparatus for identifying a fluid and locations of the fluid in a formation of shale having porous kerogen material and an inorganic matrix defining pores and micro-fractures includes: a carrier configured to be conveyed through a borehole penetrating the shale; a nuclear magnetic resonance (NMR) tool disposed at the carrier and configured to perform NMR measurements on the shale, the NMR measurements include a spectrum of transverse relaxation times; and a processor configured to receive NMR measurements on the shale performed by the NMR tool and to identify the fluid and locations of the fluid in the shale using the spectrum of transverse relaxation times.

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Katy, TX, United States of America

Guodong Jin