Schlumberger Technology Corporation

Schlumberger Canada Limited

Services Petroliers Schlumberger

Schlumberger Holdings Limited

Prad Research and Development Limited

Peter S Hegeman

Kai Hsu

Ricardo Vasques

Anthony R H Goodwin

Chengli Dong

Oliver Clinton Mullins

Kentaro Indo

Cosan Ayan

Charles Woodburn

Adriaan Gisolf

Christopher Del Campo

Soraya Sofia Betancourt

Carsten Sonne

Lennox Reid

Mustafa Onur

Tsutomu Yamate

Bhavani Raghuraman

Ronald E G Van Hal

Michael O'Keefe

Anthony Goodwin

Francois Xavier Dubost

Moin Muhammad

Andrew Carnegie

Sihar Marpaung

Oliver C Mullins

Andrew L Kurkjian

Julian J Pop

Gary John Tustin

Xu Wu

Sylvain Bedouet

Stephane Vannuffelen

Go Fujisawa

Toru Terabayashi

Fikri John Kuchuk

Ahmed Hammami

Raymond V Nold, Iii

Ryan Sangjun Lee

Ashley C Kishino

John Ratulowski

John Allan Nighswander

Kazumasa Kanayama

Fikri Kuchuk

Richard Jackson

Michael M Toribio

Erwan Olliero

ChengGang Xian

Graham Birkett

Keith A Burgess

Ahmad Saputra

Ihsan Murat Gok

Nikos Varotsis

Vassilis Gaganis

Jichao Chen

Raymond G Kennedy

Michael O'KEEFE

Anthony Rh Goodwin

Michael O'keefe

Soraya S Betancourt

Hani M Elshahawi

Andrew J Carnegie

A system and method determine formation permeability and/or at least one property indicative of formation permeability of a subsurface geological reservoir having radial-flow. Pressure data is obtained with an observation probe during a formation test, wherein the observation probe is located at a setting position within an open hole wellbore formed within the reservoir. The system and method measure radial-flow response of the reservoir at or adjacent to the setting position of the observation probe by analyzing the collected pressure data. The formation permeability and/or at least one property indicative of the permeability of the reservoir is determined based on the measured radial-flow response of the reservoir at or adjacent to the observation probe.

Method for determining a permeability or mobility of a radial flow response of a reservoir

A method including positioning a formation testing tool within a wellbore formed within a subsurface reservoir, wherein the tool has a focused opening to enable fluid communication with the reservoir, and the tool has a horizontally-displaced observation probe configured to obtain pressure data; determining one of horizontal permeability and horizontal mobility of the reservoir based on measuring a flow response of the subsurface reservoir one of at and adjacent to the observation probe; and determining orthogonal components of one of the horizontal permeability and horizontal mobility based on the measured flow response.

Detection of permeability anisotropy in the horizontal plane with a formation testing tool

Samples of hydrocarbon are obtained with a coring tool. An analysis of some thermal or electrical properties of the core samples may be performed downhole. The core samples may also be preserved in containers sealed and/or refrigerated prior to being brought uphole for analysis. The hydrocarbon trapped in the pore space of the core samples may be extracted from the core samples downhole. The extracted hydrocarbon may be preserved in chambers and/or analyzed downhole.

Obtaining and evaluating downhole samples with a coring tool

A tool is to be used within a wellbore including a wall and extending into a formation with formation fluid. The tool includes a packer expandable against the wellbore wall with ports included within the packer to enable formation fluid to flow into the tool from the formation. The ports are arranged in a first port configuration optimized based upon a first predetermined formation property.

Packer tool including multiple port configurations

A method for detection of permeability anisotropy, having steps of positioning a formation testing tool, conducting a series of three flow tests with the testing tool wherein a first test is a four drain flow test, a second test is a pair of opposite drains flowing on diametrically opposite sides of the formation testing tool and a third test is a second pair of opposite drains flowing on opposite drains different than the second test; determining one of horizontal permeability and horizontal mobility, determining one of orthogonal components of horizontal permeability and horizontal mobility based on the measured flow response and determining a direction of the orthogonal components of the horizontal permeability or horizontal mobility with respect to the orientation of the formation testing tool based on a measured flow response.

Detection of permeability anisotropy in the horizontal plane

Variable volume systems and methods of use thereof described herein are capable of making calibrated determinations of fluid properties and phase behavior of a fluid sample. The determinations can be calibrated based on one or more calibration functions, such as system volume corrected for pressure and temperature variations. Cross-checking the results of measurements can be used to determine accuracy of the calibration or monitor for leaks or other anomalies of the variable volume systems. The variable volume systems can be implemented in a well logging tool and are capable of being calibrated downhole.

Calibration and consistency check of variable volume systems

A system and method for determining at least one fluid characteristic of a downhole fluid sample using a downhole tool are provided. In one example, the method includes performing a calibration process that correlates optical and density sensor measurements of a fluid sample in a downhole tool at a plurality of pressures. The calibration process is performed while the fluid sample is not being agitated. At least one unknown value of a density calculation is determined based on the correlated optical sensor measurements and density sensor measurements. A second optical sensor measurement of the fluid sample is obtained while the fluid sample is being agitated. A density of the fluid sample is calculated based on the second optical sensor measurement and the at least one unknown value.

Fluid density from downhole optical measurements

Methods and apparatus for detecting a coating on a downhole fluid sensor are disclosed. A coating may refer to a solid or liquid film on a sensor interface with the sampled fluid, caused by contaminants. Detecting a coating may be accomplished by determining a sampled fluid type and measuring at least one fluid parameter using one or more downhole fluid sensors. The coating detection further includes determining whether the measured parameters are within ranges corresponding to the determined fluid type. Additionally or alternatively, measured parameter values that remain substantially stable during sampled fluid pumping may also indicate a coated sensor.

Methods and apparatus to detect contaminants on a fluid sensor

Methods and related systems are described relating to monitoring particulates downhole at in-situ conditions. Solid particles being carried in the fluid as the fluid is produced from the reservoir formation are monitored. The downhole solid particle monitoring can include measuring the quantity (e.g., volume fraction, weight fraction, or the like) of solid particles, measuring the distribution of sizes of the solid particles, and/or measuring the shape of the particles. The solid particles can be monitored using one or more of sensors such as optical spectrometers, acoustic sensors, video cameras, and erosion probes. A sanding prediction is generated based at least in part on the monitoring of the solid particles, and the sanding prediction is then used to design a completion, lift system, and surface facilities for the wellbore and/or select operating conditions so as to control sanding during production.

In-situ evaluation of reservoir sanding and fines migration and related completion, lift and surface facilities design

Methods of calibrating a fluid analyzer for use in a wellbore are described. An example method of generating calibration data for a fluid analyzer for use in a downhole tool involves lowering a downhole tool including a fluid analyzer to a location in a wellbore, measuring, via the fluid analyzer, a characteristic value of a calibration fluid or a vacuum while the fluid analyzer is at the location, obtaining an expected characteristic value for the calibration fluid or the vacuum at the location, and comparing the measured characteristic value to the expected characteristic value to generate a calibration value for the fluid.

Methods of calibrating a fluid analyzer for use in a wellbore

Example methods and apparatus to detect phase separation in downhole fluid sampling operations are disclosed. An example method to detect a phase separation condition of a fluid from a subterranean involves obtaining a sample of the fluid, measuring a first characteristic value of the sample, measuring a second characteristic value of the sample and comparing the first characteristic value to a first reference value associated with a single-phase condition of the fluid to generate a corresponding first comparison result. The example method then compares the second characteristic value to a second reference value associated with the single-phase condition of the fluid to generate a corresponding second comparison result and detects the phase separation condition of the fluid based on the first and second comparison results.

Phase separation detection in downhole fluid sampling

A method for determining permeability of a reservoir using a packer-probe formation testing tool. The elements of the method include generating, using a dual packer tool module, fluid flows from the reservoir into a wellbore, obtaining pressure data associated with the fluid flows using an observation probe tool module, wherein the packer-probe formation testing tool comprises the dual packer module and the observation probe tool module, identifying a portion of the pressure data corresponding to a spherical flow regime, determining horizontal permeability based on the portion of the pressure data, and displaying an output generated using the horizontal permeability.

Thickness-independent computation of horizontal and vertical permeability

A method of sampling fluid from a subterranean formation includes positioning a first tool having a heater in a borehole so that the heater is adjacent a portion of the subterranean formation; heating with the heater the portion of the subterranean formation; removing the first tool from the borehole; orienting a second tool having a sampling probe in the borehole so that the sampling probe is to contact a portion of the subterranean formation heated by the heater; and obtaining via the sampling probe a fluid sample from the portion of the subterranean formation heated by the heater.

Apparatus to sample heavy oil from a subterranean formation

A system and method for obtaining a clean fluid sample for analysis in a downhole tool are provided. In one example, the method includes directing fluid from a main flowline of the downhole tool to a secondary flowline of the downhole tool. While the fluid is being directed into the secondary flowline, sensor responses corresponding to the fluid in the secondary flowline are monitored to determine when the sensor responses stabilize. The secondary flowline is isolated from the main flowline after the sensor responses have stabilized. A quality control procedure is performed on the fluid in the secondary flowline to determine whether the captured fluid is the same as the fluid in the main flowline. Additional fluid from the main flowline is allowed into the secondary flowline if the captured fluid is not the same.

Clean fluid sample for downhole measurements

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Stafford, TX, United States of America

Peter S Hegeman