Schlumberger Technology Corporation

M-1 L.l.c.

Services Petroliers Schlumberger

Lijein Lee

James Stark

Steven Philip Young

Emanuel Stamatakis

Hui Joyce Zhang

Xia Wei

Quanxin Guo

Brandi Katherine Price Hoelscher

Changping Sui

James Friedheim

Guido De Stefano

John Moffitt

Sashikumar Mettath

Jorge Arias Prada

Arvind D Patel

Chemsseddine Bouguetta

Pawilai Chinwangso

Yiyan Chen

Bruno Lecerf

Eric James Davis

Dimitri M Khramov

Mark Luyster

Balakrishnan Panamarathupalayam

Reda Karoum

Aaron Blue

Stephen Cliffe

Karim Bondabou

Kenneth Slater

Tetsushi Yamada

Jeremy Smith

Maneesh Pisharat

Hui Zhang

Josh Sheldon

Meghan Ruth Riley

Leigh Gray

Eugene Dakin

Chris Shepherd

Weiqing Huang

A method for evaluating solid drilling fluid additives such as lost cuttings materials (LCM) includes acquiring a calibrated digital image of solid particles separated from drilling fluid circulating in a wellbore. The calibrated digital image is processed to identify individual ones of the solid particles depicted in the image. Color features and/or texture features are extracted from the identified solid particles depicted in the image. The extracted color and/or texture features are processed to identify LCM particles among the identified solid particles and to classify each of the identified LCM particles into one of a plurality of LCM classes and thereby obtain an LCM particle classification.

Automated identification and quantification of solid drilling fluid additives

A wellbore fluid comprising an aqueous base fluid and a plurality of nanoparticles suspended in the aqueous base fluid. The nanoparticles are present in the wellbore fluid in an amount effective to have an effect of increasing the density by at least 0.2 lb/gal.

Methods for completing a wellbore using high density brine containing colloidal particles

A method of recycling a direct emulsion wellbore fluid may include disrupting a direct emulsion comprising an aqueous external phase and an oleaginous internal phase, wherein the direct emulsion is stabilized by a surfactant composition; and separating the aqueous phase and the oleaginous phase.

Methods of recycling oil from a direct phase emulsion

A device includes a housing having a bore formed axially therethrough. The housing includes a stop that protrudes radially inward proximate to a lower end of the housing. The device also includes a lower piston positioned in the bore. The lower piston is configured to move axially within the bore in response to a pressure differential across the lower piston. The lower piston is prevented from passing out through the lower end of the housing by the stop. The lower piston has a lower piston hole formed therethrough. The device also includes an upper piston positioned in the bore. The upper piston is configured to move axially within the bore in response to a pressure differential across the upper piston. The upper piston has an upper piston hole formed therethrough. The device is configured to receive a fluid in the bore, between the upper and lower pistons.

System and method for measuring properties of a fluid

A wellbore fluid comprising a first aqueous base fluid and a plurality of silica nanoparticles suspended in the first aqueous base fluid. The nanoparticles are present in the fluid in an amount to have an effect of decreasing a crystallization temperature by at least 4 to 55&#xb0; F. as compared to a second aqueous base fluid without the silica nanoparticles.

High density brine with low crystallization temperature

A method of drilling a wellbore includes pumping an oleaginous wellbore fluid into a wellbore, the oleaginous wellbore fluid including an oleaginous continuous phase; a non-oleaginous discontinuous phase; an emulsifier stabilizing the non-oleaginous discontinuous phase in the oleaginous continuous phase; an organophilic clay; a weighting agent; and a wetting agent having an HLB ranging from about 4 to 10.5 that it selected such that the oleaginous wellbore fluid has a 600 rpm dial value at 40&#xb0; F. of less than about 300 and a 10 minute gel strength of less than about 40 lbf/100 ft.

Fluids and methods for mitigating sag and extending emulsion stability

A wellbore fluid may include an oleaginous fluid forming a continuous phase; a non-oleaginous fluid forming a discontinuous phase; at least one emulsifier stabilizing an emulsion of the non-oleaginous continuous phase within the oleaginous continuous phase; and at least one viscosifier dispersed into the oleaginous continuous phase in a concentration of at least 4 ppb; wherein upon subjecting the wellbore fluid to shear rate of at least 10,000 s, the emulsion is disrupted and the non-oleaginous fluid contacts the at least one viscosifier, thereby solidifying the wellbore fluid.

Methods for wellbore strengthening

A fluid may include an aqueous based continuous phase, a pH adjusting additive, wherein the pH adjusting additive is formic acid, and a clay hydration suppressant agent having the formula HNCH(CH)CH(OCH(CH)CH)NH, wherein x is a value less than 15.

High performance water based fluid

A method of sealing a formation that includes drilling a wellbore through the formation while pumping a non-aqueous based wellbore fluid comprising a first sealing component into the wellbore, wherein the non-aqueous based wellbore fluid filters into the formation as a filtrate and substantially thickens is disclosed. The substantially thickening may result from adding a second sealing component to the wellbore fluid, whereby the first sealing component initiates a reaction of the second sealing component.

Smart filtrate for strengthening formations

Emulsion-preventing compositions may contain one or more sorbitan esters; and one or more non-ionic surfactants; where the ratio of the one or more sorbitan esters to the one or more non-ionic surfactants is in the range of 1:1 to 1:5. Methods may include contacting an emulsion with a treatment fluid, the treatment fluid containing one or more sorbitan esters and one or more non-ionic surfactants, where the ratio of the one or more sorbitan esters to the one or more non-ionic surfactants is in the range of 1:1 to 1:5; and separating the emulsion into an aqueous phase and an oleaginous phase.

Emulsion preventer for completion brines

A insulating annular fluid for reducing convective currents in the annular region a wellbore is provided that includes an oleaginous fluid, a silica, and, in some embodiments, organoclay.

Insulating annular fluid

In one aspect, embodiments disclosed herein relate to an oil-based wellbore fluid. The oil-based wellbore fluid may include an oleaginous liquid and a surface-modified precipitated silica, wherein the surface-modified precipitated silica comprises a lipophilic coating. In another aspect, embodiments disclosed herein relate to a method of drilling or servicing a well. The method may include circulating a wellbore fluid, such as that described in the paragraph above, into a wellbore, and recovering at least a portion of the wellbore fluid from the wellbore.

Reservoir wellbore fluid

Wellbore fluid compositions containing a base fluid; at least one synthetic fiber; and a particulate solid are provided. In another aspect, methods of reducing loss of wellbore fluid into and strengthening of a formation are provided, including: introducing into the wellbore a fluid composition comprising one or more synthetic fibers and one or more particulate solids.

Enhanced wellbore strengthening solution

Non-emulsifying compositions may contain one or more sorbitan esters; one or more non-ionic surfactants; and one or more amphoteric surfactants, wherein the ratio of the one or more sorbitan esters to the one or more non-ionic surfactants to the one or more amphoteric surfactants is in the range of 1:1:1 to 1:5:3. Methods may include contacting an emulsion with a treatment fluid, the treatment fluid containing one or more sorbitan esters, one or more non-ionic surfactants, and one or more amphoteric surfactants, wherein the ratio of the one or more sorbitan esters to the one or more non-ionic surfactants to the one or more amphoteric surfactants is in the range of 1:1:1 to 1:5:3; and separating the emulsion into an aqueous phase and an oleaginous phase.

Growing community of inventors

Cypress, TX, United States of America

Steven Philip Young