THERMISCH STABILE BOHRLOCHFLÜSSIGKEIT HOHER DICHTE

Treatment of recovered wellbore fluids

Emulsifier-free wellbore fluid

Electromagnetic separation for shakers

Annular fluids and methods of emplacing the same

High pressure screen flow-through testing device

Wellbore fluid containing granular hemicellulose material

Shaker imaging and analysis

SHALE HYDRATION INHIBITION AGENT AND METHOD OF USE

A water-base drilling fluid for use in drilling wells through a formation containing a shale which swells in the presence of water. The drilling fluid preferably includes: an aqueous based continuous phase, a weight material, and a shale hydration inhibition agent having the formula:H2N - R - { OR' }X -Y .bullet. [H+ B-]din which R and R' are alkylene groups having 1 to 6 carbon atom and x is a value from about 1 to about 25. The Y group should be an amine or alkoxy group, preferably a primary amine or a methoxy group. The acid H+ B- is a protic acid selected from the group consisting of inorganic acids and organic acids, illustrative examples of which include: hydrochloric, hydrobromic, sulfuric, phosphoric, nitric, boric, perchloric, formic, acetic, halogenated acetic, propionic, butyric, maleic, fumeric, glycolic, lactic, citric and combinations of these. The shale hydration inhibition agent should be present in sufficient concentration to reduce the swelling of the shale. Also inclusive ...

NEW AND IMPROVED METHOD AND APPARATUS FOR CLEANING WELLBORE CASING

One or more brush bodies (20) fabricated from an incompressible material, for example, from high density polyurethane, high density polyethylene, high density polypropylene, nylon, Orlon, high density plastics, phenolic resin-based materials hard rubber, wood, aluminum, or other easily drillable metals, are connected to, or integrally fabricated with one or more elastomeric, conventional cement plugs (30), and are pumped down within the interior of oilfield casing (76) situated within an earth borehole, to minimize or eliminate the need to run a workstring of drillpipe and drill bit to clean out the interior of the string of casing (76).

INVERT EMULSION FLUIDS WITH HIGH INTERNAL PHASE CONCENTRATION

An invert emulsion wellbore fluid may include an oleaginous external phase; a non-oleaginous internal phase, wherein a ratio of the oleaginous external phase and non-oleaginous internal phase is less than 50:50; and an emulsif?er stabilizing the oleaginous external phase and the non-oleaginous internal phase, wherein an average diameter of the non-oleaginous internal phase ranges from 0.5 to 5 microns.

METHODS AND APPARATUSES FOR MIXING DRILLING FLUIDS

A method of mixing drilling fluids, the method including injecting a drilling fluid into a high shear mixing unit and processing the drilling fluid with the high shear mixing unit. The processing includes forcing the drilling fluid through a first row of teeth of a first stage.

BIODEGRADABLE SURFACTANT FOR INVERT EMULSION DRILLING FLUID

An invert emulsion drilling fluid includes an oleaginous continuous phase; a non-oleaginous discontinuous phase; a biodegradable surfactant including a di- fatty acid ester of triglycerol; and a weighting agent. It is preferred that the fatty acid have the formula RCO2H in which R is an alkyl or akenyl having 10 to 20 carbon atoms. The oleaginous fluid is selected from diesel oil, mineral oil, synthetic oil, ester oils, glycerides of fatty acids, aliphatic esters, aliphatic ethers, aliphatic acetals, or other such hydrocarbons and combinations of these and similar compounds. The non-oleaginous phase is selected from fresh water, sea water, brine, aqueous solutions containing water soluble organic salts, water soluble alcohols or water soluble glycols or combinations of these and similar compounds. The weighting agent is any suitable weighting agent and is preferably selected from water insoluble weighting agents such as barite, calcite, mullite, gallena, manganese oxides, iron oxides, or ...

IN SITU DECONTAMINATION OF DOWNHOLE EQUIPMENT

A method of decontaminating naturally occurring radioactive material (NORM) from downhole equipment may include injecting a NORM dissolver into an isolated region of a wellbore in which NORM-contaminated production equipment is located; and removing the NORM contaminants from the production equipment. The method may also include recommencing production of hydrocarbons following the decontamination.

APPARATUS, SYSTEM AND METHOD FOR FASTENING A SCREEN ON A GYRATORY SIFTER

An apparatus, system and method for fastening a screen has a screen with apertures sized to separate a first sized material from a second sized material. A box is positioned beneath the screen in a bracket extending along the screen. A protrusion extends from the box toward the screen. A triangular tensioning element secured along a length of the screen moves in a direction substantially perpendicular to the length of the screen in response to contact with the protrusion to seal the screen against the bracket and tension the screen.

SHALE HYDRATION INHIBITION AGENT AND METHOD OF USE

A water-base fluid for use in drilling wells and other drilling operation includes a shale which swells in the presence of water. The fluid preferably includes: an aqueous based continuous phase, and a shale hydration inhibition agent having the formula: H2N-R-{OR'}X-Y in which R and R' are alkylene groups having 1 to 6 carbon atoms and x is a value from about 1 to about 25. The Y group should be an amine or alkoxy group, preferably a primary amine or a methoxy group. The shale hydration inhibition agent should be present in sufficient concentration to reduce the swelling of the shale. The fluid may be used for formulating drilling fluids such as invert emulsion drilling muds or clear brine drilling fluids. The fluid may also be used in the slurrification and disposal of drill cuttings that contain water swellable clays or shales.

APPARATUS AND METHOD FOR HOMOGENIZING TWO OR MORE FLUIDS OF DIFFERENT DENSITIES

... ²An apparatus for blending two or more fluid streams, wherein a first fluid has ²a higher ²density than the other fluids, includes a first fluid director and at least a ²second fluid director ²providing fluid communication of a first and second fluid stream, ²respectively, to a primary ²mixing chamber. The first fluid director includes one or more baffles to ²disturb the first fluid ²stream and to direct it toward a rearward portion of the first inlet to the ²primary mixing ²chamber. A secondary blending chamber is in fluid communication with the ²primary ²chamber outlet and includes at least one, and preferably two static mixers. ²When two static ²mixers are serially retained in the secondary blending chamber, they may be ²skewed ²rotationally relative to each other such that the orifice profiles of each ²static mixer are not in ²alignment.² ...

WATER BASED WELLBORE FLUIDS

The invention relates to water based wellboe fluids used during a hydrocarbon recovery process, such as drilling, fracturing, gravel packing and wellbore workover. According to the present invention, said wellbore fluid comprises a fluid loss additive and a bridging material that are hydrophobic in nature, hydrophobically modified or oil wettable. The wellbore fluid generates an active filter cake that once formed, is impermeable to an aqueous phase, thus reducing fluid loss and enduring reduced damage to the formation, yet simultaneously is permeable to the back flow of hydrocarbons during a hydrocarbon recovery process.

INCREASED RATE OF PENETRATION FROM LOW RHEOLOGY WELLBORE FLUIDS

A method of increasing a rate of penetration when drilling as compared to drilling with a baseline drilling fluid comprising an API-grade barite weighting agent and having a given sag, settling rate, density, flow rate, and pressure drop through a wellbore, comprising: circulating a drilling fluid comprising a base fluid and a micronized weighting agent through the wellbore; wherein the drilling fluid is characterized as having an equivalent density, an equivalent or lower settling rate, and an equivalent or lower sag than the baseline drilling fluid; wherein the circulating is at a higher flow rate than the baseline drilling fluid flow rate; and wherein the circulating results in an equivalent or lower pressure drop through the wellbore.

PROCESS AND COMPOSITION FOR INCREASING THE REACTIVITY OF SULFUR SCAVENGING OXIDES

... ²²²In ridding fluids, including hydrocarbon fluids, both gaseous and liquid, of ²sulfur compounds including hydrogen sulfide, oxides of sulfur, and thiols, the ²present invention uses a small quantity of an activator, generally a noble ²metal oxide, preferably a copper species and/or a manganese species, along ²with a known oxide product, such as iron oxide, iron hydroxide, zinc oxide, ²zinc hydroxide, manganese oxide, manganese hydroxide, or combinations thereof, ²to thoroughly remove sulfur contaminants in a short amount of time. The ²activator allows for the use of smaller reactor vessels and the production of ²hydrocarbon fluids substantially free of sulfur products.² ...

DRILLING WASTE MANAGEMENT SYSTEM

A mobile drilling waste management system including a trailer having at least one centrifuge and a solids catch tank receiving solids separated from drilling fluid by one or more of the centrifuges. And a method of reclaiming drilling fluid including pumping drilling fluid contaminated with solids onto a trailer, separating the contaminant solids from the drilling fluid with at least one centrifuge located on the trailer, directing the contaminant solids to a solids catch tank located on the trailer, and pumping the drilling fluid off of the trailer.

AUTOCHOKE SYSTEM

Back pressure control devices used to control fluid pressure in a wellbore require various utilities for operation, such as an air supply. Apparatus disclosed herein provide for the continued operation of one or more back pressure control devices when supply of utilities for operation of the back pressure control devices are intentionally or unintentionally interrupted.

METHOD OF REMEDIATING BIT BALLING USING OXIDIZING AGENTS

A method of removing clay compounded on drilling equipment in a well that includes contacting the drilling equipment with a treatment fluid comprising an oxidizing agent. Methods disclosed also relate to drilling a wellbore though a clay-containing formation that includes drilling through the formation with a water-containing drilling fluid; reducing applied weight-on-bit when bit balling detected; emplacing a treatment fluid comprising an oxidizing agent to disrupt clay compounded on drilling equipment; and increasing weight-on-bit to continue drilling through the formation ...

SCREEN ASSEMBLY DESIGNED TO CONFORM TO THE RADIUS OF VIBRATING SHAKERS WITH CROWNED DECKS

A screen assembly that is sufficiently flexible to adapt to a non-planar profile of a crowned deck (5) on a vibrating shaker. When attached to the crowned deck (5), the screen assembly provides a screen with less curvature than the crowned deck (5).

SHAKER AND DEGASSER COMBINATION

A system for separating components of a slurry is disclosed, the system including a housing; a basket for holding at least one shaker screen, the basket movably mounted in the housing; at least one vibrator coupled to the basket; a sump disposed below the basket to collect at least a portion of the slurry passing through the at least one shaker screen; a pressure differential device fluidly connected to the sump for developing a pressure differential across the at least one shaker screen; and a toggling device for toggling the pressure differential across the screen. A system including a degassing chamber fluidly connected to a sump and a pressure differential device, wherein the degassing chamber is disposed between the sump and the pressure differential device, and a fluid conduit fluidly connected to the degassing chamber for recovering a degassed fluid is also disclosed.

AGGLOMERATION-RESISTANT DESULFURIZING PRODUCT

Disclosed herein is an agglomeration-resistant desulfurizing product for removing contaminants from a fluid stream. The agglomeration-resistant desulfurizing product comprising a metal oxide composition for reacting with contaminants and a polymeric crystallization inhibitor for reducing the agglomeration of the desulfurizing product resulting from using the desulfurizing product. A method to produce the agglomeration-resistant desulfurizing product and a method to treat a fluid stream is also disclosed.

OIL BASED SYNTHETIC HYDROCARBON DRILLING FLUID

The present invention relates to an improved continuous phase for an oil based drilling fluid and specifically a synthetic hydrocarbon continuous phase which is non-polluting and minimally toxic. The invention provides excellent drilling fluid properties under a wide variety of drilling conditions. The synthetic hydrocarbons are selected from the group consisting of branched chain oligomers synthesized from one or more olefins containing a C2 to C14 chain length and wherein the oligomers have an average molecular weight of from 120 to 1000. In the drilling fluid compositions, suitable emulsifiers, wetting agents, viscosifiers, weight materials and fluid loss additives are utilized in conjunction with water and/or a brine phase for the desired rheological properties.

VACUUM TANK FOR USE IN HANDLING OIL AND GAS WELL CUTTINGS

A vacuum tank apparatus for use with oil and gas well drilling operations facilitates the removal of well cuttings generated by drilling. The tank apparatus provides a frame having a plurality of corners reinforced by structural corner columns. The frame includes a base having a structural, generally horizontally extended base that includes a plurality o f base perimeter beams. The columns are connected structurally to the base at the perimeter beams. T he upper end portion of the frame includes a plurality of upper perimeter beams. The columns are structurally connected to the base and the perimeter beams. A shaped hopper is supported by the frame internally of the perimeter beams. The hopper includes an interior and a sidewall comprised of a plurality of inclined wall sections. Each wall section includes an upper end portion that connects to the frame at the perimeter beams, and a lower end portion that extends to another lower end portion of another inclined wall section. An outlet header ...

METHOD AND APPARATUS FOR HANDLING AND DISPOSAL OF OIL AND GAS WELL DRILL CUTTINGS

A method and apparatus for removing drill cuttings from an oil and gas well drilling platform provides for the separation of drill cuttings from at least a volume of the well drilling fluid (i.e. drilling mud) on the drilling platform so that the drilling fluids can be recycled into the well bore. The cuttings are then transferred to a cuttings collection receptacle (eg. trough) on the platform. The separated drill cuttings are then suctioned with a first suction line having an intake portion. The suctioned drill cuttings are transmitted to a processing tank (or multiple such tanks) on the platform, each having a tank interior. A vacuum is formed within the processing tank interior with a blower that is in fluid communication with the tank interior via a second vacuum line. The tank is connected to a floating work boat with a discharge flow line. Cuttings are processed within the tank, being chopped or cut into smaller size particles with a pump that is preferably contained within the processing ...

CUTTINGS TRANSFER SYSTEM

A cuttings transfer system including a separator configured to separate cuttings from a slurry and a transfer line configured to receive the cuttings from the separator. The system further including a valve in fluid communication with the transfer line and the separator, wherein the valve is configured to control a flow of the cuttings from the separator to the transfer line, and an air transfer device coupled to the transfer line that is configured to supply a flow of air through the transfer line.

Process for sulfur scavenging

In ridding fluids, including hydrocarbon fluids, both gaseous and liquid, of sulfur compounds including hydrogen sulfide, oxides of sulfur, and thiols, the present invention uses a small quantity of an activator, generally a noble metal oxide, preferably a copper species and/or a manganese species, along with a known oxide product, such as iron oxide, iron hydroxide, zinc oxide, zinc hydroxide, manganese oxide, manganese hydroxide, or combinations thereof, to thoroughly remove sulfur contaminants in a short amount of time. The activator allows for the use of smaller reactor vessels and the production of hydrocarbon fluids substantially free of sulfur products.

Single side screen clamping

An apparatus includes a vibratory separator, a screen support coupled to an inner surface of the vibratory separator, a screen having a first side with a sloped edge and a second side, the second side having a sloped edge, a screen retainer coupled to the vibratory separator, a wedge retainer coupled to a sidewall of the vibratory separator opposite the screen retainer, and a wedge having a first surface configured to engage the wedge retainer and a second surface configured to engage the a sloped edge of the second side of the screen. A method includes disposing a screen on a screen support in a vibratory separator, engaging a first side of the screen with a screen retainer coupled to the vibratory separator, and applying at least one of a downward vertical force and a lateral force to a second side of the screen with a clamping apparatus.

Application of degradable fibers in invert emulsion fluids for fluid loss control

A method of treating a subterranean formation including emplacing in a wellbore a fluid, comprising an oleaginous continuous phase, a non-oleaginous discontinuous phase, an emulsifier, at least one degradable material, and at least one bridging material, and contacting the formation with the fluid. A method and apparatus related to an invert emulsion fluid loss pill including an oleaginous continuous phase, a non-oleaginous discontinuous phase, an emulsifier, at least one degradable material, wherein the degradable material hydrolyzes to release an organic acid, and at least one bridging material.

HIGH PERFORMANCE WATER BASED DRILLING MUD AND METHOD OF USE

Uses of an aqueous dispersion of colloidal barite particles

INVERT EMULSION DRILLING FLUIDS AND METHOD FOR VISCOSIFYING INVERT EMULSION DRILLING FLUIDS

Apparatus, system and method for fastening a screen on a gyratory sifter with an integrated screen seal

Hydrate Inhibiting well fluids

Rheological measurement of filtercake

Offshore thermal treatment of drill cuttings fed from a bulk transfer system

SHALE HYDRATION INHIBITION AGENT AND METHOD OF USE

... ²²²A water-base fluid for use in drilling, cementing, workover, fracturing and ²abandonment of subterranean wells through a formation containing shale which ²swells in the presence of water. In one illustrative embodiment, the drilling ²fluid is composed of an aqueous based continuous phase, a weighting agent, and ²a shale hydration inhibition agent. The shale hydration inhibition agent ²should have the general formula (I): in which R and R' independently selected ²from hydrogen, methyl, ethyl or propyl, and X has a value from 1 to 6. The ²shale hydration inhibition agent is present in sufficient concentration to ²substantially reduce the swelling of shale drilling cuttings upon contact with ²the drilling fluid. The drilling fluid may be formulated to include a wide ²variety of components of aqueous based drilling fluids, such as weighting ²agents, fluid loss control agents, suspending agents, viscosifying agents, ²rheology control agents, as well as other compounds and materials known ...

VIBRATORY SCREEN

A screen includes three or four layers of woven metal screen cloth. The coarsest of these layers is a structural layer (26) includes threads (32) which are woven into the cloth with surfaces (32) which are fusible below a temperature at which the other layers of screen cloth are heat affected. These woven threads (28) include each of the threads in the coarse screen cloth with the coated threads being wire with fusible polypropylene or polyethylene coatings (30). The cloth could alternatively be coated or a fusible grid (42) used. A support layer (12) above the structural layer (26) may include a woven metal screen with woven elements (18) which are either coated with fusible material or are solidly of fusible material woven periodically therethrough in at least one direction. A fusible grid (42) could alternatively be employed. Screens are laminated with one or two fine mesh screens (10, 14) heated on the support woven screen cloth (12) with fusible surfaces (22) to locate the fusible ...

APPARATUS AND METHOD FOR SEPARATING HYDROCARBONS FROM MATERIAL

A system for separating hydrocarbons from a material which includes a process chamber (103), a process pan (102) operatively connected to the process chamber and removable therefrom, a blower operatively connected to the process chamber and to a heat source (112), the blower adapted to force heated air into the process chamber through the material disposed on the process pan (102), the forced heated air adapted to vaporize hydrocarbons and other contaminants disposed on the material, and at least one condenser (110) operatively connected to the process chamber (103) and adapted to condense the vaporised hydrocarbons and other contaminants is disclosed. Further, a method for separating hydrocarbons from a material which includes passing a stream of heated air over the material to volatilize the hydrocarbons, passing the stream of heated air containing the hydrocarbons through at least one condenser (110) to form liquid hydrocarbons, collecting the liquid hydrocarbons, and recirculating the ...

METHOD OF RECYCLING WATER CONTAMINATED OIL BASED DRILLING FLUID

A method for recycling an invert emulsion based drilling fluid, in which the invert emulsion based drilling fluid includes an oil component and an aqueous component. The method includes: mixing the invert emulsion drilling fluid with a emulsion clearing agent, wherein the emulsion clearing agent is a mixture of an anionic tensid and a non-ionic tensid; and separating the oil component of the invert emulsion drilling fluid from the aqueous component of the invert emulsion drilling fluid. The method preferably utilizes an emulsion breaking agent that is a combination of an anionic tensid and an alkyl polyglycoside tensid.

METHODS OF DRILLING

A method of drilling a subterranean well may include drilling the subterranean well while circulating a wellbore fluid in the subterranean well, wherein the wellbore fluid includes a base fluid; and a ground weight material comprising barite and quartz and having a d50 between about 4 and 8 microns and a d90 between about 15-25 microns.

DRY PRODUCTS FOR WELLBORE FLUIDS AND METHODS OF USE THEREOF

A method may include adding a dry carrier powder loaded with a liquid additive into a wellbore fluid, thereby releasing at least a portion of the liquid additive into the wellbore fluid; and pumping the wellbore fluid with the liquid additive therein into a wellbore.

CHEMICAL INHIBITORS WITH SUB-MICRON MATERIALS AS ADDITIVES FOR ENHANCED FLOW ASSURANCE

Methods may include admixing an additive composition with a hydrocarbon fluid, wherein the additive composition contains at least one inhibitor and at least one sub-micron particle. Additional methods may include providing an additive composition containing at least one inhibitor and at least one sub-micron particle; adding the additive composition to a fluid capable of precipitating at least one of at least of asphaltenes, wax, scale, and gas hydrates; and transporting the fluid containing the additive composition.

DEVICE AND METHODOLOGY FOR IMPROVED MIXING OF LIQUIDS AND SOLIDS

An eductor for mixing liquids and solid particles includes a nozzle, an initial mixing chamber, a first diffuser, an intermediate mixing chamber and a second diffuser. The nozzle includes a semicircular nozzle outlet that is offset from a centrally-located frst axis. Motive flow is accelerated through the nozzle through a first and second acceleration segment. Solid particles are added to the motive flow in the initial mixing chamber and directed to the first diffuser. Each diffuser includes an acceleration and a deceleration segment separated by an elliptically-shaped throat. The intermediate mixing chamber is located between the first and second diffusers. A method for mixing liquids and solids includes introducing a motive flow finto an initial mixing chamber, creating a vacuum in the initial mixing chamber to induce solids irto the motive fluid, providing a region of turbulence to enhance mixing of the motive flow and solid particles, and diffusing the motive flow to further increase ...

INVERTIBLE EMULSIONS STABILISED BY AMPHIPHILIC POLYMERS AND APPLICATION TO BORE FLUIDS

The present invention relates to polyelectrolytes which have been modified so as to be rendered hydrophobic by amidification of a hydrophilic backbone using n--alkylamines, the alkyl chains of which contain 6 to 22 carbon atoms. Amidification is preferably carried out using di-n-dodecylamine. The hydrophilic backbone is preferably a sodium polyacrylate or the corresponding polyacrylic acid or an acrylate-AMPS statistical copolymer. The polymers of the invention can be used to stabilize direct or reverse emulsions which are prone to being destabilized or reversed by modifying the degree of salinity of the aqueous phase or by modifying the pH. The invention is of particular application to petroleum or analogous drilling fluids, in particular drilling, fracturing, acidizing or completion fluids.

APPARATUS, SYSTEM AND METHOD FOR FOLDING A SCREEN FOR USE WITH A SCREEN TENSIONING SYSTEM

An apparatus, a system and a method for reinforcing a screen has a screen rod assembly extending from a first end to a second end. The screen rod assembly encloses an interior. A spring-loaded plunger is located in the interior and adjusts the length of the screen rod assembly. A ball joint is on the screen rod and defines sections of the screen rod assembly that bend around the ball joint to reduce the length of the screen rod. A sleeve extends from a screen with segments separated by a fold line extending along a width of the screen. The sleeve receives the screen rod assembly to reinforce the screen. In an embodiment, a screen pinch assembly is defined where the sleeve engages a retention clasp of a screen tensioning system that receives the screen. The screen pinch assembly holds the screen in place.

THE USE OF SIZED BARITE AS A WEIGHTING AGENT FOR DRILLING FLUIDS

An additive that increases the density of fluids used in a wellbore during the construction or repair of oil, gas, injection, water, or geothermal wells comprises a wellbore fluid containing a sized barite weighting agent that has an increased density with improved suspension stability without a significant viscosity increase. The wellbore fluid as described herein has rheological properties comparable to a conventional wellbore fluids but does not exhibit problems with sag and resulting variations in density. An illustrative embodiment of the claimed subject matter is further directed to a drilling fluid comprising a fluid phase and a solid phase weight material for increasing the density of the drilling fluid, wherein the solid phase weight material is a ground particulate material and has a cumulative volume particle distribution such that < 10% is less than 1 µm; < 25% is in the range of 1 µm to 3 µm; < 50% is in the range of 2 µm to 6 µm; < 75% is in the range of 6 µm to 10 µm; < 90% ...

METHODS AND AQUEOUS BASED WELLBORE FLUIDS FOR REDUCING WELLBORE FLUID LOSS AND FILTRATE LOSS

Embodiments disclosed herein relate to aqueous based wellbore fluids for preventing wellbore fluid loss downhole containing at least one copolymer formed from at least one natural polymer monomer and at least one latex monomer, and an aqueous base fluid.

WELLBORE STRENGTHENING MATERIAL RECOVERY

A wellbore strengthening material collection system including a vibratory separator having a top deck, a middle deck, and a bottom deck, and also including a collection trough coupled to at least one of the decks and configured to receive wellbore strengthening materials from the at least one of the decks. Additionally, a collection trough including a body having an inlet and an outlet, an angled surface disposed within the body and at least on extension surface extending form the body and con-figured to secure the collection trough to a vibratory separator.

CUTTINGS TRANSFER SYSTEM

A cuttings transfer system including a separator configured to separate cuttings from a slurry and a transfer line configured to receive the cuttings from the separator. The system further including a valve in fluid communication with the transfer line and the separator, wherein the valve is configured to control a flow of the cuttings from the separator to the transfer line, and an air transfer device coupled to the transfer line that is configured to supply a flow of air through the transfer line.

DUAL FEED CENTRIFUGE

A dual feed centrifuge system for separating solids from fluids in drilling mud, including: a bowl; a screw conveyor mounted within the bowl; a first feed pipe mounted within the screw conveyor for feeding a drilling mud through a first feed port in a wall of the screw conveyor to a first annular space between the bowl and the wall of the screw conveyor. The first feed port is located midway axially along the conical section. A second feed pipe mounted within the screw conveyor for feeding a drilling mud through a second feed port in the wall of the screw conveyor to a second annular space between the bowl and the wall of the screw conveyor. The second feed port is located midway axially along the bowl section. The multiple feed ports may allow the centrifuge to operate more efficiently with both weighted and unweighted drilling fluids.

APPARATUS AND PROCESS FOR WELLBORE CHARACTERIZATION

An apparatus and a process for wellbore characterization are disclosed, including: separating, in a separation vessel, drilling mud from gas produced during drilling of a wellbore; transporting the separated produced gas from the separation vessel to a downstream process; and measuring at least one of a temperature, a pressure, a mass flow rate, and a volumetric flow rate of the separated produced gas during transport using one or more sensors. Properties of the gas separated from the mud may be used to determine characteristics of a wellbore.

METHODS FOR MINIMIZING FLUID LOSS TO AND DETERMINING THE LOCATIONS OF LOST CIRCULATION ZONES

A method for determining a location of a lost circulation zone in a wellbore having a first wellbore fluid therein that includes allowing loss of the first wellbore fluid to the lost circulation zone to stabilize; adding a volume of a second wellbore fluid having a density less than the first wellbore fluid to the wellbore on top of the first wellbore fluid to a predetermined wellbore depth; determining an average density of the combined first wellbore fluid and second wellbore fluid; mixing the first wellbore fluid and the second wellbore fluid together; pumping a volume of a third wellbore fluid having a density greater the average density of the combined first and second wellbore fluid into the wellbore bottom until fluid loss occurs; and determining the location of the lost circulation zone is disclosed.

METHOD FOR VISCOSIFYING INVERT EMULSION DRILLING FLUIDS

An invert emulsion drilling fluid including an oleaginous fluid, wherein the oleaginous fluid is the continuous external phase of the drilling fluid, a non-oleaginous fluid, wherein the non-oleaginous fluid is the discontinuous internal aqueous phase of the drilling fluid containing water and at least one organic or inorganic salt dissolved in the water, and an aqueous-phase viscosifier, wherein the aqueous-phase viscosifier is selected from the group consisting of a biopolymer, a salt tolerant clay, and a synthetic polymer, and wherein the aqueous-phase viscosifier is dispersed in the non-oleaginous fluid in a sufficient concentration to increase a low shear viscosity of the invert emulsion drilling fluid.

DEFLUIDIZING LOST CIRCULATION PILLS

A slurry for treating a wellbore that includes a base fluid; at least one fibrous structure; and a plurality of calcium silicate particles is disclosed. Methods of reducing loss of wellbore fluid in a wellbore to a formation using an LCM pill having calcium silicate particles therein is also disclosed.

SYSTEM AND METHOD FOR CATALYST REGENERATION

The various embodiments relate to a system and method for regenerating a direct oxidation catalyst that coverts H2S to elemental S. One embodiment of the method comprises regenerating a direct oxidation catalyst by contacting the direct oxidation catalyst with steam.

IMPROVED OIL-BASED DRILLING FLUID

Invert emulsion compositions including an oleaginous, a non-oleaginous and a n amine surfactant that are useful in the oil and gas well drilling art are disclosed. The amine surfactant is selected so that the invert emulsion can be converted fr om a water-in--oil type emulsion to a oil-in-water type emulsion upon the protonation of the amine surfactant. Deprotonation of the amine surfactant reverses the conversion. ...

Centrifuge and changeable weir inserts therefor

A centrifuge, including: a flange closing off one axial end of a separation chamber; a plurality of apertures that traverse axially through the flange at a radial distance from a flange axis, wherein at least one aperture is in fluid communication with a first outlet passage; a plurality of weir inserts removably disposed within the plurality of apertures to control a flow of one or more fluids from the separation chamber; wherein at least one weir insert disposed within the at least one aperture in fluid communication with the first outlet passage is changeable to prevent or allow fluid communication between the separation chamber and the first outlet passage.

Apparatus for separation of water from oil-based drilling fluid and advanced water treatment

An apparatus for separating water from oil-based drilling fluid includes an separation tank, a chemical treatment apparatus having one or more de-oiling polymer preparation tanks, and a dissolved air flotation unit. Slop mud is directed into the separation tank where surfactant is added to separate the drilling fluid from oily water. The drilling fluid is drained for further processing. The oily water is removed by an outlet arrangement from the separation tank and directed to an initial treatment line. One or more de-oiling polymers are added to the oily water in the initial treatment line and mixed therewith. The mixture may then be directed to the dissolved air flotation unit where dissolved air is released into the bottom of the mixture. The dissolved air adheres to suspended solids in the mixture and lifts them to the top surface as a froth. The froth is skimmed from the top surface of the mixture and collected. The de-frothed water is reused or directed to a filtration system where ...

Low toxicity shale hydration inhibition agent and method of use

A low toxicity composition and method of reducing the swelling of clay in well comprising circulating in the well a water-based fluid comprising a functionally effective concentration of the additive formed from the following reaction of a tertiary amine of the following general formula: wherein R1 and R2 are alkyl or hydroxyalkyl groups with one to three carbon atoms or combinations thereof, and R3 is a hydroxyalkyl group with one to three carbon atoms, with an alkylating agent of the following general formula: R-A wherein R is an alkyl radical with one to three carbon atoms, and A is an organic or inorganic anion selected from the group consisting of sulfate, phosphate, carbonate, and combinations thereof.

Magnetic Leak Management Apparatus And Methods

Magnetic means for managing and stopping leaks in metal pipes such as we bores and pipe risers is provided. A magnetic leak arrestor comprises a spool with magnetic collar disposed thereabout. The spool has a tapered end for inserting into a pipe riser. The magnetic collar creates a seal with the pipe riser, which may the be welded in place, if desired. Additionally, a magnet may be positioned proximate a leak in a side wall of a pipe riser to seal the leak. The magnet may be shaped to conform to the shape of the pipe riser, and a seal gasket provided around an edge portion of the magnet. A slurry of magnetically active material may be provide inside the pipe to seal the leak in the side wall or to provide a blockage in the pipe riser so that killing fluids may be pumped into the well bore, if desired. 1. An apparatus for closing a leak from an open pipe , comprising:a spool tapered to extend inside the open pipe;a magnet configured to produce a magnetic field aligned with a central axis of the pipe; anda valve coupled to the spool.2. The apparatus of claim 1 , wherein the magnet is an electromagnet.3. The apparatus of claim 1 , wherein the magnet is an electromagnet disposed around the spool.4. A method comprising:tapering an end of a first pipe to mate with a second pipe;providing a magnetic field in alignment with a central axis of the first pipe and the second pipe; andconfiguring the magnetic field to provide an attractive force between the first pipe and the second pipe.5. The method of further comprising:providing a magnetically active slurry in the first pipe or the second pipe;positioning one or more magnets to direct the magnetic slurry toward an inside surface of the first pipe or the second pipe; andusing the magnetic field to harden the magnetic slurry against leaks in the inside surface of the first pipe or the second pipe.6. A method of plugging a well bore claim 4 , comprising:providing a slurry of a ferromagnetic material into the well bore; ...

Environmentally compatible hydrocarbon blend drilling fluid

A method of formulating and the resulting biodegradable wellbore fluid includes a first synthetic internal olefin fraction having from 16 to 18 carbon atoms (C_16-18 IO), a second synthetic internal olefin fraction having between 15 to 18 carbon atoms (C_15-18 IO), and a third synthetic internal olefin fraction having 15 to 16 carbon atoms (C_15-16 IO). The components of the wellbore fluid are blended such that the desired characteristics of polycyclic aromatic hydrocarbon content, toxicity and biodegrability are balance to achieve compliance with environmental requirements for hydrocarbon based drilling fluids. One such illustrative embodiment achieves this result by utilizing a formulation in which the first internal olefin fraction is present in a range of about 45 to about 55 percent by weight of the wellbore fluid and wherein the second internal olefin fraction is present in range of about 20 to about 30 percent by weight of the wellbore fluid and wherein ...

WATER ABSORBING POLYMERS FOR TREATMENT OF BRINES AND WATER-BASED DRILLING FLUIDS

VIBRATORY SCREEN

DUAL FEED CENTRIFUGE

IMPROVED INTERNAL BREAKER

Einstellbarer Drehsichter mit geteiltem Gewicht

Eine Vorrichtung beinhaltet einen Siebkorb und ein mit dem Siebkorb gekoppeltes Antriebssystem. Das Antriebssystem beinhaltet einen Motor und einen Antrieb mit einer Antriebswelle. Das Antriebssystem gibt dem Siebkorb eine Kreisbewegung. Erste und zweite exzentrische Massen sind mit der Antriebswelle gekoppelt. Ein Verfahren beinhaltet das Koppeln des Antriebssystems mit dem Siebkorb eines Sichters; die erste exzentrische Masse ist in einem Abstand über der zweiten exzentrischen Masse angeordnet. Die erste und zweite exzentrische Masse wird gemeinsam gedreht. Die Massen der ersten und zweiten exzentrischen Massen werden so bereitgestellt und/oder eingestellt, dass eine Summe der Kräfte, die durch Drehen der ersten und zweiten exzentrischen Massen erzeugt wird, eine Kraftlinie in der Ebene mit einem Schwerpunkt des Sichters erzeugt. Die Drehung der exzentrischen Gewichte kann ein distales Ende eines ersten und/oder zweiten Gewichtsarms um einen vertikalen Abstand nach oben bewegen.

ILTERKUCHENENTFERNUNG

Water-based drilling fluid

Dispersant coated weighting agents

Mixing methods and systems for fluids

Apparatus, system and method for flowing a fluid through a trough

SHAKER SCREEN CLAMPING AND SEALING ASSEMBLY

An assembly for sealing a shaker screen assembly in a shaker separator includes a substantially inflexible gasket affixed to each screen support and a flexible gasket affixed to each screen support such that the screen frame rests atop the gaskets on the support around its periphery. A wedge block retainer bracket is affixed to each side wall of the shaker separator above the corresponding section of the screen frame. A wedge block is selectively drivable into the space between the wedge block retainer bracket and the corresponding section of the screen frame, providing force thereto sufficient to seat the screen frame against the inflexible gasket and to compress the flexible gasket between the screen frame and the screen support, thereby providing a substantially fluid tight seal.

SEPARATION OF TAR FROM SAND

A system for separating hydrocarbons from a solid source including a primary separation tank including a first hydrocarbon removing device to remove hydrocarbons from a slurry of water and solids. Further, the system including a transfer device between the primary separation tank and a secondary separation tank, wherein the transfer device is configured to transfer solids from the slurry to the secondary separation tank. Further still, the system including a second hydrocarbon removal device, a fine particle separation device to remove remaining solids in the secondary separation tank, and a product collection tank to receive hydrocarbons removed from the primary and secondary separation tanks.

POLYMER COATED BRIDGING SOLIDS AND WEIGHTING AGENTS FOR USE IN DRILLING FLUIDS

... ²²²A wellbore fluid having at least two phases, including a fluid phase and a ²solid phase. The solid phase is a powdered solid material coated with a ²polymer that is the reaction product of a polyether amine and a dialdehyde ²crosslinking agent. Preferably the polyether amine is a diamine and more ²preferably the compound acts as a shale hydration inhibitor. The dialdehyde ²crosslinking agent reacts with the polyether amine compound and forms the ²polymeric material coating the solid. The polymer is substantially solubilized ²when the pH of the fluid has a value of less than about 7.² ...

METHODS OF MICROBIAL MEASURING AND CONTROL

The present disclosure relates to methods of controlling a microbial level in an aqueous fluid or a solid component used in an oilfield operation or a pre- or post- production process associated with wellbore production, the method comprising: measuring a microbial parameter of the aqueous fluid; and subsequently using the measured microbial parameter to decide on an appropriate antimicrobial treatment. These proposals also relate to methods further including monitoring of a microbial parameter in such a fluid or on such a solid component over a period of time. The methods and aspects of the present disclosure may be applied in any oilfield operation or a pre- or post- production process associated with wellbore production.

PARTICULATE BRIDGING AGENTS USED FOR FORMING AND BREAKING FILTERCAKES ON WELLBORES

A method of preventing fluid loss to a wellbore that includes pumping a wellbore fluid into the wellbore through a subterranean formation, the wellbore fluid comprising: a base fluid; and a plurality of particulate bridging agents comprising a solid breaking agent encapsulated by one of an inorganic solid material and an oil- soluble resin; and allowing some filtration of the wellbore fluid into the subterranean formation to produce a filter cake comprising the particulate bridging agents is disclosed.

TRIGGERED HEATING OF WELLBORE FLUIDS BY CARBON NANOMATERIALS

A method of triggering heating within a subterranean formation, that includes introducting a wellbore fluid containing a dispersed carbon nanomaterial into a wellbore through the subterranean formation; lowering a microwave or ultraviolet radiation source into the wellbore; and irradiating the wellbore with microwave or ultraviolet radiation, thereby increasing the temperature of the wellbore fluid and/or wellbore is disclosed.

MODULAR PRESSURE CONTROL AND DRILLING WASTE MANAGEMENT APPARATUS FOR SUBTERRANEAN BOREHOLE OPERATIONS

... ²²²A modularly segmented apparatus for precise borehole pressure control, ²removing waste from borehole fluid, and recirculating the cleaned borehole ²fluid includes a pressure control section, a gas separator section, and a ²waste management section. In the pressure control section, a pressure manifold ²interconnects a plurality of chokes. A plurality of valves are used to direct ²the contaminated fluid through one of the chokes, which maintains a precise ²and predetermined pressure in the system. The manifold, chokes, and valves are ²mounted on a skid for easy transport. In the gas separator section, a gas ²separator is used to remove a majority of the gases present in the ²contaminated borehole fluid. In the waste management section, a vibratory ²separator removes large solid contaminants from the degassed fluid. The solids ²are directed to a solids collection container for further treatment or ²disposal. The fluid is directed to a first pit, which may be one partitioned ²are of a larger ...

CLARIFYING TANK

Methods and apparatus for separating solid particles from a fluid. One preferred embodiment includes a tank for settling particles out of the fluid, a conical chamber at the bottom of the tank, an outlet connected to conical chamber, and a conical auger within the conical chamber. The tank may have a tangential inlet that creates a fluid circulation that exerts a centrifugal force on the solid particles to increase the settling of particles out of the fluid. The tank may have a static spiral on the inner wall that helps small particles coalesce into larger particles that settle faster out of the fluid. The fluid content of the solids removed from the tank may be controlled by varying the rotational speed of the conical auger. The rotational speed of the conical auger may be varied depending on the torque required to rotate the conical auger.

METHOD AND APPARATUS FOR ANGULARLY POSITIONING A SHAKER SEPARATOR BED

... ²²²An apparatus for angularly positioning a shaker bed, including a discharge ²end, includes an air source providing pressurized air, an hydraulic tank in ²selective communication with the air source and containing a quantity of ²fluid, at least one bellow in selective fluid communication with the hydraulic ²tank, and a lift control assembly controlling communication of pressurized air ²between the air source and the hydraulic tank and controlling communication of ²fluid between the hydraulic tank and the at least one bellow.² ...

SHAKER AND DEGASSER COMBINATION

A system for separating components of a slurry is disclosed, the system including a housing; a basket for holding at least one shaker screen, the basket movably mounted in the housing; at least one vibrator coupled to the basket; a sump disposed below the basket to collect at least a portion of the slurry passing through the at least one shaker screen; a pressure differential device fluidly connected to the sump for developing a pressure differential across the at least one shaker screen; and a toggling device for toggling the pressure differential across the screen. A system including a degassing chamber fluidly connected to a sump and a pressure differential device, wherein the degassing chamber is disposed between the sump and the pressure differential device, and a fluid conduit fluidly connected to the degassing chamber for recovering a degassed fluid is also disclosed.

COMPOSITE SCREEN WITH INTEGRAL INFLATABLE SEAL

A shaker screen including a screen frame and an inflatable sealing element integrally formed with the screen frame is disclosed. A screen sealing system including a plurality of shaker screens, each shaker screen having a screen frame and an inflatable sealing element integrally formed with the screen frame, wherein the inflatable sealing elements of each shaker screen are in fluid communication is also disclosed. A method of sealing a composite screen including assembling at least one shaker screen within a shale shaker and inflating at least one inflatable sealing element disposed along at least a portion of a perimeter of the screen frame, the portions selected from a group consisting of a top surface, a bottom surface, and an outer surface is disclosed.

VIBRATORY SEPARATOR SCREEN

A vibratory separator includes a screen frame having an upper screen surface and a plurality of openings and a first screen insert disposed in a first opening of the plurality of openings of the screen frame, the screen insert having a screen surface positioned at a first height above the supper screen surface. The vibratory separator also includes a second screen insert disposed in a second opening of the plurality of openings of the second screen frame, wherein a screen surface of the second screen insert is positioned at a second height. The second height may be different from the first height. A method of processing fluid includes providing a flow of fluid to a vibratory separator, and flowing the fluid over a screen having a first screen insert positioned at a first height.

MULTI-DECK SHAKER

The present disclosure relates to methods and apparatuses to separate solids from a drilling fluid. A shaker in accordance with the present disclosure includes a first screening deck having a first channel and a second channel, and also includes a second screening deck. Drilling fluid received by the first channel and separated through the first screening deck is directed to the second screening deck, and drilling fluid received by the second channel and separated through the first screening deck is directed to a sump of the shaker.

CONDUCTIVE MEDIUM FOR OPENHOLE LOGGING AND LOGGING WHILE DRILLING

A method of electrically logging subterranean wells using a conductive fluid is disclosed. The conductive fluid includes a miscible combination of an oleaginous fluid, a water soluble alcohol, and an electrolytic salt. The electrolytic salt or brine of the salt is present in a concentration sufficient to permit the electrical logging of the subterranean well. The medium may further include gelling agent, weight material, surfactant, or corrosion inhibitors. The oleaginous fluid may preferably be a preferentially-oil-soluble glycol alone or in combination with mineral oil, vegetable oil, synthetic oil, silicone oil or combinations and mixtures of these. The alcohol may preferably be a water soluble glycol or glycol ether such as ethylene glycol, diethylene glycol, propylene glycol and the like. The electrolytic salt or brine may be an inorganic or organic salt, examples of which include sodium chloride, sodium bromide, potassium chloride, ammonium chloride, magnesium chloride, calcium chloride ...

IMPROVED SIFTING SCREEN

The invention relates to a screen frame adapted for use in a shaker to separate solids from a liquid/solid mixture and to which woven wire mesh is to be attached, comprising an outer perimeter and a plurality of plastics ribs extending between opposing regions of the perimeter, the plastics ribs together forming an upper face and a lower face, wherein the frame further comprises at least one metal rib extending between opposing regions of the perimeter and extending from the upper face to the lower face, and to a shaker comprising at least one such screen frame.

IMPROVED WATER-BASED DRILLING FLUIDS FOR REDUCTION OF WATER ADSORPTION AND HYDRATION OF ARGILLACEOUS ROCKS

The present invention provides a water-based drilling fluid that reduces wat er adsorption and hydration of argillaceous rocks. The drilling fluid comprises a glycol with a molecular weight of less than about 200, an organic cationic material such as salts of cholin e or an organic salt of potassium, a filtration control agent, a viscosifier and water.

OIL BASED DRILLING FLUIDS SUITABLE FOR DRILLING IN THE PRESENCE OF ACIDIC GASES

An alkaline-reserve-free, oil-based drilling fluid is disclosed as comprisin g an oleaginous liquid, and an amine surfactant having the structure R-NH2, where in R represents a C12-C12 alkyl group or alkenyl group. Such fluid is particularl y useful in the drilling of subterranean wells in which CO2, H2S or other acidic gase s which adversely effect the rheologies and other properties of the drilling fluid a re encountered. The alkaline-reserve-free oil-based drilling fluid permits the logging of acidic gases which otherwise could not be logged in the presence of lime or other alkaline.

Breaker and displacement fluid and method of use

A method of cleaning a wellbore prior to the production of oil or gas is disclosed, wherein the wellbore has been drilled with an invert emulsion drilling mud that forms an invert emulsion filter cake. The method may include the steps of circulating a breaker fluid into the wellbore, where the breaker fluid includes an aqueous fluid, and imino diacetic acid or salt thereof. Optionally an acid buffering agent, and a weighting age are also included. The breaker fluid is formulated such that after a predetermined period of time and the filter cake present in the wellbore or on the wellbore face is substantially degraded. Other methods may also include drilling the wellbore with a water-based drilling mud that forms a water-based filter cake, wherein the method may include the steps of circulating a breaker fluid into the wellbore, where the breaker fluid may include an aqueous fluid, and an iminodiacetic acid or a salt thereof.

Apparatus and method for testing reservoir drilling fluids for drilling unconsolidated tar sands

An apparatus and method for testing fluids to be used when drilling in unconsolidated sand formations includes a container having a first port and a second port and a plurality of perforations through which fluid can be communicated, a bore holder slidingly retained through a portion of the container between the first port and the second port, wherein the bore holder has a feed end and a discharge end, a bed of unconsolidated sand contained in the container in a compacted state surrounding the bore holder, a fluid distribution nozzle at the discharge end of the bore holder, a fluid source in fluid communication with the discharge end of the bore holder, wherein the fluid source provides a test fluid to the fluid distribution nozzle through the bore holder, wherein the bore holder is withdrawn from the container at a predetermined speed as the test fluid is communicated through the fluid distribution nozzle, thereby leaving a simulated well bore in the unconsolidated sand.

High density slurry

A module for slurrifying drill cuttings that includes a skid, a programmable logic controller disposed on the skid, and a blender. The blender including a feeder for injecting drill cuttings, a gate disposed in fluid communication with the feeder for controlling a flow of the drill cuttings, and an impeller for energizing a fluid, wherein the module is configured to be removably connected to a cuttings storage vessel located at a work site. Also, a method of drill cuttings re-injection that includes creating a slurry including greater than 20 percent by volume drill cuttings in a blender system, and pumping the slurry from the blending system to a cuttings injection system. The method further includes injecting the slurry from the cuttings injection system into a wellbore.

COMPOSITION OF POLYBUTADIENE-BASED FORMULA FOR DOWNHOLE APPLICATIONS

A method of treating a wellbore may include emplacing in at least a selected region of the wellbore a formulation that includes at least one diene pre-polymer; at least one reactive diluent; at least one inert diluent comprising an oleaginous liquid or a mutual solvent; and at least one initiator; and initiating polymerization of the at least one diene pre-polymer and the at least one reactive diluent to form a composite material in the selected region of the wellbore. 1. A method of treating a wellbore , comprising: at least one diene pre-polymer;', 'at least one reactive diluent;', 'at least one inert diluent comprising an oleaginous liquid or a mutual solvent; and', 'at least one initiator; and, 'emplacing in at least a selected region of the wellbore, a formulation comprisinginitiating polymerization of the at least one diene pre-polymer and the at least one reactive diluent to form a composite material in the selected region of the wellbore.2. (canceled)3. The method of claim 1 , wherein the at least one diene pre-polymer comprises a polybutadiene dimethacrylate.4. The method of claim 1 , wherein the at least one diene pre-polymer comprises a number average molecular weight ranging from about 1000 to 5000 Da.5. The method of claim 4 , wherein the at least one diene pre-polymer comprises a number average molecular weight ranging from about 2000 to 3000 Da.6. The method of claim 1 , wherein the at least one diene pre-polymer has a vinyl content ranging from about 50 to 85%.7. The method of claim 1 , wherein the at least one diene pre-polymer is present in the formulation in an amount ranging from about 10 to 30 percent by weight.8. The method of claim 1 , wherein the reactive diluent comprises at least a cycloalkyl ester of (meth)acrylate.9. The method of claim 1 , wherein the reactive diluent comprises at least one of 4-acryloylmorpholine claim 1 , 2-phenoxyethyl(meth)acrylate claim 1 , isodecyl(meth)acrylate claim 1 , lauryl(meth)acrylate claim 1 , isobornyl( ...

Cuttings treatment and reuse

A method for treating drill cuttings including depositing drill cuttings in a desalinization cell, the desalinization cell having a high end, a low end, and a cuttings pad. The method further includes washing the drill cuttings in the desalinization cell with a liquid phase and removing a cuttings runoff from the drill cuttings. Also, a method for treating drill cuttings including depositing drill cuttings in a desalinator, the desalinator having a geometric structure having a perforated side. The method further includes adding a liquid phase to the desalinator through the perforated side, washing the drill cuttings in the desalinator with the liquid phase, and producing desalinated drill cuttings and a cuttings runoff.

Asphaltene inhibition and/or dispersion in petroleum fluids

Compositions may include an asphaltene dispersant that is the product of a reaction between a polysaccharide having at least two sugar subunits and one or more fatty acid reagents, and a petroleum fluid produced from a subterranean formation and containing asphaltenes therein. The asphaltene dispersant may have a molecular weight of at least 4000 Da. Compositions may further include an aromatic solvent. Methods may include contacting a hydrocarbon fluid with an asphaltene dispersant dissolved in an aromatic solvent, wherein the asphaltene dispersant is the product of the reaction of a polysaccharide and one or more fatty acid reagents. Methods may also include contacting a hydrocarbon fluid with an asphaltene, wherein the asphaltene dispersant is the product of the reaction of a polysaccharide and one or more fatty acid reagents and has a molecular weight of at least 4000 Da.

PROCESS FOR THE REDUCTION OR ELIMINATION OF HYDROGEN SULPHIDE

AUTOCHOKE SYSTEM

Back pressure control devices used to control fluid pressure in a wellbore require various utilities for operation, such as an air supply. Apparatus disclosed herein provide for the continued operation of one or more back pressure control devices when supply of utilities for operation of the back pressure control devices are intentionally or unintentionally interrupted. 1. An apparatus for controlling a back pressure control system , wherein the back pressure control system includes a housing having an inlet , an outlet , and a pressure chamber; a shuttle assembly adapted to reciprocate in the pressure chamber to regulate the flow of an operating fluid from the inlet to the outlet; the operating fluid applying an opening force to a first end of the shuttle assembly; and a control fluid to apply a closing force to an opposite end of the shuttle assembly , the apparatus comprising:an air source for supplying air to the system;an air storage vessel in fluid communication with the air source;a control fluid storage vessel;a pneumatic pump in fluid communication with the control fluid storage vessel, wherein the pneumatic pump is operated via air supplied from the air source; one or more valves for regulating a flow of control fluid i) from at least one of the pneumatic pump, and a control fluid accumulator to the back pressure control system, and ii) from the back pressure control system to the hydraulic fluid reservoir;', 'the control fluid accumulator in fluid communication with the pneumatic pump, and the one or more valves for regulating a flow of the control fluid;', 'devices for operating the one or more valves via fluid communication with the air storage vessel;, 'a control fluid pressure control system for controlling a pressure of the control fluid, wherein the control fluid pressure control system comprises air stored in the air storage vessel fed to the actuators; and', 'control fluid accumulated in the control fluid accumulator., 'wherein, when the air ...

IN-LINE TREATMENT OF HYDROCARBON FLUIDS WITH OZONE

A system for treating recovered fluids in-line that includes a thermal reactor for separating contaminated drill cuttings into drill cuttings and contaminants by applying heat to the contaminated drill cuttings so as to vaporize contaminants from the contaminated drill cuttings; a first condenser in fluid connection with the thermal reactor for condensing the vaporized contaminants; a separator in fluid connection with the first condenser for separating the condensed vapors into an oleaginous liquid and an aqueous liquid, wherein at least a portion of one of the aqueous liquid and oleaginous liquid is fed back into the first condenser via a feedback line; and an ozone generator operatively coupled to the feedback line, wherein at least the portion of the fed back liquid is ozonated by the ozone generator and fed into the condenser is disclosed. 111.-. (canceled)12. A method of treating recovered fluids in-line , comprising:separating contaminated drill cuttings into drill cuttings and contaminants by applying heat to the contaminated drill cuttings so as to vaporize contaminants from the contaminated drill cuttings;condensing at least a portion of the vaporized contaminants in a first condenser;separating the condensed vapors into a first oleaginous liquid and a first aqueous liquid, wherein at least a portion of one of the first oleaginous liquid and first aqueous liquid is fed back into the first condenser via a first feedback line; andinjecting ozone into at least the portion of the fed back liquid until an optimal weight ozone per gram liquid of the at least the portion of the fed back liquid is reached.13. The method of claim 12 , further comprising:condensing at least a second portion of the vaporized contaminants in a second condenser;separating the second condensed vapors into a second oleaginous liquid and a second aqueous liquid, wherein at least a portion of one of the second oleaginous liquid and second aqueous liquid is fed back into the second ...

SANITARY GAPLESS SEPARATOR DISCHARGE

A particle size separator includes an upper separator frame, a lower separator frame, a screen disposed between the upper separator frame and the lower separator frame, a large size particle outlet having an inlet disposed below the screen, a small size particle outlet disposed in the lower separator frame and a combined baffle and seal unit disposed in an opening in the screen. The unit has a seal face configured to sealingly engage the inlet of the large size particle outlet. The unit has a baffle configured to constrain movement of particles on an upper surface of the screen into the inlet. The baffle is configured to sealingly engage an interior wall of the upper separator frame. 1. A particle size separator , comprising:an upper separator frame;a lower separator frame;a screen disposed between the upper separator frame and the lower separator frame;a large size particle outlet having an inlet disposed below the screen;a small size particle outlet disposed in the lower separator frame; anda combined baffle and seal unit disposed in an opening in the screen, the unit having a seal face configured to sealingly engage the inlet of the large size particle outlet; the unit having a baffle configured to constrain movement of particles on an upper surface of the screen into the inlet, the baffle configured to sealingly engage an interior wall of the upper separator frame.2. The separator of further comprising means for imparting motion to the separator frames.3. The separator of further comprising an opening plate disposed in the opening in the screen claim 1 , the opening plate having an interior surface configured to cooperatively engage the opening in the screen claim 1 , and wherein the combined baffle and seal unit comprises a feature for sealingly engaging an interior surface of the opening plate.4. The separator of wherein the combined baffle and seal unit sealingly engages an entire circumference of the opening plate.5. The separator of wherein the combined ...

METHODS OF USING INVERT EMULSION FLUIDS WITH HIGH INTERNAL PHASE CONCENTRATION

In a method of gravel packing a wellbore in a subterranean formation, the wellbore comprising a cased section and an uncased section, the method may include pumping into the wellbore a gravel pack composition comprising gravel and a carrier fluid comprising an invert emulsion fluid, where the invert emulsion fluid may comprise: an oleaginous external phase; a non-oleaginous internal phase, wherein a ratio of the oleaginous external phase and non-oleaginous internal phase is less than 50:50 and an emulsifier stabilizing the oleaginous external phase and the non-oleaginous internal phase. 1. A method of gravel packing a wellbore in a subterranean formation , the wellbore comprising a cased section and an uncased section , the method comprising: an oleaginous external phase;', 'a non-oleaginous internal phase, wherein a ratio of the oleaginous external phase and non-oleaginous internal phase is less than 50:50 and', 'an emulsifier stabilizing the oleaginous external phase and the non-oleaginous internal phase., 'pumping into the wellbore a gravel pack composition comprising gravel and a carrier fluid comprising an invert emulsion fluid, the invert emulsion fluid comprising2. The method of claim 1 , further comprising:packing the uncased section of the wellbore with gravel using alpha and beta waves of the carrier fluid.3. The method of claim 1 , further comprising:packing the uncased section of the wellbore with gravel using alternate path technology.4. The method of claim 1 , wherein an average diameter of the non-oleaginous internal phase ranges from 0.5 to 5 microns.5. The method of claim 1 , wherein the average diameter ranges from 1 to 3 microns.6. The method of claim 1 , wherein the ratio of the oleaginous external phase to non-oleaginous internal phase is less than 40:60.7. The method of claim 1 , wherein the ratio of the oleaginous external phase to the non-oleaginous internal phase is less than 30:70.8. The method of claim 1 , wherein the invert emulsion fluid ...

CUTTINGS TREATMENT AND REUSE

A method for treating drill cuttings including depositing drill cuttings in a desalinization cell, the desalinization cell having a high end, a low end, and a cuttings pad. The method further includes washing the drill cuttings in the desalinization cell with a liquid phase and removing a cuttings runoff from the drill cuttings. Also, a method for treating drill cuttings including depositing drill cuttings in a desalinator, the desalinator having a geometric structure having a perforated side. The method further includes adding a liquid phase to the desalinator through the perforated side, washing the drill cuttings in the desalinator with the liquid phase, and producing desalinated drill cuttings and a cuttings runoff. 1. A method for treating drill cuttings comprising: 'a geometric structure having a perforated side;', 'depositing drill cuttings in a desalinator, the desalinator comprisingadding a liquid phase to the desalinator through the perforated side;washing the drill cuttings in the desalinator with the liquid phase; andproducing desalinated drill cuttings and a cuttings runoff.2. The method of claim 1 , further comprising:collecting the cuttings runoff.3. The method of claim 2 , further comprising:recycling the cuttings runoff into a drill mud reservoir.4. The method of claim 2 , further comprising:evaporating the cuttings runoff to produce a salt.5. The method of claim 1 , further comprising:evaporating the desalinated drill cuttings to remove additional liquid phase and cuttings runoff.6. The method of claim 1 , wherein the liquid phase comprises water.7. The method of claim 1 , further comprising:using the desalinated drill cuttings in a construction operation.8. The method of claim 1 , wherein the washing comprises submerging the desalinator in the liquid phase.9. The method of claim 1 , wherein the washing comprises spraying the drill cuttings in the desalinator with the liquid phase. This application claims benefit, pursuant to 35 U.S.C. 120, to U.S. ...

WATER BASED COMPLETION AND DISPLACEMENT FLUID AND METHOD OF USE

A method of cleaning a wellbore prior to the production of oil or gas is disclosed, wherein the wellbore has been drilled with an invert emulsion drilling mud that forms an invert emulsion filter cake. The method may include the steps of circulating a breaker fluid into the wellbore, where the breaker fluid includes an aqueous fluid, a water soluble polar organic solvent, a hydrolysable ester of a carboxylic acid, and a weighting age, and where the hydrolysable ester is selected so that upon hydrolysis an organic acid is released and the invert emulsion of the filter cake breaks. 1. A method of cleaning a wellbore , wherein the wellbore has been drilled with an invert emulsion drilling mud that forms an invert emulsion filter cake , the method comprising: an aqueous fluid;', 'a water soluble polar organic solvent;', 'a hydrolysable ester of formic acid; and', 'a weighting agent; and, 'circulating a breaker fluid into the wellbore, the breaker fluid comprisingwherein the hydrolysable ester is selected so that upon hydrolysis formic acid is released and the invert emulsion of the filter cake breaks.2. The method of claim 1 , wherein the water soluble polar organic solvent is a glycol or glycol ether.3. The method of claim 2 , wherein the water soluble polar organic solvent is ethylene glycol mono-butyl ether.4. The method of claim 1 , wherein the hydrolysable ester of formic acid is a formic acid ester of a C4 to C30 alcohol.5. The method of claim 1 , wherein the weighting agent comprises at least one of halide and formate salts of alkali and alkaline earth metals.6. The method of claim 1 , further comprising:displacing the aqueous fluid from the wellbore.7. The method of claim 1 , further comprising:removing the broken invert emulsion filter cake from the wellbore.8. A method of producing a hydrocarbon from a formation claim 1 , the method comprising:drilling the formation with an invert emulsion drilling mud;performing at least one completion operation in the ...

CONVEYOR FOR DRILL CUTTINGS

A conveyor for drill cuttings includes a plurality of serially-aligned augers, wherein each auger has two opposed ends, a flex coupling secured between a first end of one auger and a second end of an adjacent subsequent auger, a trough at least partially surrounding each auger, a motor coupled to one end of the series of augers and providing rotation to the end of the series of augers, and at least one hangar bearing retaining each auger within the trough, wherein a first angle is present between two of the augers, said flex coupling transferring the rotation from the motor across the angle between the two augers. 1. A conveyor for drill cuttings comprising:a plurality of serially-aligned augers, wherein each auger has two opposed ends;a flex coupling secured between a first end of one auger and a second end of an adjacent subsequent auger;a trough at least partially surrounding each auger;a motor coupled to one end of the series of augers and providing rotation to the end of the series of augers;at least one hangar bearing retaining each auger within the trough; andwherein a first angle is present between two of the augers, said flex coupling transferring the rotation from the motor across the angle between the two augers.2. The conveyor of claim 1 , further comprising a flexible boot covering the flex coupling.3. The conveyor of claim 2 , wherein the flexible boot is made from a material selected from the group consisting of nitrile claim 2 , Viton claim 2 , polyurethane claim 2 , silicone claim 2 , fluorsilicone rubber claim 2 , and nylon.4. The conveyor of claim 1 , wherein the first angle between the two augers is between 0.5° and 35°.5. The conveyor of claim 1 , wherein the first angle between the two augers is between 1° and 25°.6. The conveyor of claim 1 , wherein the first angle between the two augers is vertical.7. The conveyor of claim 1 , wherein the first angle between the two augers is horizontal.8. The conveyor of claim 1 , wherein the first angle ...

USE OF CUTTINGS TANKS FOR RECYCLING OIL BASED MUD AND WATER

A system for recycling a drilling fluid that includes a first cuttings storage vessel, a second cuttings storage vessel, and a module fluidly connected to the first and second cuttings storage vessels, the module having a valve configured to fluidly connect the first and second cuttings storage vessels. The module further includes a filter system configured to fluidly connect to at least the second cuttings storage vessel, and at least one pump to facilitate the flow of a fluid between the first and second cuttings storage vessels. 1. A system for recycling a drilling fluid comprising:a first cuttings storage vessel;a second cuttings storage vessel; and a valve configured to fluidly connect the first and second cuttings storage vessels;', 'a filter system configured to fluidly connect to at least the second cuttings storage vessel; and', 'at least one pump to facilitate the flow of a fluid between the first and second cuttings storage vessels., 'a module fluidly connected to the first and second cuttings storage vessels, the module comprising2. The system of claim 1 , wherein the valve is configured to automatically adjust the flow of the fluid between the first and second cuttings storage vessels.3. The system of claim 1 , wherein the valve comprises a sensor.4. The system of claim 3 , wherein the sensor is one selected from a group consisting of a density sensor and a conductivity sensor.5. The system of claim 1 , wherein the filter system comprises a hydrocarbon filter.6. The system of claim 1 , wherein the filter system comprises a filter press.7. The system of claim 1 , further comprising a second pump to facilitate the flow of the fluid between the second cuttings storage vessel and a third storage vessel.8. The system of claim 7 , wherein the second pump is configured to facilitate the flow of the fluid through the filter system.9. The system of claim 1 , further comprising a programmable logic controller operatively coupled to the module.10. The system of ...

CHOKE TRIM ASSEMBLY

A choke trim assembly for use as a shuttle seat in a choke valve including a flange sleeve is disclosed, the choke trim assembly comprising a trim, a trim carrier, and a clamp ring, wherein the trim carrier and the clamp ring each have a tubular member, an outer diameter of the tubular member of the clamp ring being configured to enable a slip fit of the choke trim assembly into an inner diameter of the flange sleeve, the trim being centered in the clamp ring, and an outer diameter of the tubular member of the trim carrier and the inner diameter of the clamp ring being configured to enable a slip fit of the trim carrier into the clamp ring. 1. A choke trim assembly for use as a shuttle seat in a choke valve comprising a shuttle assembly and a flange sleeve to receive the shuttle assembly , the choke trim assembly comprising:a trim;a trim carrier; anda clamp ring;wherein the trim and the trim carrier are adapted to be assembled within the clamp ring such that the trim is centered in the clamp ring, and the clamp ring is adapted to enable a slip fit of the trim carrier into the clamp ring.2. The choke trim assembly according to claim 1 , wherein an outer diameter of the clamp ring is configured to enable a slip fit of at least a portion of the choke trim assembly into an inner diameter of the flange sleeve.3. The choke trim assembly according to claim 1 , wherein the trim is centered in the clamp ring claim 1 , and an outer diameter of the trim carrier and an inner diameter of the clamp ring are configured to enable a slip fit of the trim carrier into the clamp ring.4. The choke trim assembly according to claim 1 , wherein the trim is donut shaped.5. The choke trim assembly according to claim 1 , preceding claims claim 1 , wherein the trim is wedge-locked in the clamp ring.6. The choke trim assembly according to claim 1 , wherein the outer diameter of the trim is tapered.7. The choke trim assembly according to claim 6 , wherein the outer diameter of the trim is ...

Invert Emulsion Fluids With High Internal Phase Concentration

An invert emulsion wellbore fluid may include an oleaginous external phase; a non-oleaginous internal phase, wherein a ratio of the oleaginous external phase and non-oleaginous internal phase is less than 50:50; and an emulsifier stabilizing the oleaginous external phase and the non-oleaginous internal phase, wherein an average diameter of the non-oleaginous internal phase ranges from 0.5 to 5 microns. 1. An invert emulsion wellbore fluid comprising:an oleaginous external phase;a non-oleaginous internal phase, wherein a ratio of the oleaginous external phase and non-oleaginous internal phase is less than 50:50; andan emulsifier stabilizing the oleaginous external phase and the non-oleaginous internal phase, wherein an average diameter of the non-oleaginous internal phase ranges from 0.5 to 5 microns.2. The invert emulsion fluid of claim 1 , wherein the average diameter ranges from 1 to 3 microns.3. The invert emulsion fluid of claim 1 , wherein the emulsifier is an alkoxylated ether acid.4. The invert emulsion fluid of claim 1 , wherein the ratio of the oleaginous external phase to non-oleaginous internal phase is less than 40:60.5. The invert emulsion fluid of claim 1 , wherein the ratio of the oleaginous external phase to the non-oleaginous internal phase is less than 30:70.6. An invert emulsion wellbore fluid comprising:an oleaginous external phase;a non-oleaginous internal phase, wherein a ratio of the oleaginous external phase and non-oleaginous internal phase is less than 50:50; andan emulsifier stabilizing the oleaginous external phase and the non-oleaginous internal phase, wherein the invert emulsion wellbore fluid has a viscometer reading of less than 200, measured at 600 rpm, and a viscometer reading of less than 40 at 6 and 3 rpm.7. The invert emulsion fluid of claim 6 , wherein the fluid has an electrical stability of at least 50 v.8. The invert emulsion fluid of claim 6 , wherein the emulsifier is an alkoxylated ether acid.9. The invert emulsion fluid ...

PRECIPITATED WEIGHTING AGENTS FOR USE IN WELLBORE FLUIDS

A method of formulating a wellbore fluid that includes precipitating a weighting agent from a solution; and adding the precipitated weighting agent to a base fluid to form a wellbore fluid is disclosed. Fluids and methods of formulating wellbore fluids that contain dispersant coated precipitated weighting agents are also disclosed. 125.-. (canceled)26. A method of formulating a wellbore fluid , comprising:{'sub': '50', 'precipitating a weighting agent from a solution in the presence of a dispersant to form a precipitated weighting agent having a dof less than 700 microns;'}adding the precipitated weighting agent to a base fluid to form a wellbore fluid; andcirculating the wellbore fluid into a wellbore.27. The method of claim 26 , wherein the precipitating comprises mixing a metal or an alkaline metal salt solution with at least one of a sulfate salt solution claim 26 , carbon dioxide claim 26 , or precipitating phosphate or silicate solutions.28. The method of claim 26 , wherein the precipitated weighting agent comprises at least one of barium sulfate claim 26 , calcium carbonate claim 26 , magnesium carbonate claim 26 , calcium magnesium carbonate claim 26 , iron oxide claim 26 , magnesium silicate claim 26 , iron silicate claim 26 , iron carbonate claim 26 , and strontium sulfate.29. The method of claim 26 , wherein the precipitated weighting agent has an average particle size of less than 500 nm.30. The method of claim 29 , wherein the precipitated weighting agent has an average particle size of less than 100 nm.31. The method of claim 26 , further comprising: drilling a well with the wellbore fluid.32. The method of claim 26 , wherein the base fluid is one selected from a water-based fluid claim 26 , an oil-based fluid claim 26 , and an invert emulsion.33. The method of claim 26 , wherein the dispersant comprises at least one selected from oleic acid claim 26 , polybasic fatty acids claim 26 , alkylbenzene sulfonic acids claim 26 , alkane sulfonic acids claim ...

DEGRADABLE GELS IN ZONAL ISOLATION APPLICATIONS

A method of treating a formation that includes emplacing an oxidizing breaker fluid into a region of the formation occupied by a gel; and allowing sufficient time for the oxidizing breaker fluid to degrade the gel is disclosed. 1. A method of treating a formation , comprising:emplacing an oxidizing breaker fluid into a region of the formation occupied by a gel; andallowing sufficient time for the oxidizing breaker fluid to degrade the gel,wherein the gel comprises at least one of a lignin, a lignosulfonate, a tannin, a tannic acid, a modified lignin, a modified lignosulfonate, a modified tannin, a modified tannic acid, and combinations thereof or biopolymers, starches, carboxy methyl cellulose, polyacrylates, polyacrylamides, polyamines, polyetheramines, poly vinyl amines, polyethylene imines, and combinations thereof crosslinked with a crosslinking agent.2. The method of claim 1 , wherein the oxidizing breaker fluid comprises at least one of a hypochlorite and a peroxide.3. The method of claim 2 , wherein the oxidizing breaker fluid comprises at least one of lithium and sodium hypochlorite.4. (canceled)5. (canceled)6. The method of claim 5 , wherein the crosslinking agent comprises at least one of ethylene glycol diglycidyl ether claim 5 , propylene glycol diglycidyl ether claim 5 , butylene glycol diglycidyl ether claim 5 , trimethylolpropane triglycidyl ether claim 5 , sorbitol polyglycidyl ether claim 5 , diglycidyl ether of neopentyl glycol claim 5 , epoxidized 1 claim 5 ,6-hexanediol claim 5 , aziridine derivatives claim 5 , carbodiimides claim 5 , blocked isocyanates claim 5 , epoxy functionalized polyalkalene glycols claim 5 , an oxidized starch claim 5 , a polymeric dialdehyde claim 5 , an aldehyde adduct claim 5 , a tetra methoxy propane claim 5 , a hydrolyzed acetal claim 5 , and combinations thereof.7. (canceled)8. The method of claim 1 , further comprising:emplacing gel components to form the gel.9. The method of claim 1 , further comprising:emplacing ...

METHODS FOR TREATING A WELLBORE

A method of converting a completed well into a dual completed well that includes selectively pumping a water-based fluid into a first production zone of the completed well, wherein the water-based fluid has a pH of greater than about 5; allowing the water-based fluid to form a continuous, non-flowing water-based gel in the first production zone of the completed well, wherein the water-based gel has a pH of greater than about 5; disposing a layer of cement into the completed well above the water- based gel; perforating a second production zone of the completed well in a location above the layer of cement; drilling through the layer of cement; and breaking the water-based gel located in the first production zone of the completed well, wherein the breaking comprises: exposing the water-based gel to a breaker fluid, wherein the breaker fluid has a pH of greater than about 5 is disclosed. 1. A method of converting a completed well into a dual completed well , comprising:selectively pumping a water-based fluid into a first production zone of the completed well, wherein the water-based fluid has a pH of greater than about 5;allowing the water-based fluid to form a continuous, non-flowing water-based gel in the first production zone of the completed well, wherein the water-based gel has a pH of greater than about 5;disposing a layer of cement into the completed well above the water-based gel;perforating a second production zone of the completed well in a location above the layer of cement;drilling through the layer of cement; and 'exposing the water-based gel to a breaker fluid, wherein the breaker fluid has a pH of greater than about 5.', 'breaking the water-based gel located in the first production zone of the completed well, wherein the breaking comprises2. The method of claim 1 , further comprising:installing production tubing after breaking the water-based gel.3. The method of claim 1 , further comprising:producing from both the first production zone and the second ...

GRAVEL PACK CARRIER FLUIDS

A method of gravel packing a hole in a subterranean formation having a filter cake coated on the surface thereof is disclosed. The method may include: injecting into the hole a gravel pack composition comprising gravel and a carrier fluid comprising a base fluid and at least one alkyl glycoside. Also disclosed is a solution including an aqueous fluid, at least one alkyl glycoside, and gravel which may be used as a composition for a gravel pack operation, for example. 1. A method of gravel packing a hole in a subterranean formation having a filter cake coated on the surface thereof , comprising:injecting into the hole a gravel pack composition comprising gravel and a carrier fluid comprising a base fluid and at least one alkyl glycoside.2. The method of claim 1 , wherein the alkyl glycoside has an HLB of about 9.5 to about 15.3. The method of claim 1 , wherein the alkyl glycoside has the formula RO—(R′O)Zwhere the letter O represents an oxygen atom; R represents a monovalent alkyl radical containing from 8 to 16 carbon atoms; R′ represents a divalent alkyl radical containing 2 to 4 carbon atoms; R′ represents the number of oxy-alkylene units in the alkyl glycoside varying from 0 to about 12; Z represents a saccharide moiety containing 5 or 6 carbon atoms claim 1 , and y represents the number of saccharide units in the glycoside.4. The method of claim 3 , wherein y ranges from 1.3 to 1.8.5. The method of claim 1 , wherein the carrier fluid further includes a weighting agent that is a high density brine containing water soluble salts of alkali and alkaline earth metals.6. The method of claim 5 , wherein the high density brine forms the continuous phase of a direct emulsion fluid.7. The method of claim 6 , wherein the direct emulsion fluid has a discontinuous phase selected from oleaginous fluids in the group consisting of diesel oil claim 6 , mineral oil claim 6 , synthetic oils claim 6 , fatty acid ester based synthetic oils claim 6 , polyolefin based synthetic oils ...

AQUEOUS GELS FOR WELL BORE STRENGTHENING

A process for treating an earth formation is provided, the process may include: injecting a gelling agent into the earthen formation; injecting a crosslinking agent into the earthen formation; and reacting the gelling agent and the crosslinking agent to form a gel. The gelling agent may include at least one of a lignin, a lignosulfonate, a tannin, a tannic acid, a modified lignin, a modified lignosulfonate, a modified tannin, a modified tannic acid, biopolymers, polyacrylates, polyacrylamides, polyether amines, poly vinyl amines, and combinations thereof The crosslinking agent may include at least one of ethylene glycol diglycidyl ether, propylene glycol diglycidyl ether, butylene glycol diglycidyl ether, sorbitol polyglycidyl ether, trimethylolpropane triglycidyl ether, sorbitol polyglycidyl ether, diglycidyl ether of neopentyl glycol, epoxidized 1,6-hexanediol, aziridine derivatives, epoxy functionalized polyalkalene glycols, an oxidized starch, and combinations thereof. 1. (canceled)2. (canceled)3. (canceled)4. (canceled)5. (canceled)6. (canceled)7. A gel comprising:the reaction product of a gelling agent and a crosslinking agent;wherein the gelling agent comprises at least one of a lignin, a lignosulfonate, a tannin, a tannic acid, a modified lignin, a modified lignosulfonate, a modified tannin, a modified tannic acid, polyacrylates, polyacrylamides, polyether amines, poly vinyl amines, and combinations thereof; andwherein the crosslinking agent comprises at least one of ethylene glycol diglycidyl ether, propylene glycol diglycidyl ether, butylene glycol diglycidyl ether, trimethylolpropane triglycidyl ether, sorbitol polyglyleidyl ether, diglycidyl ether of neopentyl glycol, epoxidized 1,6-hexanediol, aziridine derivatives, trimethylolpropane, tris)beta-ethyleniminopropionate), eopxy functionalized polyalkalene glycols, and combinations thereof;andwherein the weight percent of the gelling agent relative to the total weight of the gel ranges from 11 to 25 weight ...

BREAKER AND DISPLACEMENT FLUID

A breaker fluid for breaking a filtercake in a wellbore. The fluid including a hydrolysable ester of carboxylic acid, and a chelant, an alkyl glycoside, or a combination thereof. The breaker fluid may be pre-mixed and include an amount of water less than required to completely hydrolyze the ester. 1. A method of breaking a filtercake in a wellbore comprising: a hydrolysable ester of carboxylic acid;', 'a chelant; and', 'an amount of water wherein the weight ratio of water to hydrolysable ester of carboxylic acid is less than 1.3; and, 'circulating a pre-mixed breaker fluid to the wellbore, the pre-mixed breaker fluid comprisingcirculating an aqueous fluid to the wellbore.2. (canceled)3. (canceled)4. The method of wherein the pre-mixed breaker fluid comprises 0 wt %-10 wt % water.5. (canceled)6. The method of wherein the hydrolysable ester of carboxylic acid is a formic acid ester of a C2 to C30 alcohol.7. (canceled)8. The method of wherein the chelant comprises one or more chelants selected from a group consisting of: ethylenediaminetetraacetic acid; glutamic acid claim 1 , N claim 1 ,N-diacetic acid; and salts thereof.10. The method of wherein the pre-mixed breaker fluid comprises 5-35 wt % chelant.11. (canceled)12. The method of wherein the aqueous fluid comprises a divalent brine.13. (canceled)14. The method of further comprising circulating an alkyl glycoside.15. A breaker fluid comprising:a hydrolysable ester of carboxylic acid;a chelant; andan amount of water wherein the weight ratio of water to hydrolysable ester of carboxylic acid is less than 1.3.16. The breaker fluid of wherein the hydrolysable ester of carboxylic acid is a formic acid ester of a C2 to C30 alcohol.17. (canceled)18. The breaker fluid of wherein the chelant comprises one or more chelants selected from a group consisting of: ethylenediaminetetraacetic acid; glutamic acid claim 15 , N claim 15 ,N-diacetic acid; and salts thereof.20. The breaker fluid of wherein the breaker fluid comprises 0 wt ...

FEEDER WITH SCREEN FOR SHAKER

Embodiments disclosed herein relate to a fluid distribution apparatus. The fluid distribution apparatus has a housing including an inlet configured to receive a drilling material, a first outlet configured to direct a first portion of the drilling material onto a first separatory surface, and a second outlet configured to direct a second portion of the drilling material onto a second separatory surface. The fluid distribution apparatus further includes a screen disposed within the housing and configured to separate solids from the second portion of the drilling material directed through the second outlet onto the second separatory surface. 1. A fluid distribution apparatus comprising: an inlet configured to receive a drilling material;', 'a first outlet configured to direct a first portion of the drilling material onto a first separatory surface; and', 'a second outlet configured to direct a second portion of the drilling material onto a second separatory surface; and, 'a housing comprisinga screen disposed within the housing and configured to separate solids from the second portion of the drilling material directed through the second outlet onto the second separatory surface.2. The fluid distribution apparatus of claim 1 ,wherein the housing is configured to define a first flow path to direct the first portion of the drilling material from the inlet to the first outlet,wherein the housing is configured to define a second flow path to direct the second portion of the drilling material from the inlet to the second outlet, andwherein the screen is disposed within the second flow path of the housing such that the second portion of the drilling material is directed through the screen.3. The fluid distribution apparatus of claim 2 , wherein the housing further comprises a third outlet configured to direct a third portion of the drilling material onto a third separatory surface claim 2 , the fluid distribution apparatus further comprising:a second screen disposed within ...

SHAKER AND DEGASSER COMBINATION

A system for separating components from a slurry of drilling fluid and drill cuttings on a shaker screen having an upper side and a lower side within a shaker. The system also has a pressure differential generator to pull an effective volume of air through a section of the shaker screen to enhance the flow of drilling fluid through the section of the shaker screen and the separation of drilling fluid from drill cuttings and further maintain an effective flow of drill cuttings off the shaker. A method of separating components of a slurry of drilling fluids and solids has the steps of delivering the slurry to a shaker, flowing the slurry over a first screen and applying an effective amount of vacuum to a first portion of the first screen to remove the drilling fluids from the slurry without stalling the solids on the first screen. 1. A method of separating components of a slurry comprising:delivering the slurry to a shaker;flowing the slurry over a first screen; andapplying a first pressure differential to a first portion of the first screen.2. The method of further comprising:applying a second pressure differential to the first portion of the first screen wherein the second pressure differential is less than the first pressure differential.3. The method of further comprising:applying a second pressure differential to the first portion of the first screen wherein the second pressure differential is zero vacuum.4. The method of further comprising:toggling the first pressure differential between zero vacuum and at least a partial vacuum.5. The method of further comprising:intermittently interrupting the step of applying the first pressure differential.6. The method of further comprising:pulsing the step of applying the first pressure differential between the first pressure differential and a second pressure differential wherein the second pressure differential is different than the first pressure differential.7. The method of further comprising:applying a third pressure ...

BOAT INSTALLATION FRAME FOR TRANSPORTATION TANKS

A method includes attaching a storage unit to a removable frame assembly. The storage unit is then locked to the removable frame assembly. A flow conduit may be connected from the frame assembly to the storage unit and provided with a flow of material between the flow conduit and the storage unit. 119-. (canceled)20. A method comprising:attaching a first storage unit to a removable frame assembly;locking the first storage unit to the removable frame assembly;connecting a first flow conduit from the frame assembly to the first storage unit; andproviding a first flow of material between the first flow conduit and the first storage unit.21. The method of claim 20 , wherein the material flows from the first flow conduit to the first storage unit.22. The method of claim 20 , wherein the material flows from the first storage unit to the first flow conduit.23. The method of claim 20 , further comprising monitoring the first flow of material with a fill sensor.24. The method of claim 23 , wherein the fill sensor is a sensor selected from at least one of the group consisting of a level sensor claim 23 , a flow-rate sensor claim 23 , a conductivity sensor claim 23 , and a load-cell sensor.25. The method of claim 20 , further comprising providing the first flow of material between a supply vessel and a main flow pipe.26. The method of claim 20 , wherein the removable frame assembly comprises a first frame module having a first valve connected to the first flow conduit and a second frame module having a second valve connected to a second flow conduit.27. The method of claim 26 , wherein the first valve and the second valve are in fluid communication with a main flow pipe.28. The method of claim 27 , further comprising providing the first flow of material from the main flow pipe to at least one of the first and second valves.29. The method of claim 28 , further comprising adjusting the first and second valves as a system.30. The method of claim 29 , further comprising adjusting ...

Return Fluid Separator

A separator for drilling waste including a tank comprising an inlet and an outlet; a screening device disposed within the tank; a conduit coupled to the outlet; and a rotary valve coupled to the conduit. A separator including a tank having an inlet and an outlet; a trough in fluid communication with the tank; and a screening device having a plurality of members disposed within the tank, wherein the screening device is configured to direct an effluent phase through the members into the trough and a solids phase to the outlet. A method of separating drilling waste including flowing a return fluid to an inlet of a tank; and directing the return fluid against a screening device disposed within the tank, wherein an effluent phase of the return fluid passes through the screening device and wherein a solids phase of the return fluid falls to an outlet of the tank. 1. A separator for drilling waste comprising:a tank comprising an inlet and an outlet;a screening device disposed within the tank;a conduit coupled to the outlet; anda rotary valve coupled to the conduit.2. The separator of claim 1 , further comprising a trough coupled to the tank configured to remove an effluent phase of the drilling waste.3. The separator of claim 1 , further comprising an isolation valve coupled to the conduit.4. The separator of claim 3 , wherein the isolation valve is disposed between the outlet and the rotary valve.5. The separator of claim 1 , wherein the inlet is disposed on a side of the tank.6. The separator of claim 1 , wherein the screening device is disposed in the tank at a predetermined angle.7. The primary separator of claim 6 , wherein the screening device extends from a first upper edge of the tank to an opposite lower end of the tank.8. The primary separator of claim 6 , wherein the inlet is disposed below an upper edge of the screening device.9. The primary separator of claim 1 , wherein the screening device comprises a plurality of axially aligned longitudinal members.10. The ...

HIGH PRESSURE FRACTURE TESTER

A system for testing a drilling fluid including a vessel having a fluid inlet, a filtrate outlet, a fluid outlet, and at least one permeable media disposed within the vessel. The system further including a base fluid container in fluid communication with the fluid inlet, a test fluid container in fluid communication with the fluid inlet, a filtrate container in fluid communication with the filtrate outlet, and a collection container in fluid communication with the fluid outlet. Additionally, the system includes a data acquisition device configured to receive data from at least one of the vessel, the fluid container, the filtrate container, and the collection container. Also, a method for determining sealing characteristics of a drilling fluid including injecting a test fluid having a fluid loss control material from at least fluid container to a vessel, the vessel having a permeable media having two plates disposed to create a variable gap. The methods further including measuring a fracture tip fluid loss through the variable gap and measuring a matrix fluid loss through the permeable media. 19-. (canceled)10. A method comprising: two media plates;', 'wherein the two media plates are disposed to create a variable gap therebetween;, 'injecting a test fluid having a fluid loss control material from a test fluid container to a vessel, the vessel comprisingmeasuring a first amount of fluid that flows through the variable gap from an injection location to a first outlet; andmeasuring a second amount of fluid that permeates at least one of the two media plates to a second outlet.11. The method of claim 10 , further comprising:determining a first sealing parameter based on the first amount of fluid.12. The method of claim 11 , wherein the determining the first sealing parameter comprises determining at least one of a seal location claim 11 , particle size claim 11 , reduction of fluid loss claim 11 , and maximum sealing pressure.13. The method of claim 11 , further ...

SYSTEM AND METHOD FOR SEPARATING SOLIDS FROM FLUIDS

A system for separating solids from fluid including a solid-laden fluid including a base fluid, a first separator configured to receive the solid-laden fluid and separate the fluid into a solids portion and an effluent, and a membrane separator configured to receive the effluent and separate the effluent into a permeate and a concentrate is disclosed. A method for separating solids from fluid including obtaining a solid-laden fluid, wherein the solid-laden fluid comprises a base fluid, feeding the solid-laden fluid through a centrifuge, removing at least a portion of high gravity solids from the solid-laden fluids, flowing the solid-laden fluid through a membrane separator, removing at least a portion of low gravity solids from the solid-laden fluid, and collecting a permeate from the membrane separator is also disclosed. 1. A system for processing fluids , the system comprising:a pump in fluid communication with a used fluid pit;a membrane separator in fluid communication with the used fluid pit, the membrane separator comprising a plurality of openings; anda clean fluid pit in fluid communication with the membrane separator.2. The system of claim 1 , wherein the plurality of openings range between 0.1 and 1.0 microns in size.3. The system of claim 1 , further comprising a primary separator in fluid communication with the used completion fluid pit and the membrane separator.4. The system of claim 3 , wherein the primary separator comprises at least one of a shaker claim 3 , a centrifuge claim 3 , and a hydrocyclone.5. The system of claim 1 , wherein the membrane separator is configured to separate a fluid into a permeate and a concentrate.6. The system of claim 5 , further comprising a recirculation loop configured to return the permeate to the membrane separator.7. The method of claim 1 , wherein the membrane separator comprises at least one multiple channel membrane.8. A method of processing fluids claim 1 , the method comprising:transferring a fluid from a used ...

Agglomeration-Resistant Desulfurizing Product

Disclosed herein is an agglomeration-resistant desulfurizing product for removing contaminants from a fluid stream. The agglomeration-resistant desulfurizing product comprising a metal oxide composition for reacting with contaminants and a polymeric crystallization inhibitor for reducing the agglomeration of the desulfurizing product resulting from using the desulfurizing product. A method to produce the agglomeration-resistant desulfurizing product and a method to treat a fluid stream is also disclosed. 1. An agglomeration-resistant desulfurizing product for removing contaminants from a fluid stream , the desulfurizing product comprising:{'sub': x', 'y', '2', 'z, '(a) a metal oxide composition that comprises a primary component, wherein the primary component comprises at least one metal oxide of the formula MeO.(HO), wherein Me is selected from groups 4-12 of the periodic table of elements, O is oxygen; 1≦x≦3; 1≦y≦4, and 0≦z≦10; and'}(b) a polymeric crystallization inhibitor.2. The agglomeration-resistant desulfurizing product of claim 1 , wherein the polymeric crystallization inhibitor is at an amount that is in the range of about 1000 ppm by weight to about 10 wt % based on the weight of the metal oxide composition.3. The agglomeration-resistant desulfurizing product of claim 2 , wherein the polymeric inhibitor comprises:a salt of acrylamido-methyl propane sulfonate/acrylic acid copolymer (AMPS/AA);a phosphonated maleic copolymer (PHOS/MA);a salt of polymaleic acid/acrylic acid/acrylamido-methyl propane sulfonate terpolymers (PMA/AMPS); ora copolymer that comprises an acrylamide moiety, a quaternary ammonium moiety, a quaternary ammonium salt moiety, an acrylate moiety, an acrylic acid moiety, or combination thereof; ofa combination thereof.4. The agglomeration-resistant desulfurizing product of claim 1 , wherein the polymeric crystallization inhibitor comprises an acrylamide moiety claim 1 , a quaternary ammonium moiety claim 1 , a quaternary ammonium salt ...

Tank System

A vessel including an inlet to receive fluids; at least five side walls configured in a polygonal shape, a lower angled section having an angle selected to enable mass flow of fluids coupled to the side walls, and an outlet coupled to the lower angled section is disclosed. A system of vessels including a first vessel and a second vessel, each including an inlet to receive fluids, at least five side walls configured in a polygonal shape, a lower angled section having an angle selected to enable mass flow of fluids coupled to the side walls, and an outlet coupled to the lower angled section, wherein the first vessel and the second vessel have at least one common side wall is also disclosed. 1. A vessel comprising:an inlet to receive fluids;at least five side walls configured in a polygonal shape;a lower angled section having an angle selected to enable mass flow of fluids coupled to the side walls; andan outlet coupled to the lower angled section.2. The vessel of further comprising an agitator.3. The vessel of further comprising an automatic tank cleaner.4. The vessel of having six side walls configured as a hexagon.5. The vessel of having eight side walls configured as an octagon.6. The vessel of wherein the lower angled section comprises at least five bottom walls.7. The vessel of wherein the lower angled section comprises six bottom walls.8. The vessel of further comprising internal baffles.9. The vessel of comprises a pressurized vessel.11. The system of vessels of wherein the first vessel and the second vessel are fluidly connected via one or more apertures in the common wall between the first vessel and the second vessel.12. The system of vessels of wherein the first vessel and the second vessel are fluidly connected via the common wall between the first vessel and the second vessel.13. The system of vessels of wherein the first vessel and the second vessel have a common discharge coupled to the outlet of each vessel.15. The system of vessel of wherein first ...

Viscosified Fluid Loss Control Agent Utilizing Chelates

Disclosed herein is a well treatment method comprising the steps of injecting into a well a fluid loss control agent comprising a chelating agent, a viscosity increasing agent, and a plurality of at least partially insoluble bridging solid particles dispersed therein, wherein the chelating agent is effective to at least partially solubilize at least a portion of the bridging solid particles over a solubilizing period of time for thereafter substantially dissolving the bridging solid particles, wherein the solubilizing period of time is controlled by the concentration of the viscosity increasing agent, the concentration of the chelating agent, the composition of the metal salt, the pH of the fluid loss control agent, or a combination thereof. A fluid loss control agent is also disclosed. 1. A well treatment method , comprising: spotting into a well a fluid loss control agent comprising a chelating agent , a viscosity increasing agent , and a plurality of at least partially insoluble bridging solid particles dispersed therein , wherein the bridging solid particles comprise a metal , wherein the chelating agent is effective to at least partially solubilize at least a portion of the bridging solid particles over a solubilizing period of time for thereafter substantially dissolving the bridging solid particles , wherein the solubilizing period of time is controlled by the concentration of the viscosity increasing agent , the concentration of the chelating agent , the composition of the metal salt , the pH of the fluid loss control agent , or a combination thereof.2. The well treatment method of wherein the chelating agent is selected from the group consisting of ethylenediamine tetra acetic acid claim 1 , 1 claim 1 ,2-bis(o-aminophenoxy) ethane-N claim 1 ,N claim 1 ,N′ claim 1 ,N′-tetraacetic acid) claim 1 , ethylene glycol tetraacetic acid claim 1 , nitrilotriacetic acid claim 1 , hydroxyethylimnodiacetic acid claim 1 , hydroxyethylethylenediaminetetraacetic acid claim ...

FLUID LOSS ADDITIVE FOR OIL-BASED MUDS

A composition that includes a product resulting from a condensation reaction of quebracho with at least one organophilic species that includes a reactive amine is disclosed. 123-. (canceled)24. An invert emulsion wellbore fluid , comprising:an oleaginous continuous phase;a non-oleaginous discontinuous phase;an emulsifier present in an amount sufficient to stabilize the invert emulsion; and{'sub': 6', '22', '2, 'a quebracho-based additive resulting from a reaction of quebracho and a C-Calkyl amine, wherein the amine has the formula HNR, where R is an alkyl chain having 6 to 22 carbons.'}25. The drilling fluid of claim 24 , wherein the C-Calkyl amine comprises at least one surfactant.26. The drilling fluid of claim 24 , wherein the weight percent ratio of quebracho to the a C-Calkyl amine ranges from 50:50 to about 95:5.27. The drilling fluid of claim 24 , wherein the oleaginous fluid comprises from about 30% to less than 100% by volume of the drilling fluid.28. The drilling fluid of claim 24 , wherein the oleaginous fluid is selected from diesel oil claim 24 , mineral oil claim 24 , synthetic oil claim 24 , ester oils claim 24 , glycerides of fatty acids claim 24 , aliphatic esters claim 24 , aliphatic ethers claim 24 , aliphatic acetals claim 24 , or other such hydrocarbons and combinations thereof.29. The drilling fluid of claim 24 , wherein the non-oleaginous fluid comprises from about 1% to about 70% by volume of said drilling fluid.30. The drilling fluid of claim 24 , wherein the non-oleaginous fluid is selected from fresh water claim 24 , sea water claim 24 , brine claim 24 , aqueous solutions containing water soluble organic salts claim 24 , water soluble alcohols or water soluble glycols or combinations thereof.31. The drilling fluid of claim 24 , further comprising:a weighting agent.32. A method of drilling a subterranean hole with an invert emulsion drilling fluid claim 24 , comprising:{'sub': 6', '22', '2, 'drilling the subterranean hole using an invert ...

FLAT RHEOLOGY WELLBORE FLUID

Wellbore fluids comprising a flat rheology profile are disclosed herein. In one aspect, the invert emulsion wellbore fluid is formulated to include: an oleallinous fluid as the continuous phase of the invert emulsion well bore fluid, a non-oleaginous fluid as the discontinuous phase of the invert emulsion well bore fluid; an emulsifier; and a rheology modifier, wherein the rheology modifier is a polyamide formed by reacting an alcoholamine, a fatty acid, and polyamine, where the invert emulsion well bore fluid has a flat rheology profile. 1. An invert emulsion well bore fluid comprising:an oleanginous fluid, wherein the oleaginous fluid is the continuous phase of the well bore fluid;a non-oleaginous fluid, wherein the non-oleaginous fluid is the discontinuous phase of the well bore fluid;an emulsifier, wherein the emulsifier is an amidoamine formed from the reaction of a fatty acid with an alkylamine, wherein the fatty acid is selected from the group consisting of oleic acid, palmitic acid, linoleic acid, tall oil fatty acids (TOFA), and combinations thereof; anda rheology modifier, wherein the rheology modifier is a polyamide formed by the reaction of a polyamine with the reaction product of an alcoholamine and a fatty acid;2. (canceled)3. The invert emulsion well bore fluid of claim 1 , wherein the rheology modifier comprises a polyamine selected from the group consisting of diethylenetriamine claim 1 , triethylenetetramine claim 1 , tetraethylenepentamine claim 1 , and combinations thereof.4. The invert emulsion well bore fluid of claim 1 , wherein the rheology modifier comprises an alcoholamine selected from the group consisting of monoethanolamine claim 1 , diethanolamine claim 1 , and triethanolamine.5. The invert emulsion wellbore fluid of claim 1 , wherein the rheology modifier comprises a fatty acid that is a dimer or trimer fatty acid claim 1 , or combinations thereof.6. (canceled)7. (canceled)8. The invert emulsion well bore fluid of claim 1 , wherein the ...

Method Of Minimizing Wellbore Instability

A process for reducing wellbore instability includes inputting pre-drilling assessment information into an hydraulics analysis and wellbore stability application, inputting a well plan into the hydraulics and wellbore analysis application, inputting a parameter measured at the wellsite into the hydraulics and wellbore stability analysis application, inputting an observation made at the wellsite into the hydraulics and wellbore stability analysis application, integrating the pre-drilling assessment information, the measured parameter, and the observation into the wellbore strengthening analysis application, and adjusting a drilling fluid parameter in response to the integrated pre-drilling assessment information, the measured parameter, and the observation. 1. A method for reducing wellbore instability comprising:inputting pre-drilling assessment information into an hydraulics analysis and wellbore stability application;inputting a well plan into the hydraulics and wellbore analysis application;inputting a parameter measured at the wellsite into the hydraulics and wellbore stability analysis application;inputting an observation made at the wellsite into the hydraulics and wellbore stability analysis application;integrating the pre-drilling assessment information, the measured parameter, and the observation into the wellbore strengthening analysis application; andadjusting a drilling fluid parameter in response to the integrated pre-drilling assessment information, the measured parameter, and the observation.2. The method of claim 1 , wherein the pre-drilling assessment information includes at least one input selected from data consisting of: client data claim 1 , third party data claim 1 , offset well data claim 1 , drill bit data and planning simulations.3. The method of claim 1 , wherein the parameter measured at the wellsite includes at least one selected from the group consisting of: downhole equivalent static density claim 1 , equivalent circulating density ...

Hydraulic Position Indicator System

A system useful for monitoring or controlling the back pressure of fluid in a wellbore is disclosed. The system may include: a choke assembly including: a housing having an inlet, an outlet, and a bore; a choke member disposed in the bore for controlling a flow of a fluid from the inlet to the outlet, and a rod coupled to the choke member and extending through the housing; a cylinder including: a housing having an axial bore; a piston, directly or indirectly coupled to the rod, disposed in the axial bore and separating the axial bore into a first chamber and a second chamber; a position indicating device fluidly coupled to the second chamber, wherein a change in volume of fluid in the second chamber causes a corresponding change in volume of fluid in the position indicating device, thereby indicating a change in the position of the choke member. 1. A method of monitoring or controlling one or more operating pressures within a subterranean borehole that includes a choke assembly comprising a housing having an inlet , an outlet , a bore , a choke member disposed in the bore for controlling a flow of a fluid from the inlet to the outlet , and a rod coupled to the choke member and extending through the housing , the method comprising: a housing having an axial bore;', 'a first piston disposed in the axial bore and separating the axial bore into a first chamber and a second chamber;, 'providing a cylinder comprisingdirectly or indirectly coupling the rod of the choke assembly to the piston;fluidly coupling the second chamber to a position indicating device, wherein movement of the choke member causes a corresponding movement in the rod and the first piston, resulting in a change in a volume of fluid in the second chamber and a corresponding change in a volume of fluid in the position indicating device, thereby indicating a change in the position of the choke member; anddetermining a position of the choke member using the position indicating device.2. The method of claim ...

SYSTEM AND METHOD TO ASSIST IN LIFTING A VESSEL

A system includes a vessel configured to contain a substance therein having a top end and a bottom end with a center-of-gravity for the vessel disposed between the top end and the bottom end, a frame connected to the vessel, a cable link connected to the frame configured to connect a cable thereto, and a cable support connected to the vessel or the frame. The cable support disposed above the center-of-gravity of the vessel with respect to the top end and the bottom end of the vessel. As the vessel moves from a first position to a second position, the cable engages the cable support such that a lifting force is translated from the cable and through the cable support to have the cable move the vessel through the cable support, the cable support attached to the frame or the vessel with the cable support disposed above the center-of-gravity. 1. A system comprising:a vessel configured to contain a substance therein having a top end and a bottom end with a center-of-gravity for the vessel disposed between the top end and the bottom end;a frame connected to the vessel;a cable link connected to the frame configured to connect a cable thereto; anda cable support connected to the vessel or the frame, the cable support disposed above the center-of-gravity of the vessel with respect to the top end and the bottom end of the vessel.2. The system of claim 1 , wherein the cable support is disposed between the center-of-gravity and the top end of the vessel.3. The system of claim 2 , wherein the cable link is disposed above the center-of-gravity of the vessel with respect to the top end and the bottom end of the vessel claim 2 , and wherein the cable link is disposed closer to the center-of-gravity of the vessel than the cable support.4. The system of claim 1 , wherein the vessel comprises a separator and the substance comprises a multiphase fluid.5. The system of claim 1 , wherein the cable comprises a first cable and a second cable claim 1 , wherein the cable support comprises a ...

GRAVEL PACK CARRIER FLUIDS

A method of gravel packing a hole in a subterranean formation having a filter cake coated on the surface thereof is disclosed. The method may include: injecting into the hole a gravel pack composition comprising gravel and a carrier fluid comprising a base fluid and at least one alkyl glycoside. Also disclosed is a solution including an aqueous fluid, at least one alkyl glycoside, and gravel which may be used as a composition for a gravel pack operation, for example. 1. A method of gravel packing a hole in a subterranean formation having a filter cake coated on the surface thereof , comprising:injecting into the hole a gravel pack composition comprising gravel and a carrier fluid comprising a base fluid and at least one alkyl glycoside;wherein the carrier fluid has at least one of:a density of at least 11 pounds per gallon; anda Fann 35 viscometer value of 10 or less when measured at 300 rpm and 120° F.2. The method of claim 1 , wherein the alkyl glycoside has an HLB of about 9.5 to about 15.3. The method of claim 1 , wherein the alkyl glycoside has the formula RO—(R′O)Zwhere the letter O represents an oxygen atom; R represents a monovalent alkyl radical containing from 8 to 16 carbon atoms; R′ represents a divalent alkyl radical containing 2 to 4 carbon atoms; x represents the number of oxy-alkylene units in the alkyl glycoside varying from 0 to about 12; Z represents a saccharide moiety containing 5 or 6 carbon atoms claim 1 , and y represents the number of saccharide units in the glycoside.4. The method of claim 3 , wherein y ranges from 1.3 to 1.8.5. The method of claim 1 , wherein the carrier fluid further includes a weighting agent that is a high density brine containing water soluble salts of alkali and alkaline earth metals.6. The method of claim 5 , wherein the high density brine forms the continuous phase of a direct emulsion fluid.7. The method of claim 6 , wherein the direct emulsion fluid has a discontinuous phase selected from oleaginous fluids in the ...

INVERT WELLBORE FLUID

There is described an invert emulsion wellbore fluid that includes: an oleaginous external phase; a non-oleaginous internal phase; an emulsifier; and a rheological additive comprising a sulphonated polymer formed from 100 to 10,000 monomers. There is also described a method of drilling a subterranean hole using the invert emulsion drilling fluid. 1. A wellbore fluid that comprising:an oleaginous external phase;a non-oleaginous internal phase;an emulsifier; anda rheological additive comprising a sulphonated polymer formed from 100 to 10,000 monomers.2. The fluid of claim 1 , wherein the sulphonated polymer is a chlorosulphonated polymer.3. The fluid of claim 1 , wherein the sulphonated polymer is an α-olefin copolymer.4. The fluid of claim 1 , wherein the sulphonated polymer is comprised of repeat units which are derived from ethylene and an α-olefin that contains from 3 to 20 carbon atoms.5. The fluid of claim 1 , wherein the sulphonated polymer is a chlorosulphonated α-olefin copolymer which is comprised of repeat units which are derived from ethylene and an α-olefin that contains from 3 to 20 carbon atoms.6. The fluid of claim 1 , wherein the non-oleaginous internal phase comprises a plurality of droplets claim 1 , said droplets having an average diameter in the range of from 0.5 to 5 micrometers.7. The fluid of claim 6 , wherein the average diameter of the droplets is in the range of from 1 to 3 micrometers.8. The fluid of claim 1 , wherein the ratio of the oleaginous external phase to the non-oleaginous internal phase is greater than 50:50.9. The fluid of claim 8 , wherein the ratio of the oleaginous external phase to the non-oleaginous internal phase ranges from 50:50 to 95:5.10. The fluid of claim 1 , wherein the non-oleaginous internal phase comprises brine with a specific gravity greater than 1.4.11. The fluid of claim 1 , wherein the emulsifier is an alkoxylated ether acid.12. The fluid of claim 1 , wherein the emulsifier is an alkoxylated ether acid ...

BREAKER FLUIDS FOR WELLBORE FLUIDS AND METHODS OF USE

Compositions for controlling fluid loss may include an aqueous fluid, a viscosifier, a water soluble polar organic solvent, a delayed acid source, and a weighting agent. The composition may further comprise at least one selected from bridging solids, cleaning agent, dispersant, interfacial tension reducer, pH buffer, thinner, or surfactant. Such compositions may be used in producing a hydrocarbon from a formation by drilling the formation with a drill-in fluid to form a wellbore, emplacing the composition in the wellbore, and shutting the well for a predetermined time to allow the viscosity of the fluid loss composition to decrease. 1. A composition comprising:an aqueous fluid;a viscosifier;a water soluble polar organic solvent;a delayed acid source; anda weighting agent.2. The composition of claim 1 , wherein the water soluble polar organic solvent is a glycol or glycol ether.3. The composition of claim 1 , wherein the delayed acid source is a formic acid or acetic acid ester of a C2 to C30 alcohol.4. The composition of claim 1 , wherein the weighting agent comprises at least one of halide or formate salts of alkali or alkaline earth metals.5. The composition of claim 1 , further comprising:at least one selected from bridging solids, a cleaning agent, a dispersant, an interfacial tension reducer, a pH buffer, a thinner, or a surfactant.6. The composition of claim 1 , wherein the aqueous fluid is selected from fresh water claim 1 , sea water claim 1 , a brine containing organic and/or inorganic dissolved salts claim 1 , liquids containing water-miscible organic compounds or combinations thereof.7. The composition of claim 1 , wherein the viscosifier comprises a hydratable natural polymer.8. The composition of claim 7 , wherein the hydratable natural polymer comprises hydroxyethyl cellulose.9. The composition of claim 1 , wherein the viscosifier comprises one or more viscoelastic surfactant.10. The composition of claim 1 , wherein the viscosifier comprises starch.11. ...

WELLBORE FLUID USED WITH SWELLABLE ELEMENTS

A method for completing a wellbore may include introducing a wellbore fluid into a wellbore, the wellbore fluid having a base fluid; and a solid weighting agent having a d90 of less than 20 microns; where the method may also include contacting the wellbore fluid with a swellable element in the wellbore; and allowing swelling of the swellable element. 1. A method for completing a wellbore , comprising: a base fluid; and', {'sub': '90', 'a solid weighting agent having a dof less than 20 microns;'}, 'contacting the wellbore fluid with a swellable element in the wellbore; and, 'introducing a wellbore fluid into a wellbore, the wellbore fluid comprisingallowing swelling of the meltable element.2. The method of claim 1 , wherein the swellable element comprises a water swellable elastomer.3. The method of claim 2 , wherein the wellbore fluid includes less than 10% w/w of dissolved claim 2 , salts.4. The method of claim 4 , wherein the dissolved salts are selected from a group consisting of NaCl claim 4 , CaCl claim 4 , NaBr claim 4 , CaBr claim 4 , ZnBr claim 4 , NaHCO claim 4 , KHCO claim 4 , KCl claim 4 , NHCl claim 4 , CsHCO claim 4 , MgCl claim 4 , MgBr claim 4 , KHCO claim 4 , KBr claim 4 , NaHCO claim 4 , and combinations thereof.5. The method of claim 1 , wherein the solid weighting agent is at least one selected from barite claim 1 , calcium carbonate claim 1 , dolomite claim 1 , ilmenite claim 1 , hematite claim 1 , olivine claim 1 , siderite claim 1 , manganese oxide claim 1 , hausmannite claim 1 , and strontium sulfate.6. The method of claim 1 , wherein the solid weighting agent has a particle size dof less than about 10 microns.7. The method of claim 1 , wherein the solid weighting agent has a particle size dof less than about 5 microns.8. The method of claim 1 , wherein the solid weighting agent is coated with a first dispersant.9. The method of claim 8 , wherein the first dispersant comprises at least one selected from oleic acid claim 8 , polybasic fatty ...

METHODS OF USING OLEAGINOUS FLUIDS FOR COMPLETION OPERATIONS

In a method of gravel packing a wellbore in a subterranean formation, the wellbore having a cased section and an uncased section, the method may include pumping into the wellbore a gravel pack composition having gravel and a carrier fluid, where the carrier fluid includes an oleaginous fluid and an inorganic solid aggregator material. 1. A method of gravel packing a wellbore in a subterranean formation , the wellbore comprising a cased section and an uncased section , the method comprising: an oleaginous fluid; and', 'an inorganic solid aggregator material., 'pumping into the wellbore a gravel pack composition comprising gravel and a carrier fluid, the carrier fluid comprising2. The method of claim 1 , further comprising:packing the uncased section of the wellbore with gravel using alpha and beta waves of the carrier fluid.3. The method of claim 1 , further comprising:packing the uncased section of the wellbore with gravel using alternate path technology.4. The method of claim 1 , wherein the inorganic solid aggregator material has a dless than 100 microns.5. The method of claim 1 , wherein the inorganic solid aggregator material has a dless than 10 microns.6. The method of claim 1 , wherein the inorganic solid aggregator material is selected from the group consisting of calcium hydroxide claim 1 , calcium oxide claim 1 , calcium carbonate claim 1 , silica claim 1 , and combinations thereof.7. The method of claim 1 , wherein the oleaginous fluid consists essentially of a base fluid selecting from the group consisting of diesel oil claim 1 , mineral oil claim 1 , white oil claim 1 , n-alkanes claim 1 , synthetic oil claim 1 , saturated polyalpha olefins claim 1 , unsaturated polyalpha olefins claim 1 , and combinations thereof.8. The method of claim 1 , wherein the oleaginous fluid comprises an invert claim 1 , emulsion claim 1 , wherein the invert emulsion comprises:an oleaginous external phase;a non-oleaginous internal phase; andan emulsifier stabilizing the ...

METHODS OF DRILLING

A method of drilling a subterranean well may include drilling the subterranean well while circulating a wellbore fluid in the subterranean well, wherein the wellbore fluid includes a base fluid; and a ground weight material comprising barite and quartz and having a dbetween about 4 and 8 microns and a dbetween about 15-25 microns. 1. A method of drilling a subterranean well , comprising: wherein the wellbore fluid comprises:', 'a base fluid; and', {'sub': 50', '90, 'a ground weight material comprising barite and quartz and having a dbetween about 4 and 8 microns and a dbetween about 15-25 microns.'}], 'drilling the subterranean well while circulating a wellbore fluid in the subterranean well,'}2. The method of claim 1 , wherein the weight material has a specific gravity of less than or equal to about 4.2.3. The method of claim 1 , wherein the weight material has a weight percent of quartz of about 4 to 12 percent.4. The method of claim 3 , wherein the ground weight material has a weight percent of quartz ranging between about 5 and 7 percent.5. The method of claim 1 , wherein the quartz has a larger average particle size than the barite.6. The method of claim 1 , wherein the weight material has a dbetween about 18-22 microns.7. The method of claim 1 , wherein the weight material has a dbetween about 4-8 microns.8. The method of claim 1 , wherein the weight material has a dbetween about 12-14 microns.9. The method of claim 1 , wherein the weight material has a dbetween about 15-17 microns.10. The method of claim 1 , wherein the weight material has a dbetween about 24-34 microns.11. The method of claim 1 , wherein the weight material has a dbetween about 32-60 microns.12. The method of claim 1 , wherein the weight material has a dbetween about 32-60 microns.13. The method of claim 1 , wherein the weight material has a dbetween about 48-120 microns.14. The method of claim 1 , wherein the base fluid is one selected from a water-based fluid claim 1 , an invert emulsion ...

METHODS OF PNEUMATICALLY CONVEYING SOLID PARTICULATES

A method for transferring barite for use in wellbore fluids may include providing a ground weight material comprising barite and quartz having a dbetween about 4 and 8 and a dbetween about 15-25 microns to a pneumatic transfer vessel, supplying an air flow to the ground weight material in the pneumatic transfer vessel, and pneumatically transferring the ground weight material from the pneumatic transfer vessel to a storage vessel. 1. A method for transferring barite for use in wellbore fluids comprising:{'sub': 50', '90, 'providing a ground weight material comprising barite and quartz having a dbetween about 4 and 8 and a dbetween about 15-25 microns to a pneumatic transfer vessel;'}supplying an air flow to the ground weight material in the pneumatic transfer vessel; andpneumatically transferring the ground weight material from the pneumatic transfer vessel to a storage vessel.2. The method of claim 1 , wherein the finely ground weight material has a specific gravity of less than or equal to about 4.2.3. The method of claim 1 , wherein the ground weight material has a weight percent of quartz of between 4 and 12 percent.4. The method of claim 1 , wherein the ground weight material has a weight percent of quartz ranging between about 5 and 7 percent.5. The method of claim 1 , wherein the ground weight material has a weight percent of quartz of at least 10 percent.6. The method of claim 1 , wherein the quartz has a larger average particle size than the barite.7. The method of claim 1 , wherein supplying the air flow comprises supplying between 10-80 psi of air to the contents of the pneumatic transfer vessel.8. The method of claim 1 , wherein the efficiency of the transferring is at least about 92%.9. The method of claim 7 , wherein the efficiency of the transferring is at least about 95%.10. The method of claim 1 , wherein the storage vessel is a second pneumatic transfer vessel.11. The method of claim 1 , wherein the pneumatically transferring transfers the ground ...

WELLBORE FLUIDS FOR USE DOWNHOLE

A wellbore fluid may include a base fluid, and a ground weight material comprising barite and quartz and having a dbetween about 4 and 8 microns and a dbetween about 15-25 microns. The ground weight material of the wellbore fluid may have a specific gravity of less than or equal to about 42. 1. A wellbore fluid comprising:a base fluid; and{'sub': 50', '90, 'a ground weight material comprising barite and quartz and having a dbetween about 4 and 8 microns and a dbetween about 15-25 microns.'}2. The wellbore fluid of claim 1 , wherein the weight material has a specific gravity of less than or equal to about 4.2.3. The wellbore fluid of claim 1 , wherein the weight material has a weight percent of silica of about 4 to 12 percent.4. The wellbore fluid of claim 5 , wherein the ground weight material has a weight percent of quartz ranging between about 5 and 7 percent.5. The wellbore fluid of claim 1 , wherein the quartz has a larger average particle size than the barite.6. The wellbore fluid of claim 1 , wherein the weight material has a dbetween about 18-22 microns.7. The wellbore fluid of claim 1 , wherein the weight material has a dbetween about 4-8 microns.8. The wellbore fluid of claim 1 , wherein the weight material has a dbetween about 12-14 microns.9. The wellbore fluid of claim 1 , wherein the weight material has a dbetween about 15-17 microns.10. The wellbore fluid of claim 1 , wherein the weight material has a dbetween about 24-34 microns.11. The wellbore fluid of claim 1 , wherein the weight material has a dbetween about 32-60 microns.12. The wellbore fluid of claim 1 , wherein the weight material has a dbetween about 32-60 microns.13. The wellbore fluid of claim 1 , wherein the weight material has a dbetween about 48-120 microns.14. The wellbore fluid of claim 1 , wherein the base fluid is one selected from a water-based fluid claim 1 , an invert emulsion and a direct emulsion.15. The wellbore fluid of claim 1 , wherein the mixed wellbore fluid has a ...

POLYMERIC COMPOSITIONS FOR DOWNHOLE APPLICATIONS

Methods for treating a wellbore and compositions used for same are provided that include emplacing a polymer-forming composition in the wellbore, and initiating polymerization of the polymer-forming composition to form a polymerized material in the selected region of the wellbore. In some aspects, polymeric compositions provided may also be useful for isolating pressure differentials downhole. 1. A method of treating a wellbore , comprising:drilling the wellbore with a drilling fluid;emplacing a polymer-forming composition in the wellbore; andinitiating polymerization of the polymer-forming composition to form a polymerized material in the wellbore.2. The method of claim 1 , wherein the drilling fluid is one selected from a group consisting of oil-based claim 1 , water-in-oil emulsion claim 1 , oil-in-water emulsion claim 1 , and water-based.3. The method of claim 1 , wherein emplacing a polymer-forming composition directly displaces the drilling fluid in at least a selected region of the wellbore.4. The method of claim 1 , further comprising injecting a displacement fluid after emplacing the polymer-forming composition.5. The method of claim 1 , wherein the polymer-forming composition comprises at least one polymerizable component and at least one initiator.6. The method of claim 5 , wherein the polymer-forming composition further comprises at least one reactive diluent and/or at least one inert diluent comprising an oleaginous liquid or a mutual solvent.7. The method of claim 5 , wherein the at least one polymerizable component comprises a polybutadiene homopolymer.8. The method of claim 5 , wherein the at least one polymerizable component comprises a polybutadiene dimethacrylate.9. The method of claim 5 , wherein the at least one polymerizable component comprises a number average molecular weight ranging from about 1000 to 5000 Da.10. The method of claim 5 , wherein the at least one polymerizable component comprises a number average molecular weight ranging from ...

Thermal Stability of High Temperature Oil Based System Enhanced by Organophilic Clay

Compositions herein may include an oleaginous continuous phase, an aqueous discontinuous phase, a first clay comprising an organophilic smectite clay, and a second clay comprising a magnesium silicate clay. Methods herein may include circulating such fluids downhole as well as admixing a magnesium silicate dispersed clay and an organophilic smectite clay in an oleaginous base fluid.

BREAKER AND DISPLACEMENT FLUID

A breaker fluid for breaking a filtercake in a wellbore. The fluid including a hydrolysable ester of carboxylic acid, and a chelant, an alkyl glycoside, or a combination thereof. The breaker fluid may be pre-mixed and include an amount of water less than required to completely hydrolyze the ester. 114.-. (canceled)15. A breaker fluid comprising:a hydrolysable ester of carboxylic acid;a chelant; andan amount of water wherein the weight ratio of water to hydrolysable ester of carboxylic acid is less than 1.3 to 1, wherein the hydrolysable ester of carboxylic acid, the chelant, and the water are pre-mixed prior to circulating in a wellbore.16. The breaker fluid of wherein the hydrolysable ester of carboxylic acid is a formic acid ester of a C2 to C30 alcohol.17. The breaker fluid of wherein the hydrolysable ester of carboxylic acid comprises ethanediol monoformate.18. The breaker fluid of wherein the chelant comprises one or more chelants selected from a group consisting of: ethylenediaminetetraacetic acid; glutamic acid claim 15 , N claim 15 ,N-diacetic acid; and salts thereof.20. The breaker fluid of wherein the breaker fluid comprises 0 wt %-10 wt % water.21. The breaker fluid of further comprising an alkyl glycoside.22. A breaker base fluid comprising:a formic acid ester of a C2 to C30 alcohol;one or more chelants selected from a group consisting of: ethylenediaminetetraacetic acid; glutamic acid; N,N-diacetic acid; and salts thereof; andan amount of water where the weight ratio of water to hydrolysable ester of carboxylic acid is less than 1.3.23. The breaker fluid of comprising 5-35 wt % chelants.24. The breaker fluid of comprising 0 wt %-10 wt % water.2535.-. (canceled)36. A breaker fluid comprising:a hydrolysable ester of carboxylic acid; andan alkyl glycoside.37. The breaker fluid of wherein the hydrolysable ester of carboxylic acid is a formic acid ester of a C2 to C30 alcohol.38. The breaker fluid of wherein the hydrolysable ester of carboxylic acid ...

KINETIC HYDRATE INHIBITORS WITH PENDENT AMINO FUNCTIONALITY

A kinetic gas hydrate inhibitor is provided as a polyester polymer with a plurality of amino or ammonium groups pendent directly from the backbone. A composition containing concentrated kinetic inhibitor is injected into gas wells, or into other systems involving transporting liquid gas mixtures through a conduit. Use of the kinetic inhibitor prevents formation of gas hydrates under conditions of temperature and pressure where they would otherwise occur. 1. A method comprising transporting a mixture comprising hydrocarbon and water in a conduit at a temperature sufficiently low and at a pressure sufficiently high that hydrocarbon hydrates would form in the absence of a hydrate inhibitor ,the mixture comprising an aqueous phase in contact with a gaseous or liquid hydrocarbon phase,wherein the aqueous phase comprises a glycol ether and kinetic hydrate inhibitor,wherein the kinetic hydrate inhibitor is a polyester polymer comprising a plurality of ester groups in the polymer backbone and a plurality of amino groups or ammonium groups directly pendent from the backbone, and{'sub': 3', '4', '2', '3, 'wherein the glycol ether is a Cor Cether of a Cor Cglycol.'}2. A method according to claim 1 , wherein the conduit is a natural gas pipeline.3. A method according to claim 1 , wherein the conduit is a well bore.4. A method according to claim 1 , wherein the hydrocarbon comprises natural gas.5. A method according to claim 1 , wherein the temperature is 25° C. or lower.6. A method according to claim 1 , wherein the kinetic hydrate inhibitor is made by polymerizing an amino functional diacid with an alkylene or oxyalkylene diol or triol.8. A method according to claim 7 , wherein A is C-Calkylene claim 7 , B is C-Calkylene or polyoxyalkylene claim 7 , and n is 2 or 3.9. A method according to claim 7 , wherein A in the acid monomer is Cor Calkylene and wherein the polyol component is ethylene glycol claim 7 , diethylene glycol claim 7 , or triethylene glycol.10. A method ...

Modular Rig Design

In one aspect, embodiments disclosed herein relate to modular drilling system, the system comprising a first module comprising a first work surface; and a second module comprising a second work surface; wherein the first module is disposed above the second module. In another aspect, embodiments disclosed herein relate to a modular drilling system, the system comprising a first module; and a second module; wherein at least one of the first and second modules comprises oilfield process equipment disposed on the module around a center point. 1. A system comprising:a first module comprising a first work surface and a double walled tank disposed within the first module beneath the first work surface, the double walled tank comprising an inner portion for receiving an effluent phase of drilling waste and an outer portion for receiving a solids phase of the drilling waste; anda second module disposed below the first module, the second module comprising a second work surface and at least one storage pit, the at least one storage pit in fluid communication with the inner portion of the double walled tank.2. (canceled)3. The system of claim 1 , wherein the first module comprises at least one vibratory separator.4. (canceled)5. The system of claim 1 , wherein the at least one storage pit comprises more than four sides.6. The system of claim 5 , wherein the second module comprises at least one vibratory separator.7. The system of claim 1 , further comprising a third module comprising a third work surface.8. The system of claim 7 , wherein the third module comprises at least one separator device.9. The system of claim 7 , further comprising a fourth module comprising a fourth work surface.10. The system of claim 1 , wherein the first module is in fluid communication with the second module through an overboard discharge.11. The system of claim 1 , wherein at least one of the first and second modules is substantially round.12. A method comprising:transferring drilling waste from a ...

Chelate Compositions And Methods And Fluids For Use In Oilfield Operations

A breaker fluid may include a base fluid; and an inactive chelating agent. A process may include pumping a first wellbore fluid comprising an inactive chelating agent into a wellbore through a subterranean formation; and activating the inactive chelating agent to release an active chelating agent into the wellbore. 1. A breaker fluid comprising:a base fluid; andan inactive chelating agent.2. The breaker fluid of claim 1 , further comprising:an enzyme source capable of activating the inactive chelating agent.3. The breaker fluid of claim 1 , further comprising:at least one of a surfactant, an oxidant, a pH buffer, a mutual solvent, a cleaning agent, and combinations thereof4. The breaker fluid of claim 2 , wherein the enzyme source is added to the breaker fluid after both the base fluid and the inactive chelating agent have been introduced to a wellbore.5. The breaker fluid of claim 1 , wherein the inactive chelating agent comprises at least one of an amido-chelant claim 1 , an esterified-chelant claim 1 , a nitrile-chelant claim 1 , and combinations thereof.6. The breaker fluid of claim 5 , wherein the amide claim 5 , ester claim 5 , nitrile claim 5 , and anhydride linkage respectively present in the amido-chelant claim 5 , esterified-chelant claim 5 , and nitrile-chelant reduce the chelating strength of the inactive chelating agent.7. The breaker fluid of claim 5 , wherein the amido-chelant comprises at least one of a polyethyl amide claim 5 , an internal cyclic amide claim 5 , and combinations thereof.8. The breaker fluid of claim 5 , wherein the esterified-chelant comprises at least one of a polyethyl ester claim 5 , an internal cyclic ester claim 5 , and combinations thereof.9. The breaker fluid of claim 5 , wherein the nitrile-chelant comprises a nitrile group.10. The breaker fluid of claim 2 , wherein the enzyme source comprises at least one of an esterase claim 2 , a phosphoric monoester hydrolase claim 2 , a peptide hydrolase claim 2 , a cysteine proteinase ...

LOW CONDUCTIVITY WATER BASED WELLBORE FLUID

A low electrical conductivity water-based wellbore fluid for use in drilling wells through a formation containing a clay which swells in the presence of water, said wellbore fluid that includes an aqueous base fluid; and a polymeric non-ionic tertiary amine is disclosed. Methods of using such fluids are also disclosed. 18-. (canceled)9. A method of reducing the swelling of clay in a well comprising: an aqueous base fluid; and', 'a polymeric non-ionic tertiary amine., 'circulating in the well a water based wellbore fluid comprising10. The method of claim 9 , wherein the polymeric non-ionic tertiary amine comprises a condensation reaction product of a tri-hydroxyalkyl amine.12. The method of claim 10 , wherein the tri-hydroxyalkyl amine is selected from the group consisting of trimethanolamine claim 10 , triethanolamine or tripropanolamine.13. The method of claim 9 , wherein the wellbore fluid has an electrical conductivity of less than about 10 claim 9 ,000 μS/cm.14. The method of claim 13 , wherein the wellbore fluid has an electrical conductivity of less than about 2000 μS/cm.15. The method of claim 9 , further comprising:disposing of at least a portion of the wellbore fluid or cuttings on land.16. A method for controlling shale hydration in the drilling of subterranean wells comprising: an aqueous base fluid; and', 'a polymeric non-ionic tertiary amine., 'adding to said well a water-based wellbore fluid comprising17. The method of claim 16 , wherein the polymeric non-ionic tertiary amine comprises a condensation reaction product of a tri-hydroxyalkyl amine.19. The method of claim 17 , wherein the tri-hydroxyalkyl amine is selected from the group consisting of trimethanolamine claim 17 , triethanolamine or tripropanolamine.20. The method of claim 16 , wherein the wellbore fluid has an electrical conductivity of less than about 10 claim 16 ,000 μS/cm.21. The method of claim 20 , wherein the wellbore fluid has an electrical conductivity of less than about 2000 μS/cm. ...

SYSTEM AND METHOD FOR CATALYST REGENERATION

The various embodiments relate to a system and method for regenerating a direct oxidation catalyst that coverts HS to elemental S. One embodiment of the method comprises regenerating a direct oxidation catalyst by contacting the direct oxidation catalyst with steam. 1. A method of regenerating a direct oxidation catalyst , the method comprising:contacting the direct oxidation catalyst with steam.2. The process of wherein the direct oxidation catalyst comprises at least one of titanium oxide claim 1 , aluminum oxide claim 1 , or mixtures thereof.3. The process of wherein the direct oxidation catalyst further comprises a promoter metal oxide selected from a group consisting of oxides of Mn claim 2 , Co claim 2 , Cu claim 2 , Nb claim 2 , Mo claim 2 , Tc claim 2 , Ru claim 2 , Rh claim 2 , Hf claim 2 , Ta claim 2 , W claim 2 , Au claim 2 , La claim 2 , Ce claim 2 , Pr claim 2 , Nd claim 2 , Pm claim 2 , Sm claim 2 , Eu claim 2 , Gd claim 2 , Tb claim 2 , Dy claim 2 , Ho claim 2 , Er claim 2 , Tm claim 2 , Yb claim 2 , Lu and mixtures thereof.4. The process of wherein the direct oxidation catalyst was fouled by exposure to hydrocarbons and sulfur-containing compounds.5. The process of wherein the direct oxidation catalyst is contacted with steam at a temperature greater than 200° C.6. The process of wherein the direct oxidation catalyst is contacted with steam at a temperature greater than 310° C.7. The process of wherein the direct oxidation catalyst is contacted with steam at a temperature between about 300° C. and about 400° C.8. The process of further comprising adding oxygen to the steam.9. The process of further comprising flowing an inert gas across the catalyst after contacting the catalyst with steam.10. A process for treating a gas stream claim 1 , the process comprising:contacting a gas stream comprising hydrogen sulfide and at least one hydrocarbon component with an oxygen-containing gas in the presence of a direct oxidation catalyst; andcontacting the ...

CONTINUOUS CIRCULATION VALVE

A valve comprises a housing and a closing member. The housing provides a flow path and comprises a chamber with a first opening and a second opening. The housing further comprises an upstream port, a downstream port and a lateral port. The closing member is located inside the chamber and is rotatable selectively between a first position and a second position so as to dose the first opening and the second opening respectively The lateral port is in flow communication with the downstream port in the first position of the closing member. The upstream port is in flow communication with the downstream port in the second position of the closing member. The dosing member has an internal profile that adjoins the flow path. The internal profile is shaped such that a cross-sectional area of the flow path is larger through the chamber than the rest of the flow path. 1. A valve comprising:a housing providing a flow path and comprising a chamber with a first opening and a second opening, the housing further comprising an upstream port, a downstream port and a lateral port, the upstream port and the lateral port being upstream of the chamber, the downstream port being downstream of the chamber, the upstream port being in flow communication with the first opening, the lateral port being in flow communication with the second opening;a closing member that is located inside the chamber and is rotatable selectively between a first position and a second position so as to close the first opening and the second opening in the first position and the second position respectively, the lateral port being in flow communication with the downstream port in the first position of the closing member, the upstream port being, in flow communication with the downstream port in the second position of the closing member, the closing member having an internal profile that adjoins the flow path, the internal profile being shaped such that a cross-sectional area of the flow path is larger through the ...

PRECIPITATED WEIGHTING AGENTS FOR USE IN WELLBORE FLUIDS

A method of formulating a wellbore fluid that includes precipitating a weighting agent from a solution; and adding the precipitated weighting agent to a base fluid to form a wellbore fluid is disclosed. Fluids and methods of formulating wellbore fluids that contain dispersant coated precipitated weighting agents are also disclosed. 125-. (canceled)26. A wellbore fluid , comprising:a base fluid;{'sub': '50', 'a precipitated weighting agent comprising at least one of barium sulfate, calcium carbonate, magnesium carbonate, calcium magnesium carbonate, iron oxide, magnesium silicate, iron silicate, iron carbonate, and strontium sulfate and formed by precipitating a weighting agent from a solution in the presence of a dispersant to have a dof of less than 1 micron; and'}at least one selected from the group consisting of wetting agents, organophilic clays, viscosifiers, fluid loss control agents, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents, and cleaning agents.27. The wellbore fluid of claim 26 , wherein the precipitated weighting agent has a dof less than 700 nanometers.28. The wellbore fluid of wherein the precipitated weighting agent has a dof at least 5 nanometers.29. The wellbore fluid of claim 26 , wherein the base fluid is one selected from a water-based fluid claim 26 , an oil-based fluid claim 26 , and an invert emulsion.30. The wellbore fluid of claim 26 , wherein the dispersant comprises at least one selected from oleic acid claim 26 , polybasic fatty acids claim 26 , alkylbenzene sulfonic acids claim 26 , alkane sulfonic acids claim 26 , linear alpa olefins sulfonic acid claim 26 , alkaline earth metal salts thereof claim 26 , and phospholipids.31. The wellbore fluid of claim 26 , wherein the dispersant comprises polyacrylate esters.32. The wellbore fluid of claim 31 , wherein the polyacrylate ester is at least one selected from polymers of stearyl methacrylate claim 31 , butylacrylate claim 31 ...

SELF CLAMPING SHAKER SCREENS

A screen frame assembly, including a frame having a first end, a second end, a top surface, a first side disposed between the first end and the second end, and a second side disposed opposite the first side and disposed between the first end and the second end, in which at least one of the first end and the second end is sloped. 1. A screen frame assembly , comprising: a first end;', 'a second end;', 'a top surface;', 'a first side disposed between the first end and the second end; and', 'a second side disposed opposite the first side and disposed between the first end and the second end,', 'wherein at least one of the first end and the second end is sloped., 'a frame comprising2. The screen frame assembly of claim 1 , wherein an angle formed between the top surface and at least one of the first end and the second end is one of an acute angle and an obtuse angle.3. The screen frame assembly of claim 1 , wherein the screen frame assembly comprises a layer of screen mesh mounted on the screen frame.4. The screen frame assembly of claim 1 , wherein the first end is parallel to the second end.5. A shaker apparatus claim 1 , comprising:a basket having a feed end and a discharge end; and a first end;', 'a second end;', 'a top surface;', 'a bottom surface;', 'a first side disposed between the first end and the second end; and', 'a second side disposed opposite the first side and disposed between the first end and the second end,', 'wherein at least one of the first end and the second end is sloped., 'a first frame comprising, 'a first screen frame assembly, comprising6. The shaker apparatus of claim 5 , wherein an angle formed between the top surface and at least one of the first end and the second end is one of an acute angle and an obtuse angle.7. The shaker apparatus of claim 5 , wherein the first screen frame assembly comprises a layer of screen mesh mounted on the first frame.8. The shaker apparatus of claim 5 , wherein the first end of the first screen frame assembly ...

HIGH DENSITY BRINE WITH LOW CRYSTALLIZATION TEMPERATURE

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° F. as compared to a second aqueous base fluid without the silica nanoparticles. 1. A wellbore fluid , comprising:a first aqueous base fluid; anda plurality of silica nanoparticles suspended in the first aqueous base fluid, wherein 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° F. as compared to a second aqueous base fluid without the silica nanoparticles.2. The wellbore fluid of claim 1 , wherein the nanoparticles are selected from the group of colloidal silica nanoparticles and nano-sized precipitated silica.3. The wellbore fluid of claim 2 , wherein the silica nanoparticles are coated.4. The wellbore fluid of claim 2 , wherein the silica nanoparticles are uncoated.5. The wellbore fluid of claim 1 , wherein the wellbore fluid does not scatter light above 400 nm6. The wellbore fluid of claim 1 , wherein the nanoparticles have at least one dimension of less than 1 micron.7. The wellbore fluid of claim 1 , wherein an amount of nanoparticles ranges from about 1 wt % to about 32 wt % of the wellbore fluid.8. The wellbore fluid of claim 1 , wherein the aqueous base fluid is a halide brine or a formate brine.9. The wellbore fluid of claim 8 , wherein the halide brine is selected from the group of alkali metal and/or alkaline earth metal halide brines.10. The wellbore fluid of claim 1 , wherein the wellbore fluid has a density in the range of about 11 ppg to about 18 ppg.11. The wellbore fluid of claim 1 , wherein the wellbore fluid is a drilling fluid and further comprises a gelling agent and a plurality of salt or mineral particulates.12. The wellbore fluid of claim 1 , wherein the wellbore fluid is a fluid ...

INTERNAL BREAKER COMPOSITIONS FOR WELLBORE APPLICATIONS

Methods may include circulating a first wellbore fluid into a wellbore, wherein the first wellbore fluid contains: a non-aqueous continuous phase, and a polyester internal breaker; wherein the first wellbore fluid generates a filter cake in at least a section of the wellbore; circulating a second wellbore fluid into the wellbore, wherein the second wellbore fluid contains an acid source and a surfactant; and allowing the second wellbore fluid to degrade at least a portion of the filter cake. Other methods may include circulating a wellbore fluid into a wellbore drilled with an oil-based mud containing a polyester fluid loss additive, wherein the wellbore fluid comprises one or more surfactants and an acid source. 1. A method comprising: a non-aqueous continuous phase, and', 'a polyester internal breaker,', 'wherein the first wellbore fluid generates a filter cake in at least a section of the wellbore;, 'circulating a first wellbore fluid into a wellbore, wherein the first wellbore fluid comprisescirculating a second wellbore fluid into the wellbore, wherein the second wellbore fluid comprises an acid source and a surfactant; andallowing the second wellbore fluid to degrade at least a portion of the filter cake.2. The method of claim 1 , wherein the polyester internal breaker is one or more selected from a group consisting of polyglycolic acid claim 1 , polylactic acid claim 1 , and copolymers of lactic and glycolic acid.3. The method of claim 1 , wherein the concentration of the polyester in the first wellbore fluid is in the range of about 0.5 ppb to 15 ppb.4. The method of claim 1 , wherein the polyester internal breaker has an average particle size within the range of about 10 μm to 200 μm.5. The method of claim 1 , wherein the second wellbore fluid comprises an acid source claim 1 , and wherein the acid source is a hydrolysable ester.6. The method of claim 1 , wherein the acid source is a formic acid ester.7. The method of claim 1 , wherein the acid source is a ...

INVERT EMULSION FLUIDS WITH HIGH INTERNAL PHASE CONCENTRATION

An invert emulsion wellbore fluid may include an oleaginous external phase; a non-oleaginous internal phase, wherein a ratio of the oleaginous external phase and non-oleaginous internal phase is less than 50:50; and an emulsifier stabilizing the oleaginous external phase and the non-oleaginous internal phase, wherein an average diameter of the non-oleaginous internal phase ranges from 0.5 to 5 microns. 1. An invert emulsion wellbore fluid comprising:an oleaginous external phase;a non-oleaginous internal phase, wherein a ratio of the oleaginous external phase and non-oleaginous internal phase is less than 50:50; andan emulsifier stabilizing the oleaginous external phase and the non-oleaginous internal phase, wherein an average diameter of the non-oleaginous internal phase ranges from 0.5 to 5 microns.2. The invert emulsion fluid of claim 1 , wherein the average diameter ranges from 1 to 3 microns.3. The invert emulsion fluid of claim 1 , wherein the emulsifier is an alkoxylated ether acid.4. The invert emulsion fluid of claim 1 , wherein the ratio of the oleaginous external phase to non-oleaginous internal phase is less than 40:60.5. The invert emulsion fluid of claim 1 , wherein the ratio of the oleaginous external phase to the non-oleaginous internal phase is less than 30:70.6. An invert emulsion wellbore fluid comprising:an oleaginous external phase;a non-oleaginous internal phase, wherein a ratio of the oleaginous external phase and non-oleaginous internal phase is less than 50:50; andan emulsifier stabilizing the oleaginous external phase and the non-oleaginous internal phase, wherein the invert emulsion wellbore fluid has a viscometer reading of less than 200, measured at 600 rpm, and a viscometer reading of less than 40 at 6 and 3 rpm.7. The invert emulsion fluid of claim 6 , wherein the fluid has an electrical stability of at least 50 v.8. The invert emulsion fluid of claim 6 , wherein the emulsifier is an alkoxylated ether acid claim 6 ,9. The invert ...

SLOT TESTER

A method for using a drilling fluid test device including a test cell including a perforated plate disposed proximate a first end of the test cell, a piston disposed within the cell, a first chamber formed between the perforated plate and the piston, the first chamber configured to receive lost circulation material (LCM), a second chamber formed between the piston and a second end of the test cell, the piston providing a seal between the first and second chambers, a fluid inlet disposed proximate the second end of the test cell configured to introduce fluid into a second chamber of the test cell, a filtrate outlet disposed proximate the first end of the test cell to discharge filtrate, and a pump in communication with the fluid inlet. 1. A system comprising: a perforated plate disposed proximate a first end of the test cell;', 'a piston disposed within the test cell;', 'a first chamber formed between the perforated plate and the piston, the first chamber configured to receive lost circulation material (LCM);', 'a second chamber formed between the piston and a second end of the test cell, the piston providing a seal between the first and second chambers;', 'a fluid inlet disposed proximate the second end of the test cell configured to introduce fluid into a second chamber of the test cell;', 'a filtrate outlet disposed proximate the first end of the test cell to discharge filtrate; and', 'a pump in communication with the fluid inlet., 'a test cell comprising2. The system of claim 1 , further comprising a fluid inlet configured to introduce fluid to the first chamber.3. The system of claim 1 , further comprising a spacer ring disposed between the perforated plate and the filtrate outlet.4. The system of claim 3 , further comprising a third chamber formed between the perforated plate and the first end of the test cell.5. The system of claim 1 , wherein the perforated plate includes at least one slot claim 1 , the at least one slot having a width ranging from about 1 mm ...

PROCESS FOR MIXING WELLBORE FLUIDS

A method for mixing a drilling fluid formulation that includes establishing a flow path for a base fluid, adding drilling fluid additives to the base fluid to create a mixture, aerating the mixture of base fluid and drilling fluid additives, and injecting a compressible driving fluid into the mixture of base fluid and drilling fluid additives to form a mixed drilling fluid is disclosed. 19.-. (canceled)10. A system for mixing drilling fluids , comprising:a fluid supply tank for supplying an unmixed drilling fluid; and an intake and an outlet;', 'a mixing chamber disposed between the intake and the outlet;', 'an inlet for injecting a compressible driving fluid into the mixing chamber; and', 'an inlet for injecting an aerating gas into the mixing chamber;, 'a mixing reactor fluidly connected to the fluid supply tank, the mixing reactor comprisingwherein as the unmixed drilling fluid flows into the mixing reactor, the compressible driving fluid and aerating gas are injected into the unmixed drilling fluid to form the mixed drilling fluid.11. The system of claim 10 , wherein the unmixed drilling fluid comprises a base fluid and drilling fluid additives.12. The system of claim 10 , further comprising:a hopper operatively connected to the fluid supply tank for supplying drilling fluid components to the unmixed drilling fluid.13. The system of claim 10 , wherein the unmixed drilling fluid comprises a base fluid claim 10 , and wherein the system further comprises a hopper fluidly connected to a fluid line between the fluid supply tank and the mixing reactor for supplying drilling fluid additives to the unmixed drilling fluid.14. The system of claim 10 , further comprising:a recycling line fluidly connecting the outlet of the mixing reactor to the intake of the mixing reactor.15. The system of claim 10 , further comprising:a recycling line fluidly connecting the outlet of the mixing reactor to the fluid supply tank.16. The system of claim 10 , further comprising:a receiving ...

VISCOELASTIC SURFACTANTS IN MIXED BRINES

A wellbore fluid is provided that includes at least one viscoelastic surfactant, a first brine solution including one or more water soluble monovalent cation salts, and a second brine solution including one or more water soluble divalent cation salts in an amount effective to increase the viscosity of the wellbore fluid. The wellbore fluid may be injected into a wellbore as a gravel packing agent, to enhance the thermal insulation of a production tubing or transfer pipe surrounded by at least one annuli, or to reduce fluid loss. 1. A method for injecting a fluid into a wellbore , comprising: at least one viscoelastic surfactant;', 'a first brine solution including one or more water soluble monovalent cation salts; and', 'a second brine solution including one or more water soluble divalent cation salts in an amount effective to increase the viscosity of the wellbore fluid., 'injecting a wellbore fluid into the wellbore, the wellbore fluid comprising2. The method of claim 1 , wherein the viscoelastic surfactant is amphoteric or zwitterionic.3. The method of claim 1 , wherein the viscoelastic surfactant is a betaine surfactant.4. The method of claim 3 , wherein the betaine surfactant is oleylamidopropyl betaine surfactant.5. The method of claim 1 , wherein the viscoelastic surfactant is an amidoamine oxide surfactant.6. The method of claim 5 , wherein the amidoamine oxide surfactant is a tallowalkylamidopropyl dimethylamine oxide surfactant.7. The method of claim 3 , wherein the effective amount of water soluble divalent cation salts comprises a molar ratio of divalent cation salts to monovalent cation salts ranging from about 0.1 to about 2 percent.8. The method of claim 5 , wherein the effective amount of water soluble divalent cation salts comprises a molar ratio of divalent cation salts to monovalent cation salts ranging from about 3 to about 40 percent.9. The method of claim 1 , wherein injecting the wellbore fluid into the wellbore comprises injecting the ...

CHEMICAL INHIBITORS WITH SUB-MICRON MATERIALS AS ADDITIVES FOR ENHANCED FLOW ASSURANCE

Methods may include admixing an additive composition with a hydrocarbon fluid, wherein the additive composition contains at least one inhibitor and at least one sub-micron particle. Additional methods may include providing an additive composition containing at least one inhibitor and at least one sub-micron particle; adding the additive composition to a fluid capable of precipitating at least one of at least of asphaltenes, wax, scale, and gas hydrates; and transporting the fluid containing the additive composition. 1. A method comprising:admixing an additive composition with a hydrocarbon fluid, wherein the additive composition comprises at least one inhibitor and at least one sub-micron particle.2. The method of claim 1 , wherein the at least one sub-micron particle is present at a percent by weight (wt %) of the total fluid weight that ranges from 0.001 wt % to 20 wt %3. The method of claim 1 , further comprising the reducing the deposition or precipitation of at least one of asphaltenes claim 1 , wax claim 1 , scale claim 1 , and hydrates from the hydrocarbon fluid.4. The method of claim 1 , wherein the inhibitor is at least one of a hydrate inhibitor claim 1 , a scale inhibitor claim 1 , or a wax inhibitor.5. The method of claim 1 , wherein the at least one sub-micron particle is is one or more selected from a group consisting of carbon nanotubes claim 1 , carbon fibers claim 1 , fullerenes claim 1 , and graphene particles.6. The method of claim 1 , wherein the at least one sub-micron particle is one or more selected from a group consisting of microcrystalline cellulose claim 1 , nanocrystalline cellulose claim 1 , colloidal silicas claim 1 , hydroxyapatite claim 1 , calcium tertiary phosphate claim 1 , calcium oxide claim 1 , zinc oxide claim 1 , silicon oxide claim 1 , aluminum oxide claim 1 , magnesium oxide claim 1 , and calcium fluoride.7. The method of claim 1 , wherein the at least one sub-micron particle is functionalized.8. The method of claim 7 , ...

EMULSION PREVENTER FOR COMPLETION BRINES

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. 1. A composition comprising:one or more sorbitan esters; andone or more nonionic surfactants, wherein the volumetric ratio of the one or more sorbitan esters to the one or more nonionic surfactants is in the range of 1:1 to 1:5.2. The composition of claim 1 , further comprising a mutual solvent.3. The composition of claim 1 , further comprising one or more amphoteric surfactants.4. The composition of claim 3 , wherein the volumetric ratio of the one or more sorbitan esters to the one or more nonionic surfactants to the one or more amphoteric surfactants is in the range of 1:1:1 to 1:5:3.5. The composition of claim 1 , wherein the composition meets at least two of the following three criteria: a) >60% in 28 days as measured by OECD 306 or any other OSPAR-accepted marine protocols,', i. >60% in 28 days as measured by OECD 301B, 301C, 301D, 301F, 310, Freshwater BODIS or', 'ii. >70% in 28 days as measured by OECD 301A, 301E;, 'b) or in the absence of valid results for such tests], '(1) Biodegradation'} a) a bioconcentration factor of less than 100;', {'sub': 'ow', 'b) log P≦3 and molecular weight >700, or'}, 'c) if the conclusion of a weight of evidence expert judgment under Appendix 3 of OSPAR Agreement 2008-5 is positive; and, '(2) Bioaccumulation'} 'a) LC50>10 mg/l or EC50>10 mg/l.', '(3) Aquatic Toxicity'}6. The composition of claim 1 , wherein the one or more sorbitan esters ...

NON-EMULSIFIER FOR COMPLETION BRINES TO PREVENT EMULSION FROM FORMING

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. 1. A composition comprising:one or more sorbitan esters;one or more non-ionic surfactants; andone 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 1:5:3.2. The composition of claim 1 , wherein the one or more sorbitan esters are selected from one or more of a group consisting of alkoxylated sorbitan esters claim 1 , polysorbates claim 1 , and sorbitans esterified with mono- claim 1 , di- claim 1 , tri- claim 1 , or tetra-esters of C8-C22 alkyl or alkenyl fatty acids.3. The composition of claim 1 , wherein the one or more nonionic surfactants are selected from one or more of a group consisting of ethylene oxide polymers claim 1 , copolymers and block copolymers of poly(ethylene oxide-propylene oxide) claim 1 , and poloxamers.4. The composition of claim 1 , wherein the one or more amphoteric surfactants are selected from one or more of a group consisting of C8-C22 alkyl amidopropyl sultaines claim 1 , C8-C22 alkyl amidopropyl betaines claim 1 , C8-C22 alkenyl amidopropyl betaines claim 1 , alkyl amphohydroxypropyl sulfonates claim 1 , and alkyl ampho(di)acetates.5. The ...

INTEGRATED MANAGED PRESSURE DRILLING RISER JOINT

An apparatus comprises a telescoping marine riser action and one of a rotating control device and an annular blow out preventer. The telescoping marine riser section comprises an inner barrel and an outer barrel. The one of a rotating control device and an annular blow out preventer is disposed inside the outer barrel 1. An apparatus , comprising:a telescoping marine riser comprising an inner barrel and an outer barrel; andone of a rotating control device and an annular blow out preventer disposed inside the outer barrel.2. The apparatus of claim 1 , further comprising a flow port located adjacent to a lower end of the outer barrel.3. The apparatus of claim 1 , the outer barrel further comprising a landing device located proximate a lower end of the outer barrel.4. The apparatus of claim 1 , wherein the rotating control device is coupled to a upper end of the annular blowout preventer.5. The apparatus of claim 1 , wherein an outer surface of the annular blowout preventer is in sealing engagement with an inner diameter of the outer barrel.6. The apparatus of claim 2 , wherein an outer surface of the rotating control device is in sealing engagement with an inner diameter of the outer barrel.7. The apparatus of claim 1 , further comprising a locking device operable to controllably retain one of the rotating control device and the annular blow out preventer in the outer barrel claim 1 , wherein the locking device comprises at least one of hydraulically operated pistons claim 1 , motor driven set screws and mechanical fasteners.8. The apparatus of claim 3 , wherein the landing device comprises at least one of a landing ring claim 3 , hydraulic piston claim 3 , and a shoulder formed on an inner surface of the outer barrel.9. The apparatus of claim 1 , wherein the outer barrel is slidably and sealingly engaged with an inner barrel.10. A method comprising:providing an annular blowout preventer retainably coupled in an outer barrel of a telescoping marine riser;coupling the ...

METHODS OF DRILLING WITH RESISTIVITY TOOLS

A method of electrically logging a section of a wellbore includes circulating an oil-based wellbore fluid within the wellbore and allowing filtration of the oil-based wellbore fluid to form a conductive filtercake on a wall of the wellbore; placing within the wellbore a wellbore logging tool with at least one pad capable of applying a current to a portion of the conductive filtercake and wellbore wall; applying electrical current from the at least one pad; and collecting an electrical log of the portion of the wellbore that has had electrical current applied thereto. 1. A method of electrically logging a section of a wellbore , comprising:circulating an oil-based wellbore fluid within the wellbore and allowing filtration of the oil-based wellbore fluid to form a conductive filtercake on a wall of the wellbore;placing within the wellbore a wellbore logging tool with at least one pad capable of applying a current to a portion of the conductive filtercake and wellbore wall;applying electrical current from the at least one pad; andcollecting an electrical log of the portion of the wellbore that has had electrical current applied thereto.2. The method of claim 1 , further comprising:contacting the at least one pad against the conductive filtercake.3. The method of claim 2 , further comprising:moving the wellbore logging tool within the wellbore to move the at least one pad along a section of the wellbore while continuously applying electrical current.4. The method of claim 1 , further comprising:transmitting the electrical log to the surface.5. The method of claim 1 , wherein the electrical current is applied from the pad by an array of electrodes thereon.6. The method of claim 1 , wherein the wellbore logging tool comprises:a sonde having a plurality of supports, each attached to a pad, and wherein the plurality of supports urge the pads outwardly against the conductive filtercake.7. The method of claim 1 , wherein placing within the wellbore a wellbore logging tool ...

INVERT EMULSIFIERS FROM DCPD COPOLYMERS AND THEIR DERIVATIVES FOR DRILLING APPLICATIONS

A wellbore fluid, comprising an oleaginous continuous phase, a non-oleaginous discontinuous phase and a polymer having a polycyclic backbone. A method of drilling comprising pumping the said wellbore fluid into a wellbore through an earthen formation is also described. 1. A wellbore fluid , comprising:an oleaginous continuous phase;a non-oleaginous discontinuous phase; anda polymer having a polycyclic backbone.2. The wellbore fluid of claim 1 , wherein the polycyclic backbone of the polymer has at least a dicyclopentadiene repeating unit.3. The wellbore fluid of claim 2 , wherein the polymer having a polycyclic backbone further contains at least a styrene monomer unit.4. The wellbore fluid of claim 2 , wherein the dycyclopentadiene is derivatized with maleic anhydride.5. The wellbore fluid of claim 4 , wherein the maleic anhydride is not functionalized.6. The wellbore fluid of claim 4 , wherein the maleic anhydride is functionalized at an anhydride group.7. The wellbore fluid of claim 6 , wherein the functionalized anhydride group of the maleic anhydride has at least a hydrophilic group.8. The wellbore fluid of claim 7 , wherein the anhydride group is functionalized with an alcohol claim 7 , an amine claim 7 , or combinations thereof.9. The wellbore fluid of claim 8 , wherein the alcohol is selected from the group of primary claim 8 , secondary and tertiary alcohols.10. The wellbore fluid of claim 8 , wherein the amine is selected from the group of primary claim 8 , secondary and polyfunctional amines.11. The wellbore fluid of claim 1 , wherein the polymer has a molecular weight ranging from about 200 to about 2000.12. A method of drilling claim 1 , comprising: an oleaginous continuous phase;', 'a non-oleaginous discontinuous phase; and', 'a polymer having a polycyclic backbone., 'pumping a wellbore fluid into a wellbore through an earthen formation, the wellbore fluid comprising13. The method of drilling of claim 12 , wherein the polycyclic backbone of the polymer ...

WATER BASED COMPLETION AND DISPLACEMENT FLUID AND METHOD OF USE

A method of cleaning a wellbore prior to the production of oil or gas is disclosed, wherein the wellbore has been drilled with an invert emulsion drilling mud that forms an invert emulsion filter cake. The method may include the steps of circulating a breaker fluid into the wellbore, where the breaker fluid includes an aqueous fluid, a water soluble polar organic solvent, a hydrolysable ester of a carboxylic acid, and a weighting age, and where the hydrolysable ester is selected so that upon hydrolysis an organic acid is released and the invert emulsion of the filter cake breaks. 1. A method of cleaning a wellbore , wherein the wellbore has been drilled with an invert emulsion drilling mud that forms an invert emulsion filter cake , the method comprising; an aqueous fluid;', 'a water soluble polar organic solvent;', 'a hydrolysable ester of formic acid; and', 'a weighting agent; and, 'circulating a breaker fluid into the wellbore, the breaker fluid comprisingwherein the hydrolysable ester is selected so that upon hydrolysis formic acid is released and the invert emulsion of the filter cake breaks.2. The method of claim 1 , wherein the water soluble polar organic solvent is a glycol or glycol ether.3. The method of claim 2 , wherein the water soluble polar organic solvent is ethylene glycol mono-butyl ether.4. The method of claim 1 , wherein the hydrolysable ester of formic acid is a formic acid ester of a C4 to C30 alcohol.5. The method of claim 1 , wherein the weighting agent comprises at least one of halide and formate salts of alkali and alkaline earth metals.6. The method of claim 1 , further comprising:displacing the aqueous fluid from the wellbore.7. The method of claim 1 , further comprising:removing the broken invert emulsion filter cake from the wellbore.8. (canceled)9. (canceled)10. (canceled)11. (canceled)12. (canceled)13. (canceled)14. (canceled)15. (canceled)16. (canceled)17. A solution claim 1 , comprising:an aqueous fluid;a water soluble polar organic ...

RESERVOIR WELLBORE 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. 1. An oil-based wellbore fluid , comprising:an oleaginous liquid;a surface-modified precipitated silica, wherein the surface-modified precipitated silica comprises a lipophilic coating.2. The fluid of claim 1 , wherein the lipophilic coating comprises at least one of a polysiloxane claim 1 , an aminoalkylsilane claim 1 , and an alkoxyorganomercaptosilane.3. The fluid of claim 1 , wherein the surface modified precipitated silica has an average particle size (D) of less than 100 microns.4. The fluid of claim 1 , wherein the oleaginous liquid comprises at least one of a diesel oil claim 1 , a mineral oil claim 1 , and a synthetic oil.5. The fluid of claim 1 , wherein the fluid has a density of less than about 9.0 lb/gal.6. The fluid of claim 1 , wherein the precipitated silica is present in an amount ranging from about 10 ppb to about 25 ppb claim 1 , based on a total volume of the fluid.7. The fluid of claim 1 , further comprising at least one of an organoclay claim 1 , a wetting agent claim 1 , and a water-absorbing polymer.8. The fluid of claim 1 , wherein the organoclay is present in an amount ranging from about 4 ppb to about 8 ppb claim 1 , based on a total volume of the fluid.9. The fluid of claim 1 , further comprising at least one of drilled solids claim 1 , a gravel packing material claim 1 , a fluid loss control agent claim 1 , and a micronized weighting agent.10. The fluid of claim 1 , wherein the fluid ...

USE OF CUTTINGS VESSEL FOR TANK CLEANING

A tank cleaning system for use at a drilling location, including a first cuttings storage vessel comprising an inlet and an outlet, at least one tank cleaning machine configured to clean a tank, a disposal vessel, and a module including a pump configured to facilitate the transfer of fluids from a clean water vessel to the at least one tank cleaning machine, and a fluid connection configured to facilitate the transfer of fluids from the outlet of the first cuttings storage vessel to the disposal vessel. 1. A tank cleaning system comprising:a tank;at least one tank cleaning machine configured to clean the tank;a water recycling unit comprising a water recovery tank;a first pump configured to transfer a tank slop from inside the tank to the water recycling unit;a disposal vessel; anda separator in fluid communication with the water recovery tank, the separator configured to separate the tank slop into a solids-lean fraction and a solids-rich fraction,wherein the solids-rich fraction is directed to the disposal vessel, and the solids-lean fraction is directed to the tank.2. The tank cleaning system of claim 1 , wherein the first pump is located downstream of the tank and upstream of the water recycling unit.3. The tank cleaning system of claim 1 , further comprising a second pump configured to transfer the solids-lean fraction from the water recycling unit to the tank.4. The tank cleaning system of claim 3 , wherein the second pump is located downstream of the water recycling unit and upstream of the tank.5. The tank cleaning system of claim 3 , further comprising a power unit coupled to at least one of the first pump and the second pump.6. A tank cleaning system comprising:a tank;a tank cleaning machine disposed in the tank;a first pump disposed between the tank and a water recycling unit, the water recycling unit comprising a water recovery tank;a separator disposed in the water recycling unit, the separator configured to direct a solids-lean fraction to the tank ...

BREAKER FLUID

A breaker fluid composition and methods for using said breaker fluid composition are provided, where the breaker fluid includes a non-aqueous base fluid, a precipitated silica, an acid source, and, in some embodiments, a chelant. 1. A method of cleaning a wellbore , the method comprising: an oleaginous base fluid,', 'a precipitated silica, and', 'at least one of an acid source and a chelant; and, 'emplacing a breaker fluid into the wellbore proximate a filter cake, the breaker fluid comprisingshutting in the well for a period of time.2. A method for completing a wellbore , comprising:drilling the wellbore with a drilling fluid and forming a filtercake on the walls thereof;gravel packing at least one interval of the wellbore; an oleaginous base fluid;', 'a precipitated silica; and', 'at least one of an acid source and a chelant., 'emplacing a breaker fluid into the wellbore, the breaker fluid comprising3. The method of claim 3 , wherein the breaker fluid comprises both an acid source and a chelant.4. The method of claim 3 , wherein the oleaginous fluid comprises at least one selected from diesel oil claim 3 , a mixture of diesel and paraffin oil claim 3 , mineral oil claim 3 , and isomerized olefins.5. The method of claim 3 , wherein the average particle diameter of the precipitated silica is less than 50 μm.6. The method of claim 3 , wherein the precipitated silica is a surface-modified precipitated silica comprising a lipophilic coating.7. The method of claim 6 , wherein the lipophilic coating comprises at least one of a polysiloxane claim 6 , an aminoalkylsilane claim 6 , and an alkoxyorganomercaptosilane.8. The method of claim 3 , wherein the breaker fluid further comprises a micronized weighting agent.9. The method of claim 3 , wherein the breaker fluid is an all-oil breaker fluid essentially free of free water prior to emplacement in the wellbore.10. The method of claim 3 , wherein the breaker fluid further comprises water.11. The method of claim 3 , further ...

DEMISTER FOR CAPTURING MOIST FINE PARTICULATES

An apparatus is disclosed including an encasement defining a gas inlet to receive a gas stream and a gas outlet to release the gas stream. The apparatus further includes a vertical baffle attached to an encasement top within the encasement, the vertical baffle in contact with at least one horizontal baffle, the baffles separating the encasement into at least one chamber. The gas stream passes through the at least one chamber through perforations on the at least one horizontal baffle, and particulates from the gas stream are deposited on the encasement or the baffles. 1. An apparatus comprising:an encasement defining a gas inlet to receive a gas stream and a gas outlet to release the gas stream; anda vertical baffle attached to an encasement top within the encasement, the vertical baffle in contact with at least one horizontal baffle, the baffles separating the encasement into at least one chamber,wherein the gas stream passes through the at least one chamber through perforations on the at least one horizontal baffle, andwherein particulates from the gas stream are deposited on the encasement or the baffles.2. The apparatus of further comprising:a vacuum device in fluid communication with the gas outlet, the vacuum device providing a negative pressure to the encasement.3. The apparatus of claim 1 , wherein the vertical baffle separates the encasement into an encasement left side and an encasement right side claim 1 , the vertical baffle terminating at a vertical baffle lower edge disposed to deflect the gas stream downward toward an encasement bottom.4. The apparatus of claim 1 , wherein the vertical baffle has a continuous surface.5. The apparatus of claim 1 , wherein the encasement defines an atmospheric inlet to receive incoming air.6. The apparatus of claim 1 , wherein the at least one horizontal baffle defines a notch to engage with the vertical baffle.7. A method comprising:providing an encasement comprising a vertical baffle in contact with at least one ...

APPARATUS AND METHOD TO MEASURE A PROPERTY OF WELLBORE FLUID

A method includes disposing an open end of a housing in a wellbore fluid, flowing the wellbore fluid into the housing though the open end, rotating an impeller disposed within the housing at a first rotational speed with a motor coupled to the impeller, and determining at least one of viscosity and rheology of the wellbore fluid based on the rotating an impeller. An apparatus includes a housing, a mechanical agitator disposed in the housing, a motor operatively coupled to the mechanical agitator, a first sensor coupled to at least one of the mechanical agitator and the motor, and a second sensor disposed in the housing and configured to measure a fluid property or characteristic. 1. A method comprising:disposing an open end of a housing in a wellbore fluid;flowing the wellbore fluid into the housing through the open end;rotating an impeller disposed within the housing at a first rotational speed with a motor coupled to the impeller; anddetermining at least one of viscosity and rheology of the wellbore fluid based on the rotating the impeller.2. The method of claim 1 , wherein the determining at least one of viscosity and rheology of the wellbore fluid based on the rotating the impeller comprises:measuring power usage of the motor to rotate the impeller at the first rotational speed; anddetermining at least one of viscosity and rheology of the wellbore fluid based on the power usage measured at the first rotational speed.3. The method of claim 2 , further comprising:determining a torque applied to the motor through the impeller based on the power usage measured at the first rotational speed;determining a shear stress applied on the impeller by the wellbore fluid based on the applied torque determined at the first rotational speed; anddetermining the at least one of the viscosity and the rheology of the wellbore fluid based on the applied shear stress determined at the first rotational speed.4. The method of claim 1 , further comprising:rotating the impeller at a ...

ENCAPSULATED POLYMERS AND SELECTIVE ACTIVATION THEREOF

Wellbore strengthening compositions and methods of use are disclosed herein, where the wellbore strengthening compositions may include a base fluid and a plurality of hydrogel particles or a plurality of core-shell particles suspended in the base fluid. A method of treating a formation may include pumping a wellbore fluid into the formation, where the wellbore fluid includes a base fluid; and a plurality of hydrogel particles or a plurality of core-shell particles suspended in the base fluid. 1. A wellbore fluid comprising:a base fluid; anda plurality of hydrogel particles or a plurality of core-shell particles suspended in the base fluid.2. The wellbore fluid of claim 1 , wherein the base fluid is an oil-based fluid claim 1 , an aqueous-based fluid or an emulsion thereof.3. The wellbore fluid of claim 1 , wherein the plurality of hydrogel particles or the plurality of core-shell particles are formed from at least a monomer selected from the group of acrylates and acrylate derivatives.4. The wellbore fluid of claim 3 , wherein the plurality of core-shell particles further comprise an organic solvent.5. The wellbore fluid of claim 4 , wherein the organic solvent is hexadecane.6. The wellbore fluid of claim 3 , wherein the plurality of hydrogel particles or the plurality of core-shell particles encapsulate a water soluble material.7. The wellbore fluid of claim 6 , wherein the water soluble material is selected from the group of polyether amines claim 6 , free water claim 6 , organic acids and inorganic salts.8. The wellbore fluid of claim 3 , wherein the plurality of hydrogel particles have an average size ranging from about 15 to about 85 microns.9. The wellbore fluid of claim 3 , wherein the plurality of core-shell particles have an average size ranging from about 15 microns to about 130 microns.10. The wellbore fluid of claim 6 , wherein the encapsulated water soluble material is released by subjecting the plurality of hydrogel particles or the plurality of core- ...

EMULSIFIERS FOR WELLBORE STRENGTHENING

Methods may include drilling at least a section of a wellbore using an invert emulsion wellbore fluid, where the invert emulsion wellbore fluid may contain an emulsifier, a first wellbore strengthening material (WBS)-forming component, and a second WBS-forming component; and increasing the shear experienced at the bit. 1. A method comprising: an emulsifier; and', 'a first wellbore strengthening material (WBS)-forming component and a second WBS-forming component; and, 'drilling at least a section of a wellbore using an invert emulsion wellbore fluid comprisingupon experience of a fluid loss, increasing the shear experienced at the bit.2. The method of claim 1 , further comprising resuming drilling operations after the formed WBS reduces fluid loss.3. The method of claim 1 , wherein the invert emulsion wellbore fluid has about 1.5 to 15 ppb emulsifier.4. The method of claim 1 , wherein the first WBS-forming component and the second WBS-forming component are in separate phases of the invert emulsion wellbore fluid.5. The method of claim 1 , wherein increasing the shear experienced at the bit comprises injecting a fluid through a nozzle present on a drill bit and/or drill string.6. The method of claim 1 , wherein the increase in the shear experienced at the bit is enough to break the invert emulsion wellbore fluid.7. The method of claim 1 , wherein the shear is increased to at least about 20 claim 1 ,000 s.8. The method of claim 1 , wherein the shear is increased to at least about 25 claim 1 ,000 s.9. The method of claim 1 , wherein the first WBS-forming component is one or more silicates claim 1 , and the second WBS-forming component is at least one of an alcohol claim 1 , polyol claim 1 , amine claim 1 , or polyamine.10. The method of claim 1 , wherein the formed WBS is an alcohol crosslinked silicate.11. An invert emulsion fluid system comprising:a continuous phase comprising a first base fluid and a first WBS-forming component; anda discontinuous phase comprising a ...

SELF-CLEANING, ANTI-SMOG, ANTI-MOULD PHOTOCATALYTIC POWDERED WATER BASED PAINT

A photocatalytic powdered water based paint is described comprising photocatalytic binding cement, inert micronized limestone, low viscosity cellulose, fluidifying agent, anti-foaming agent, vinyl polymer and pigments. The water based paint is characterized by the fact of comprising at least one and preferably all the following further additives: metakaolin, titanium dioxide, calcium formate and kieselguhr. 1. Photocatalytic powdered paint for use diluted in water , comprising Portland cement admixed with nanoparticle photocatalytic Titanium Dioxide , the size of said Titanium Dioxide nanoparticles being lower than 5 nanometers; inert limestone with a maximum grain-size distribution lower than 100 microns; cellulose with viscosity lower than 1 ,000 mPas; fluidizer; antifoam; vinyl polymer and pigments , comprising at least one and preferably all the following further additives: metakaolin , calcium formate and kieselguhr.3. Paint according to claim 2 , wherein said pigments are coated with a cellulose-based film that claim 2 , when comes in contact with water claim 2 , dissolves releasing the pigment claim 2 , said film preferably dissolving in a time lower than 2 seconds and more preferably in less than 1 second.4. Paint according to claim 3 , wherein said pigments are formed into granules whose dimensions have a grain-size range from 200 to 500 microns.6. Paint obtained with the method according to . The present invention relates to a photocatalytic powdered water based paint, i.e. a powdered compound that becomes a water based paint once diluted in water, that has considerable advantageous characteristics in addition to its main property of converting pollutants present in the air by photocatalysis, it being also able to remove bad smells, to prevent mould and bacterial cultures from developing on the supports painted therewith, as well as to prevent dark marks from developing on the surfaces because of its self-cleaning function and to prevent heat from being ...

METHODS OF DRILLING WITH RESISTIVITY TOOLS

A method of electrically logging a section of a wellbore includes circulating an oil-based wellbore fluid comprising a conductive carbon material therein, the oil-based wellbore fluid having a conductivity of at most 0.01 S/m when measured at 20 kHz, within the wellbore while drilling the wellbore with a drill bit on a drill string; applying electrical current from a logging tool on the drill string above the drill bit; and collecting an electrical log of the portion of the wellbore that has had electrical current applied thereto. 1. A method of electrically logging a section of a wellbore , comprising:circulating an oil-based wellbore fluid comprising a conductive carbon material therein, the oil-based wellbore fluid having a conductivity of at most 0.01 S/m when measured at 20 kHz, within the wellbore while drilling the wellbore with a drill bit on a drill string;applying electrical current from a logging tool on the drill string above the drill bit; andcollecting an electrical log of the portion of the wellbore that has had electrical current applied thereto.2. The method of claim 1 , wherein the electrical current is applied continuously as the wellbore is drilled by the drill bit.3. The method of claim 1 , further comprising:transmitting the electrical log to the surface.4. The method of claim 1 , wherein the electrical current is applied from the logging tool by at least one electrode thereon.5. The method of claim 1 , wherein the oil-based wellbore fluid has a surface area loading factor of at least 2000 lbm/gbbl.6. The method of claim 1 , wherein the carbon material is a carbon black that has spheroidal primary particles from about 5 nm to about 150 nm in diameter.7. The method of claim 1 , wherein the carbon material is a carbon black wherein a circumscribing sphere encompassing a carbon black aggregate has a diameter from about 60 nanometers to 3 micrometers.8. The method of claim 1 , wherein the carbon material is a carbon black having a pore volume of at ...

BRANCHED ACID EMULSIFIER COMPOSITIONS AND METHODS OF USE

Compositions may contain an oleaginous base fluid, and a branched amidoamine surfactant prepared from the reaction of an alkylene amine or an oligoalkylene amine and a branched acid having a C4 to C24 primary hydrocarbon chain, and having one or more C1 to C24 branches. Methods may include emplacing a wellbore fluid into a wellbore, wherein the wellbore fluid contains an oleaginous base fluid; and a branched amidoamine surfactant prepared from the reaction of an alkylene amine or an oligoalkylene amine and a branched acid having a C4 to C24 primary hydrocarbon chain, and having one or more C1 to C24 branches. 1. A composition comprising:an oleaginous base fluid; anda branched amidoamine surfactant having at least one C1 to C24 branch, the surfactant prepared from reaction of an all amine or an oligoalkylene amine and a branched acid having a C4 to C24 primary hydrocarbon chain.3. The composition of claim 2 , wherein Rof the branched amidoamine surfactant is of the formula: —(CH)C(R)(R)(R) claim 2 , where Ris hydrogen or a C1 to C24 alkyl claim 2 , Rand Rare C1 to C24 alkyl chains extending from the branching carbon claim 2 , where the alkyl chains may be the same carbon length or different claim 2 , and x is an integer between 0 and 6.4. The composition of claim 3 , wherein Rand Rcontain the same number of carbons.5. The composition of claim 1 , further comprising an aqueous internal phase.6. The composition of claim 5 , wherein the oleaginous base fluid forms an oleaginous external phase claim 5 , and wherein the composition has a ratio of the aqueous internal phase to the oleaginous external phase with the range of 30:70 to 95:5.7. The composition of claim 1 , wherein the branched amidoamine surfactant is prepared from a branched acid selected from a group consisting of 2-butyloctanoic acid claim 1 , 2 claim 1 ,2-dimethyloctanoic acid claim 1 , 2 claim 1 ,2-ethylmethlyheptanoic acid claim 1 , 2 claim 1 ,2-methyl-sec-butylbutanoic acid claim 1 , 2 claim 1 ,2- ...

CROSSLINKED SYNTHETIC POLYMER-BASED RESERVOIR DRILLING FLUID

A wellbore fluid includes a base fluid; and a crosslinked and branched polymeric fluid loss control agent formed from at least an acrylamide monomer and a sulfonated anionic monomer; wherein the fluid loss control agent has an extent of crosslinking that is selected so that the fluid loss control agent has a viscosity that is within a peak viscosity response of the viscosity response curve. 1. A wellbore fluid , comprising:a base fluid; anda crosslinked and branched polymeric fluid loss control agent formed from at least an acrylamide monomer and a sulfonated anionic monomer;wherein the fluid loss control agent has an extent of crosslinking that is selected so that the fluid loss control agent has a viscosity that is within a peak viscosity response of the viscosity response curve.2. The wellbore fluid of claim 1 , wherein the acrylamide monomer is at least one selected from unsubstituted acrylamide claim 1 , alkylacrylamides claim 1 , N-methylol acrylamide claim 1 , N-isopropyl acrylamide claim 1 , diacetone-acrylamide claim 1 , N-alkyl acrylamide claim 1 , where alkyl is Cto C claim 1 , N claim 1 ,N-dialkyl acrylamides claim 1 , where alkyl is Cto C claim 1 , N-cycloalkane acrylamides.3. The wellbore fluid of claim 1 , wherein the sulfonated anionic monomer is selected from 2-acrylamide-2-methyl-propanesulfonic acid claim 1 , vinyl sulfonate claim 1 , and styrene sulfonic acid.4. The wellbore fluid of claim 1 , wherein the fluid loss control agent contains covalent intermolecular crosslinking.5. The wellbore fluid of claim 1 , wherein the wellbore fluid exhibits temperature stability up to 300° F.6. The wellbore fluid of claim 1 , wherein the wellbore fluid exhibits low end rheology that does not deviate by more than 30 percent under a temperature up to 300° F. when compared to low end rheology of the fluid at temperatures below about 250° F.7. The wellbore fluid of claim 1 , wherein after aging the wellbore fluid for at least 5 days at a temperature of at least ...

BREAKER FLUIDS AND METHODS OF USE THEREOF

A method may include circulating a breaker fluid into a wellbore having a filtercake on the walls thereon, the filter cake including copolymer formed from at least one acrylamide monomer and at least one sulfonated anionic monomer, the breaker fluid comprising: a base fluid; and a mixture of hydrolysable esters of dicarboxylic acids. 1. A method of breaking a filtercake in a wellbore , comprising: a base fluid; and', 'a mixture of hydrolysable esters of dicarboxylic acids., 'circulating a breaker fluid into the wellbore having a filtercake on the walls thereon, the filter cake including copolymer formed from at least one acrylamide monomer and at least one sulfonated anionic monomer, the breaker fluid comprising2. The method of claim 1 , the breaker fluid further comprising lactide.3. The method of claim 1 , wherein the acrylamide monomer is at least one selected from unsubstituted acrylamide claim 1 , alkylacrylamides claim 1 , N-methylol acrylamide claim 1 , N-isopropyl acrylamide claim 1 , diacetone-acrylamide claim 1 , N-alkyl acrylamide claim 1 , where alkyl is Cto C claim 1 , N claim 1 ,N-dialkyl acrylamides claim 1 , where alkyl is Cto C claim 1 , N-cycloalkane acrylamides.4. The method of claim 1 , wherein the sulfonated anionic monomer is selected from 2-acrylamide-2-methyl-propanesulfonic acid claim 1 , vinyl sulfonate claim 1 , and styrene sulfonic acid.5. The method of claim 1 , wherein the copolymer contains covalent intermolecular crosslinking.6. The method of claim 1 , wherein the mixture of hydrolysable esters of dicarboxylic acids includes about 57-67 wt. % dimethyl glutarate claim 1 , 18-28 wt. % dimethyl succinate claim 1 , and 8.-22 wt. % dimethyl adipate.7. The method of claim 2 , wherein relative to the total amount of lactide and the mixture of hydrolyzable esters of dicarboxylic acid esters in the breaker fluid claim 2 , the mixture of dicarboxylic acid esters forms about 10-99 wt. % claim 2 , and lactide forms about 1 to 90 wt. %.8. The ...

METHODS OF LOGGING

A method of electrically logging a section of a wellbore includes circulating a wellbore fluid within the wellbore, the wellbore fluid including a base fluid; and a crosslinked and branched polymeric fluid loss control agent formed from at least an acrylamide monomer and a sulfonated anionic monomer; wherein the fluid loss control agent has an extent of crosslinking that is selected so that the fluid loss control agent has a viscosity that is within a peak viscosity response of the viscosity response curve; placing within the wellbore a wellbore logging tool capable of applying an electrical current to the wellbore; applying electrical current from the logging tool; and collecting an electrical log of the portion of the wellbore that has had electrical current applied thereto. 1. A method of electrically logging a section of a wellbore , comprising: a base fluid; and', 'a crosslinked and branched polymeric fluid loss control agent formed from at least an acrylamide monomer and a sulfonated anionic monomer;', 'wherein the fluid loss control agent has an extent of crosslinking that is selected so that the fluid loss control agent has a viscosity that is within a peak viscosity response of the viscosity response curve;, 'circulating a wellbore fluid within the wellbore, the wellbore fluid comprisingplacing within the wellbore a wellbore logging tool capable of applying an electrical current to the wellbore;applying electrical current from the logging tool; andcollecting an electrical log of the portion of the wellbore that has had electrical current applied thereto.2. The method of claim 1 , further comprising:moving the wellbore logging tool within the wellbore while continuously applying electrical current and collecting an electrical log.3. The method of claim 1 , further comprising:transmitting the electrical log to the surface.4. The method of claim 1 , wherein the acrylamide monomer is at least one selected from unsubstituted acrylamide claim 1 , alkylacrylamides ...

FILTER CAKE DRAG TESTER

A method that includes pulling a sled disposed on a trough across a first filtercake at a constant speed, measuring a force versus distance or time based on the pulling; and outputting a frictional force curve is described. An apparatus that includes a base, a pulley attached to the base, a trough attached to the base, a sled disposed on the trough, a cable connecting the pulley and the sled, the cable connected to an arm capable of being moved at a constant speed, and a system to measure the force required to move the sled is also described. 1. A method comprising:pulling a sled disposed on a trough across a first filtercake at a constant speed;measuring a force versus distance or time based on the pulling; andoutputting a frictional force curve.2. The method of claim 1 , further comprising:repeating the pulling, measuring, and outputting with at least one other filtercake.3. The method of claim 2 , wherein the repeating occurs until an optimized force versus distance curve is output.4. The method of claim 1 , further comprising:modifying the filtercake by increasing the thickness of the filtercake.5. The method of claim 2 , wherein the at least one other filtercake comes from a fluid having a different composition than the first filtercake.6. The method of claim 1 , further comprising:modifying a property of the sled or the trough, wherein the property comprises at least one selected from the group consisting of surface roughness, shape, length, diameter, weight, and a material that the sled or the trough is formed from.7. A method comprising:pulling a sled across a first filtercake at a constant speed;measuring a force versus distance or time;outputting a first frictional force curve;creating a second filtercake;pulling a sled across the second filtercake;measuring a force versus distance or time;outputting a second frictional force curve;comparing the first frictional force curve and the second frictional force curve; andselecting a drilling fluid based on the ...

SEPARATOR AND METHOD OF SEPARATION WITH AN AUTOMATED PRESSURE DIFFERENTIAL DEVICE

Systems, separators and methods separate one or more solids from a fluid and utilize an automated pressure differential device to improve separation of the one or more solids and the fluid. The systems and methods comprise at least a pressure differential system adjacent a screen in a shaker for separating one or more solids from a fluid, the pressure differential system adapted to provide a pressure differential adjacent the screen in the shaker, a monitoring tool coupled to an actuated arm adjacent the shaker, the monitoring tool adapted to monitor the one or more solids and the fluid adjacent the screen in the shaker, and a controller in electrical communication with the pressure differential system, the monitoring tool and the actuated arm, wherein the controller adapted to control the pressure differential based on the monitoring of the one or more solids and the fluid adjacent the screen of the shaker. 1. A method , comprising:monitoring, using a monitoring tool or actuated arm coupled to the monitoring tool, fluid containing one or more solids located adjacent to a discharge end of a shaker for separating the one or more solids from the fluid;determining at least one property selected from at least one fluid property and at least one solids property, wherein the at least one fluid property comprises an amount of the fluid on the one or more solids and the at least one solids property comprises an amount of the one or more solids present in the fluid; andcontrolling, via a controller, a pressure differential system adjust to a screen in the shaker based at least in part on the determined at least one property, wherein the controller is in electrical communication with the actuated arm, the monitoring tool, and the pressure differential system.2. The method according to claim 1 , wherein controlling the pressure differential system includes:changing application of at least one pressure differential by the pressure differential system at or near the screen in ...

DISINFECTING WATER USED IN A FRACTURING OPERATION

A process for disinfecting a treatment fluid is disclosed, including the step of admixing an aqueous solution comprising two or more oxidants generated via electrolysis of a salt solution with a treatment fluid. The mixed oxidants may be generated on site, using a containerized system. 1. A process for disinfecting a treatment fluid , comprising:admixing an aqueous solution comprising two or more oxidants generated via electrolysis of a salt solution with a treatment fluid or treatment fluid precursor.2. The process of claim 1 , further comprising at least one of:disposing a quantity of one or more salts in a tank;transporting the tank containing the disposed quantity of one or more salts to a well site to be serviced;receiving water from a water supply;treating the water received in a water treatment system to form a conditioned water stream, wherein the treating comprises at least one of filtering, softening, heating, and cooling;admixing the one or more salts and the water to form the salt solution, wherein the water may be a first portion of the conditioned water stream;combining the salt solution with additional water to form a diluted salt solution, wherein the additional water may be a second portion of the conditioned water stream;converting the salt solution to an aqueous solution comprising the two or more oxidants via electrolysis in one or more electrolytic oxidant producing units.3. The process of or claim 1 , wherein the one or more salts comprise at least one of an alkali metal halide claim 1 , an alkaline earth metal halide claim 1 , and a transition metal halide claim 1 , and wherein the two or more mixed oxidants comprise two or more of ozone claim 1 , hydrogen peroxide claim 1 , hypochlorite claim 1 , hypochlorous acid claim 1 , chlorine dioxide claim 1 , hypobromous acid claim 1 , bromine claim 1 , and chlorine.43. The process of any one of - claims 1 , further comprising measuring at least one of a residual oxidant content claims 1 , a pH claims ...

Internal Breaker for Water-Based Fluid and Fluid Loss Control Pill

A method comprising degrading a filtercake with a breaker comprising a urea-based polymer is provided. Also, a breaker composition is provided which includes a urea-based polymer that can hydrolyze in the presence of water and heat to release water-soluble byproducts and intermediates. 1. A method comprising:degrading a filtercake formed within a formation with a breaker comprising a urea-based polymer.2. The method of claim 1 , wherein the urea-based polymer is a hydrolyzable urea-aldehyde.3. The method of claim 1 , wherein the urea-based polymer is selected from a urea claim 1 , a urea-formaldehyde claim 1 , a urea-isobutyraldehyde claim 1 , a urea-crotonaldehyde claim 1 , a polyurea claim 1 , a urea-formaldehyde claim 1 , a poly(urea-isobutyraldehyde) claim 1 , a poly(urea-crotonaldehyde) claim 1 , a urea-isobutyraldehyde-formaldehyde claim 1 , copolymers of urea with other aldehydes claim 1 , and a mixture thereof.4. The method of claim 1 , wherein the filtercake comprises a urea-based polymer.5. The method of claim 4 , wherein the urea-based polymer is a urea-aldehyde.6. The method of claim 4 , wherein degrading the filtercake comprises hydrolyzing the urea-based polymer of the filtercake.7. The method of claim 1 , wherein the filtercake comprises sized urea-aldehyde particles as bridging materials.8. The method of claim 1 , wherein the breaker further comprises a hydrolyzable polyester.9. The method of claim 8 , wherein the hydrolyzable polyester is selected from a lactide claim 8 , a glycolide claim 8 , a polylactic acid (PLA) claim 8 , a polyglycolic acid (PGA) claim 8 , a copolymer of PLA and PGA claim 8 , a copolymer of glycolic acid with other hydroxy- claim 8 , carboxylic acid- claim 8 , or hydroxycarboxylic acid-containing moieties claim 8 , a copolymer of lactic acid with other hydroxy- claim 8 , carboxylic acid claim 8 , or hydroxycarboxylic acid-containing moieties claim 8 , and a mixture thereof.10. A breaker composition comprising:a urea-based ...

WELLBORE STRENGTHENING COMPOSITION

In one aspect, embodiments disclosed herein relate to a wellbore strengthening composition including at least one polymer capable of polymerizing through a free radical polymerization reaction from the group of epoxy acrylates, modified epoxy acrylates, epoxy precursors, modified epoxy vinyl esters, unsaturated polyesters, urethane (meth)acrylates, polyester acrylates, epoxy vinyl ester resins having the wherein R and R-Rmay be CH— or H and R-Rmay be H or Br, and polymer combinations thereof; and at least one initiator, wherein the resin is present in the amount from about 10 to about 90 weight percent. 112.-. (canceled)14. The method of claim 13 , wherein the initiator is selected from the group consisting of benzoyl peroxide claim 13 , dibenzoyl peroxide claim 13 , diacetyl peroxide claim 13 , di-t-butyl peroxide claim 13 , cumyl peroxide claim 13 , dicumyl peroxide claim 13 , dilauryl peroxide claim 13 , t-butyl hydroperoxide claim 13 , methyl ketone peroxide claim 13 , acetylacetone peroxide claim 13 , methylethyl ketone peroxide claim 13 , dibutylperoxyl cyclohexane claim 13 , di (2 claim 13 ,4-dichlorobenzoyl) peroxide claim 13 , diisobutyl peroxide claim 13 , t-butyl perbenzoate claim 13 , t-butyl peracetate claim 13 , and combinations thereof.15. The method of claim 13 , further comprising:introducing at least a monomer from the group of hydroxyethyl methacrylate (HEMA), hydroxypropyl methacrylate (HPMA), acrylic acid, methacrylic acid, methyl acrylate, ethyl acrylate, propyl acrylate, butyl acrylate, isodecyl acrylate, stearyl acrylate, lauryl acrylate, tridecyl acrylate, isoctyl acrylate, ethyoxylated bisphenol A diacrylate, ethoxylated hydroxyethyl acrylate, allyl acrylate, glycidyl methacrylate, 1,4-butanediol diacrylate (BDDA), 1,6-hexanediol diacrylate (HDDA), diethylene glycol diacrylate, 1,3-butylene glycol diacrylate, neopentyl glycol diacrylate, cyclohexane dimethanol diacrylate, dipropylene glycol diacrylate, ethoxylated bisphenol A diacrylate, ...

USE OF CHELANTS IN FORMATE-BASED SOLUTIONS TO DISSOLVE RESIDUAL FILTERCAKES IN SUBTERRANEAN WELLS

A wellbore fluid for dissolving a filtercake includes a chelating agent and an aqueous solution of carboxylate salt. The concentration of the chelating agent is up to 50 percent volume per volume (v/v) in the aqueous solution of carboxylate salt. A method of treating a well includes preparing a wellbore fluid up to 50 percent volume per volume (v/v) chelating agent in an aqueous solution of carboxylate salt. The method further includes emplacing the wellbore fluid downhole such that the wellbore fluid dissolves a filtercake in the well. 1. A wellbore fluid for dissolving a filtercake , the fluid comprising:a chelating agent; andan aqueous solution of carboxylate salt, wherein concentration of the chelating agent is up to 50 percent volume per volume (v/v) in the aqueous solution of carboxylate salt.2. The fluid of claim 1 , wherein the chelating agent is in an amount from 41 to 50 percent by weight.3. The fluid of claim 1 , wherein the carboxylate salt comprises at least one of a cesium formate claim 1 , a potassium formate claim 1 , and a sodium formate.4. The fluid of claim 3 , wherein the potassium formate has a specific gravity of about 1.57.5. The fluid of claim 3 , wherein the cesium formate has a specific gravity of about 2.3.6. The fluid of claim 1 , wherein the chelating agent includes at least one of EDTA claim 1 , GLDA claim 1 , HEDTA claim 1 , DTPA claim 1 , NTA claim 1 , BAPTA claim 1 , CDTA claim 1 , and TTHA.7. The fluid of claim 1 , wherein the chelating agent is from 50 to 80 percent volume per volume (v/v) in the aqueous solution of carboxylate salt.8. A method of treating a well claim 1 , the method comprising:preparing a wellbore fluid up to 50 percent volume per volume (v/v) chelating agent in an aqueous solution of carboxylate salt; andemplacing the wellbore fluid downhole such that the wellbore fluid dissolves a filtercake in the well.9. The method of claim 8 , wherein the chelating agent is in an amount from 41 to 50 percent by weight.10. The ...

HOT SWAPPABLE CHOKE ACTUATOR SYSTEM AND/OR METHOD

A system having a choke assembly with a mandrel extending therefrom, an actuator with an actuator member extending therefrom, and a spool having a bore therethrough configured to provide a passage for the mandrel and the actuator member. The spool further includes a first end configured to be coupled to the choke assembly, a second end configured to be coupled to the actuator; and an access port formed in a wall of the spool. The system also includes a locking device configured to couple the mandrel to the actuator member within the bore of the spool. The access port is configured to receive the locking device. 1. An apparatus comprising:a spool configured to couple a choke assembly to an actuator, the spool comprising:an access port extending from an outer surface of the spool to an inner surface of the spool; anda locking device configured to couple a mandrel of the choke assembly to an actuator member of the actuator.2. The apparatus of claim 1 , further comprising a first flange disposed proximate a first end of the spool coupled to the choke assembly and a second flange disposed proximate an opposite end of the spool coupled to the actuator.3. The apparatus of claim 2 , wherein the first flange is removably coupled to the choke assembly and the second flange is removably coupled to the actuator.4. The apparatus of claim 1 , wherein the spool further comprises a longitudinal bore providing a passage for the mandrel and the actuator member.5. The apparatus of claim 1 , wherein the mandrel comprises a first transverse locking bore and the actuator comprises a second transverse locking bore.6. The apparatus of claim 5 , wherein the first transverse locking bore is aligned with the second transverse locking bore to provide a passage through the mandrel and the actuator member for the locking device.7. The apparatus of claim 6 , the spool further comprising an access port configured to receive the locking device claim 6 , the access port configured to provide a ...

ADDITIVE TO IMPROVE COLD TEMPERATURE PROPERTIES IN OIL-BASED FLUIDS

An additive composition includes a rheology modifier selected from alcohol ethoxylates, amine ethoxylates, or ethylene oxide/propylene oxide copolymers, wherein the rheology modifier has an HLB ranging from about 4 to 10; and a winterizing agent that is at least one aliphatic non-ionic surfactant that has a branched structure and/or includes at least one unsaturation, wherein the winterizing agent has an HLB value between about 8 and 10.5. 1. An additive composition , comprising:a rheology modifier selected from alcohol ethoxylates, amine ethoxylates, or ethylene oxide/propylene oxide copolymers, wherein the rheology modifier has an HLB ranging from about 4 to 10; anda winterizing agent that is at least one aliphatic non-ionic surfactant that has a branched structure and/or includes at least one unsaturation, wherein the winterizing agent has an HLB value between about 8 and 10.5.2. The additive composition of claim 1 , wherein the winterizing agent has a pour point of less than about −10° C.3. The additive composition of claim 1 , wherein the rheology modifier is an alcohol ethoxylate.4. The additive composition of claim 1 , wherein the additive composition includes between about 10 wt. % and 90 wt. % of the rheology modifier and 10 wt. % and 90 wt. % of the winterizing agent.6. The additive composition of claim 1 , wherein the winterizing agent is a secondary alcohol ethoxylate.8. A method of modifying cold temperature stability of a rheology modifier claim 1 , the method comprising:combining a winterizing agent that is at least one aliphatic non-ionic surfactant that has a branched structure and/or includes at least one unsaturation with at least one rheology modifier to form a winterized composition,wherein the winterizing agent has an HLB value between about 8 and 10.5.9. The method of claim 8 , wherein the winterizing agent has a pour point of less than about −10° C.10. The method of claim 8 , wherein the rheology modifier is an alcohol ethoxylate.11. The ...

FLUIDS AND METHODS FOR MITIGATING SAG AND EXTENDING EMULSION STABILITY

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° F. of less than about 300 and a 10 minute gel strength of less than about 40 lbf/100 ft. 1. A method of drilling a wellbore , comprising: 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', {'sup': '2', '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° F. of less than about 300 and a 10 minute gel strength of less than about 40 lbf/100 ft.'}], 'pumping an oleaginous wellbore fluid into a wellbore, the oleaginous wellbore fluid comprising2. The method of claim 1 , wherein the wetting agent is present in the oleaginous wellbore fluid in an amount ranging from about 2 to 6 pounds per barrel.3. The method of claim 1 , wherein the oleaginous wellbore fluid has a 6 rpm dial value at 150° F. ranging from about 6 to 15.4. The method of claim 1 , wherein the wetting agent is selected from alcohol ethoxylates claim 1 , amine ethoxylates claim 1 , or ethylene oxide/propylene oxide copolymers.5. An oleaginous wellbore fluid comprising: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;at least one wetting agent selected from alcohol ethoxylates, amine ethoxylates, or ethylene oxide ...

ELECTRICALLY CONDUCTIVE WELLBORE FLUIDS AND METHODS OF USE

Electrically conductive oil-based wellbore fluids and methods of using same are provided. Wellbore fluids provided may contain one or more carbon nanotubes, where the one or more carbon nanotubes have a particular d/g ratio as determined by Raman spectroscopy. Also provided are methods for electrical logging of a subterranean well that include emplacing a logging medium into a subterranean well, wherein the logging medium contains a non-aqueous fluid and one or more carbon nanotubes, where the one or more carbon nanotubes are present in a concentration so as to permit the electrical logging of the subterranean well; and acquiring an electrical log the subterranean well. 1. A wellbore fluid comprising:an oil-based fluid;one or more carbon nanotubes, wherein the one or more carbon nanotubes have a d/g ratio as determined by Raman spectroscopy of 0.01 to 0.6.2. The wellbore fluid of claim 1 , wherein the one or more carbon nanotubes have at least one dimensional measurement within the range of 50 μm to 5 cm.3. The wellbore fluid of claim 1 , the composition further comprises one or more particulate carbons selected from a group consisting of graphite claim 1 , synthetic graphite claim 1 , and carbon black.4. The wellbore fluid of claim 1 , wherein the one or more carbon nanotubes comprise from about 0.0001 wt % to about 10 wt % of the wellbore fluid.5. The wellbore fluid of claim 1 , wherein the oil-based fluid is an invert emulsion.6. The wellbore fluid of claim 1 , further comprising one or more emulsifiers selected from a group consisting of carboxylic acid-based emulsifiers claim 1 , carboxylic fatty acids claim 1 , dimer acids claim 1 , and dimers of fatty acids.7. The wellbore fluid of claim 1 , further comprising one or more emulsifiers selected from amidoamines claim 1 , alkyl aromatic sulfates claim 1 , and sulfonates.8. A wellbore fluid comprising:an oil-based fluid;one or more carbon nanotubes, andone or more emulsifiers selected from a group consisting of ...

COLLOIDAL SILICA AND POLYMER SYSTEM FOR INSULATING PACKER FLUIDS

Insulating packer fluids containing colloidal silica inorganic additives may be used in methods that reduce convective currents in a packer fluid. In other aspects, packer fluids containing colloidal silica inorganic additives may be used in methods of insulating production wells and methods for stimulating production of hydrocarbons. 1. A method of reducing convective currents in a packer fluid , the method comprising: an aqueous base fluid,', 'a colloidal silica inorganic additive, and', 'a polymeric viscosifier., 'pumping a packer fluid into an annulus of a wellbore created by two concentric strings of pipe extending into the wellbore, wherein the packer fluid comprises2. The method of claim 1 , wherein the packer fluid further comprises a thermal stabilizer.3. The method of claim 1 , wherein polymeric viscosifier is a polymer claim 1 , copolymer claim 1 , or higher order copolymer containing one or more monomers selected from a group consisting of 2-acrylamido-2-methylpropanesulfonate claim 1 , acrylamide claim 1 , methacrylamide claim 1 , N claim 1 ,N dimethyl acrylamide claim 1 , N claim 1 ,N dimethyl methacrylamide claim 1 , dimethylaminopropyl methacrylamide claim 1 , N-vinyl-2-pyrrolidone claim 1 , N-vinyl-3-methyl-2-pyrrolidone claim 1 , N-vinyl-4 claim 1 ,4-diethyl-2-pyrrolidone claim 1 , 5-isobutyl-2-pyrrolidone claim 1 , N-vinyl-3-methyl-2-pyrrolidone claim 1 , alkyl oxazoline claim 1 , and 2-ethyl-2-oxazoline.4. The method of claim 3 , wherein the polymeric viscosifier is a terpolymer of 2-acrylamido-2-methylpropanesulfonate claim 3 , acrylamide claim 3 , and 2-vinylpryrrolidone.5. A method for stimulating a well claim 3 , comprising an aqueous base fluid,', 'a colloidal silica inorganic additive, and', 'a polymeric viscosifier; and, 'pumping a packer fluid into an annulus a wellbore created by two concentric strings of pipe extending into the wellbore, wherein the packer fluid comprisesinjecting hot water or steam through an interior pipe of the two ...

SHAKER AND DEGASSER COMBINATION

A system for separating components from a slurry of drilling fluid and drill cuttings on a shaker screen having an upper side and a lower side within a shaker. The system also has a pressure differential generator to pull an effective volume of air through a section of the shaker screen to enhance the flow of drilling fluid through the section of the shaker screen and the separation of drilling fluid from drill cuttings and further maintain an effective flow of drill cuttings off the shaker. A method of separating components of a slurry of drilling fluids and solids has the steps of delivering the slurry to a shaker, flowing the slurry over a first screen and applying an effective amount of vacuum to a first portion of the first screen to remove the drilling fluids from the slurry without stalling the solids on the first screen. 120.-. (canceled)21. A method comprising:introducing material to a shaker having a plurality of screens;flowing the material over the plurality of screens;collecting a liquid portion of the material passing through one of the plurality of screens with a sump; andutilizing a pressure differential device to create a pressure differential between a space above the one of the plurality of screens and the sump such that the pressure differential prevents stalling of the material on the one of the plurality of screens.22. The method of further comprising pulling air or vapor above the one of the plurality of screens through the sump to a chamber external to the shaker while maintaining the pressure differential.23. The method of wherein the material comprises a solid portion and a liquid portion claim 21 , and further wherein the pressure differential prevents stalling of the solid portion on the one of the plurality of screens.24. The method of further comprising transferring the material recovered from the one of the plurality of screens from the sump to a chamber external the shaker to separate vapor or air and liquid while maintaining the ...

SELF-CROSSLINKING POLYMERS FOR WELLBORE STRENGTHENING

Wellbore fluids, and methods of use thereof, are disclosed. Wellbore fluids may include a non-oleaginous internal phase, an oleaginous external phase, a first latex-containing copolymer comprising at least one copolymer formed from at least one natural polymer and at least one latex monomer, and a second latex polymer distinct from the first latex polymer. 1. A wellbore fluid comprising:a non-oleaginous internal phase;an oleaginous external phase;a first latex-containing copolymer comprising at least one copolymer formed from at least one natural polymer and at least one latex monomer; anda second latex polymer distinct from the first latex polymer.2. The wellbore fluid of claim 1 , further comprising at least one fiber material.3. The wellbore fluid of claim 1 , further comprising:a third latex polymer.4. The wellbore fluid of claim 3 , wherein the third latex polymer is distinct from the second latex polymer.5. The wellbore fluid of claim 4 , wherein the monomer species of the second latex polymer and third latex polymers are distinct.6. The wellbore fluid of claim 4 , wherein the stabilizer of the second latex polymer and third latex polymers are distinct.7. The wellbore fluid of claim 1 , wherein the second latex polymer is stabilized by a rosin acid soap.8. The wellbore fluid of claim 1 , wherein the at least one natural polymer is at least one of lignins claim 1 , lignitic material claim 1 , tannins claim 1 , polysaccharides claim 1 , or mixtures and derivatives thereof.9. The wellbore fluid of claim 8 , wherein the natural polymer is a polysaccharide.10. The wellbore fluid of claim 9 , wherein the at least one natural polymer is at least one of corn starch claim 9 , cellulose claim 9 , potato starch claim 9 , tapioca starch claim 9 , wheat starch or rice starch.11. The wellbore fluid of claim 1 , wherein the at least one latex monomer of the first latex polymer is at least one of styrene-butadiene copolymers claim 1 , polymethyl methacrylate claim 1 , ...

SELF-CROSSLINKING POLYMERS AND PLATELETS FOR WELLBORE STRENGTHENING

Wellbore fluids, and methods of use thereof, are disclosed. Wellbore fluids may include a non-oleaginous internal phase; an oleaginous external phase; at least one two-dimensional platelet-like material; a first latex-containing copolymer comprising at least one copolymer formed from at least one natural polymer and at least one latex monomer; and a second latex polymer distinct from the first latex polymer. 1. A wellbore fluid comprising:a non-oleaginous internal phase;an oleaginous external phase;at least one two-dimensional platelet-like material;a first latex-containing polymer comprising at least one copolymer formed from at least one natural polymer and at least one latex monomer; anda second latex polymer distinct from the first latex polymer.2. The wellbore fluid of claim 1 , further comprising at least one fiber material.3. The wellbore fluid of claim 1 , further comprising:a third latex polymer.4. The wellbore fluid of claim 3 , wherein the third latex polymer is distinct from the second latex polymer.5. The wellbore fluid of claim 4 , wherein the monomer species of the second latex polymer and third latex polymers are distinct.6. The wellbore fluid of claim 4 , wherein the stabilizer of the second latex polymer and third latex polymers are distinct.7. The wellbore fluid of claim 1 , wherein the second latex polymer is stabilized by a rosin acid soap.8. The wellbore fluid of claim 1 , wherein the at least one natural polymer is at least one of lignins claim 1 , lignitic material claim 1 , tannins claim 1 , polysaccharides claim 1 , or mixtures and derivatives thereof.9. The wellbore fluid of claim 8 , wherein the natural polymer is a polysaccharide.10. The wellbore fluid of claim 9 , wherein the at least one natural polymer is at least one of corn starch claim 9 , cellulose claim 9 , potato starch claim 9 , tapioca starch claim 9 , wheat starch or rice starch.11. The wellbore fluid of claim 1 , wherein the at least one latex monomer of the first latex ...

Hinge device with the possibility of breather opening

A hinge device includes a first connection means () assigned to be fixed to a structure or frame and rotatably connected to a second connection means () assigned to be fixed to a door device () comprises at least one interconnecting means () connected to a sliding means () and a friction means () with at least one friction sliding block () secured to the sliding means () and sliding along a respective sliding wall () of the first connection means () and parallel to a direction of translation of the sliding means (), wherein at least one arrest means () is fixed or made in the first connection means () in proximity to a sliding wall () to abut with the sliding means () to arrest its stroke towards the closing of the door or of the shutter in correspondence to the breather opening condition (S). 1) Hinge device with the possibility of breather opening comprising{'b': 3', '4, 'a first connection means () assigned to be fixed to a structure or frame and rotatably connected by a hinge pin () to'}{'b': '5', 'a second connection means () assigned to be fixed to a door or shutter;'}{'b': 7', '5', '9', '11, 'at least one interconnecting means () having a first end connected to the second connection means () by a first connecting pin () and a second end connected by a second connecting pin () to'}{'b': 13', '3', '15', '17', '5', '7, 'a sliding means () constrained to translate along the first connection means () and provided with elastic means () and with friction means () assigned to transmit to the second connection means (), by the interconnecting means (), respectively, an elastic force directed in a direction of an extreme closing condition (C) of the door or shutter and a frictional force directed opposite to the rotation of the door or of the shutter;'}{'b': 19', '13', '13', '11', '21', '7', '17, 'arrest means () assigned to abut with the sliding means () in an end portion of the rotation of the closing door or shutter arresting the sliding means () in correspondence ...

MECHANICAL SHAFT COUPLING FOR FLUID SYSTEM CONNECTIONS

A fluid control system includes a choke valve having a first connector shaft an actuator haying a second connector shaft; a collar disposed around the first and second connector shafts; and a spring disposed on the first connector shaft. The collar may have an internal taper and a plurality of engagement pins. 1. A system comprising:a choke valve having a first connector shaft;an actuator having, a second connector shaft; an internal taper; and', 'a plurality of engagement pins; and, 'a collar disposed around the first and second connector shafts, the collar comprisinga spring disposed on the first connector shaft.2. The system of claim 1 , wherein the first connector shaft comprises a distal recess configured to receive an extension of the second connector shaft.3. The system of claim 1 , wherein the second connector shaft comprises an extension configured to engage a distal recess of the first connector shaft.4. The system of claim 2 , wherein the first connector shaft further comprises a plurality of recesses that receive the plurality of engagement pins.5. The system of claim 4 , wherein the second connector shaft has a plurality of pin recesses disposed radially about the extension.6. The system of claim 5 , wherein the plurality of engagement pins extend through the first connector shaft into the plurality of pin recesses.7. The system of claim 4 , wherein the plurality of engagement pins are disposed within the collar and the corresponding claim 4 , recesses along the first connector shaft when the spring is compressed.8. The system of claim 1 , wherein the first connector shaft comprises a distal engagement geometry and the second connector shaft comprises a corresponding distal engagement geometry.9. The system of claim 1 , wherein the collar comprises a first end and a second end and wherein the internal taper radially expands from the first end to the second end.10. The system of claim 1 , wherein the collar comprises an end seal.11. A method comprising: ...

SHAKER SCREEN ASSEMBLY

An apparatus and method have a screen frame having a screening surface provided by an array of openings separated by transverse ribs, a scalping surface having a plurality of openings formed therethrough and a vertical base portion contacting the screen surface of the screen frame such that vertical base portion connects the scalping surface to the screen frame. A scalping surface support member is disposed vertically between the scalping surface and the vertical base portion such that the scalping surface support member spaces the scalping surface a vertical height above the screening surface of the screen frame. 1. An apparatus comprising:a screen frame having a screening surface provided by an array of openings separated by transverse ribs; anda scalping surface having a plurality of openings formed therethrough;a vertical base portion contacting the screen surface of the screen frame such that vertical base portion connects the scalping surface to the screen frame; anda scalping surface support member disposed vertically between the scalping surface and the vertical base portion such that the scalping surface support member spaces the scalping surface a vertical height above the screening surface of the screen frame.2. The apparatus of claim 1 , further comprising:sidewalls on each end of the scalping surface.3. The apparatus of claim 2 , wherein the sidewalls further comprise angled inner surfaces to direct fluid to the plurality of openings in the scalping surface.4. The apparatus of claim 1 , further comprising:a center divider having an angled surface directed to the plurality of openings in the scalping surface.5. The apparatus of claim 1 , wherein the plurality of openings in the scalping surface has a trapezoidal or rectangular cross-section geometry claim 1 , the cross-section being taken perpendicularly to the longitudinal axis of the openings in the scalping surface.6. The apparatus of claim 1 , wherein the vertical base portion is configured to ...

In Situ Decontamination of Downhole Equipment

A method of decontaminating naturally occurring radioactive material (NORM) from downhole equipment may include injecting a NORM dissolver into an isolated region of a wellbore in which NORM-contaminated production equipment is located; and removing the NORM contaminants from the production equipment. The method may also include recommencing production of hydrocarbons following the decontamination. 2. The method of claim 1 , further comprising:isolating the NORM-contaminated production equipment from other regions of the wellbore.3. The method of claim 2 , wherein the isolation comprises at least one packer.4. The method of claim 2 , wherein the isolation comprises a cement claim 2 , polymeric claim 2 , or gel plug.5. The method of any of claim 1 , further comprising:flushing a fluid through the isolated region prior to the injecting.6. The method of claim 1 , further comprising:circulating a wetting agent through the isolated region to render the NORM-contaminated production equipment water wet.7. The method of any of claim 1 , further comprising:flushing diesel through the isolated region after the removing.8. The method of claim 1 , wherein the NORM dissolver comprises at least one chelating agent.9. The method of claim 1 , further comprising:running a first gamma log before the injecting,running a second gamma log after the injecting, andverifying whether NORM has been removed.10. The method of claim 1 , wherein the NORM-contaminated production equipment comprises an artificial lift.11. The method of claim 10 , wherein the NORM-contaminated production equipment comprises an electric submersible pump.12. The method of claim 10 , wherein the NORM-contaminated production equipment comprises a gas lift.13. The method of any of claim 1 , wherein the NORM-contaminated production equipment comprises at least one valve.14. The method of any of claim 1 , wherein the NORM-contaminated production equipment comprises a packer.15. The method of any of claim 1 , wherein the ...

SHAKER AND DEGASSER COMBINATION

A system for separating components from a slurry of drilling fluid and drill cuttings on a shaker screen having an upper side and a lower side within a shaker. The system also has a pressure differential generator to pull an effective volume of air through a section of the shaker screen to enhance the flow of drilling fluid through the section of the shaker screen and the separation of drilling fluid from drill cuttings and further maintain an effective flow of drill cuttings off the shaker. A method of separating components of a slurry of drilling fluids and solids has the steps of delivering the slurry to a shaker, flowing the slurry over a first screen and applying an effective amount of vacuum to a first portion of the first screen to remove the drilling fluids from the slurry without stalling the solids on the first screen. 1. A method comprising:introducing a slurry to a shaker having a first screen and a second screen;flowing the slurry over the first screen; andapplying a first pressure differential to the first screen and not applying the first pressure differential across the second screen.2. The method of further comprising:applying a second pressure differential to the second screen wherein the second pressure differential is less than the first pressure differential.3. The method of further comprising:applying a second pressure differential to the first screen wherein the second pressure differential is zero.4. The method of further comprising:toggling the first pressure differential between static and at least a partial vacuum.5. The method of further comprising:intermittently interrupting the step of applying the first pressure differential.6. The method of further comprising:pulsing the step of applying the first pressure differential between the first pressure differential and a second pressure differential wherein the second pressure differential is different than the first pressure differential.7. The method of further comprising:applying a third ...

Chelate compositions and methods and fluids for use in oilfield operations

A breaker fluid may include a base fluid; and an inactive chelating agent. A process may include pumping a first wellbore fluid comprising an inactive chelating agent into a wellbore through a subterranean formation; and activating the inactive chelating agent to release an active chelating agent into the wellbore.

Corrosion inhibitor

Corrosion inhibition compositions and methods useful for inhibiting corrosion are provided. The corrosion inhibition compositions comprise at least one filming agent and at least one promoting agent and the methods for inhibiting corrosion on metal surfaces utilize the disclosed corrosion inhibiting compositions.

Methods of using oleaginous fluids for completion operations

In a method of gravel packing a wellbore in a subterranean formation, the wellbore having a cased section and an uncased section, the method may include pumping into the wellbore a gravel pack composition having gravel and a carrier fluid, where the carrier fluid includes an oleaginous fluid and an inorganic solid aggregator material.

Methods for minimizing fluid loss to and determining the locations of lost circulation zones

A method for determining a location of a lost circulation zone in a wellbore having a first wellbore fluid therein that includes allowing loss of the first wellbore fluid to the lost circulation zone to stabilize; adding a volume of a second wellbore fluid having a density less than the first wellbore fluid to the wellbore on top of the first wellbore fluid to a predetermined wellbore depth; determining an average density of the combined first wellbore fluid and second wellbore fluid; mixing the first wellbore fluid and the second wellbore fluid together; pumping a volume of a third wellbore fluid having a density greater the average density of the combined first and second wellbore fluid into the wellbore bottom until fluid loss occurs; and determining the location of the lost circulation zone is disclosed.