Andrew J Bradbury

Christopher Alan Sawdon

Jarrod Massam

Sonny Clary

William M Reid

Tom Heinz

Doug Oakley

Todd Reid

Fabien J Brand

Gunnar Fimreite

Grete Svanes

A method for drilling and completing a wellbore that includes drilling a wellbore through a subterranean formation with a wellbore fluid, the wellbore fluid comprising: a base fluid; and micronized weighting agent; and disposing a sand screen in an interval of the wellbore with the wellbore fluid is disclosed.

Method of completing a well with sand screens

A method of treating a wellbore that includes circulating a wellbore fluid in the wellbore, wherein the wellbore fluid comprises an oleaginous base fluid and a wellbore additive colloidal solid material, and wherein the wellbore additive colloidal solid material is formed by grinding a solid particulate material and a polymeric dispersing agent for a sufficient time so that the polymeric dispersing agent is absorbed to the surface of the resulting colloidal solid particles and less than 10% of the resulting colloidal solid particles have a diameter greater than 10 microns, but not more than five percent of the particles are less than 0.2 micron in diameter, wherein the grinding is carried out in the presence of an oleaginous base fluid and wherein the grinding is carried out so that the wellbore additive colloidal solid material has a weight average particle diameter dless than 2.0 microns.

Additive for increasing the density of a fluid for casing annulus pressure control

A method of controlling the pressure of a casing annulus in a subterranean well that includes injecting into the casing annulus a composition including a base fluid and a polymer coated colloidal solid material. The polymer coated colloidal solid material includes: a solid particle having an weight average particle diameter (d) of less than two microns, and a polymeric dispersing agent coated onto the surface of the solid particle during the cominution (i.e. grinding) process utilized to make the colloidal particles. The polymeric dispersing agent may be a water soluble polymer having a molecular weight of at least 2000 Daltons. The solid particulate material may be selected from materials having of specific gravity of at least 2.68 and preferably the solid particulate material may be selected from barium sulfate (barite), calcium carbonate, dolomite, ilmenite, hematite, olivine, siderite, strontium sulfate, combinations and mixtures of these and other similar solids that should be apparent to one of skill in the art.

Composition of base fluid and polymeric dispersing agent-absorbed polymer-coated colloidal particles

A method of formulating a wellbore fluid that includes grinding a solid particulate material and a polymeric dispersing agent to provide a resulting polymer coated solid material, and suspending the resulting polymer coated solid material in the wellbore fluid. At least a portion of the resulting polymer coated solid material has a particle diameter less than 2.0 microns, wherein the polymeric dispersing agent has a molecular weight greater than 10,000. Exemplary starting materials for the solid material include weighting agents including barite, calcium carbonate, dolomite, ilmenite, hematite or other iron ores, olivine, siderite and strontium sulfate as well as mixture and combinations of these and other similar weighting materials. The dispersant in one illustrative embodiment is a polymeric acrylate ester made from the monomers of stearyl methacrylate, butylacrylate, and acrylic acid.

Additive for increasing the density of an oil-based fluid and fluid comprising such additive

A method of prolonging the average lifespan of downhole tools that includes circulating the wellbore fluid comprising a base fluid and at least one of a micronized weighting agent and a dispersant coated weighting agent through the wellbore; wherein the wellbore fluid is characterized as having at least one of an equivalent weight, an equivalent or lower settling rate, and an equivalent or lower sag than a baseline wellbore fluid comprising a base fluid and an API-grade barite weighting agent; and wherein the wellbore fluid reduces abrasive wear of the downhole tool as compared to drilling with the baseline wellbore fluid is disclosed.

Reduced abrasiveness with micronized weighting material

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.

Increased rate of penetration from low rheology wellbore fluids

Additive for increasing the density of a fluid for casing annulus pressure

A wellbore fluid having an oleaginous phase and an additive for increasing the density of the wellbore fluid. The additive comprises solid colloidal particles coated with a dispersant coated onto the colloidal particle during the comminution process of forming the particles. Exemplary starting materials for the colloidal particles include commonly known weighting agents including barite, calcium carbonate, dolomite, ilmenite, hematite or other iron ores, olivine, siderite, and strontium sulfate as well as mixture and combinations of these and other similar weighting materials. The dispersant in one illustrative embodiment, is selected from carboxylic acids of molecular weight of at least 150 Daltons. Alternatively, the dispersant coating may be made of compounds including oleic acid, polybasic fatty acids, alkylbenzene sulfonic acids, alkane sulfonic acids, linear alpha-olefin sulfonic acid or the alkaline earth metal salts of any of the above acids, and phospholipids as well as mixtures and combinations of these compounds. In another illustrative embodiment the dispersant is a polyacrylate ester. The illustrative polymeric dispersant should have an average molecular weight from about 10,000 Daltons to about 200,000 Daltons.

A method of controlling the pressure of a casing annulus in a subterranean well that includes injecting into the casing annulus a composition including a base fluid and a polymer coated colloidal solid material. The polymer coated colloidal solid material includes: a solid particle having an weight average particle diameter (d) of less than two microns, and a polymeric dispersing agent coated onto the surface of the solid particle during the comminution (i.e. grinding) process utilized to make the colloidal particles. The polymeric dispersing agent may be a water soluble polymer having a molecular weight of at least 2000 Daltons. The solid particulate material may be selected from materials having of specific gravity of at least 2.68 and preferably the solid particulate material may be selected from barium sulfate (barite), calcium carbonate, dolomite, ilmenite, hematite, olivine, siderite, strontium sulfate, combinations and mixtures of these-and other similar solids.

A wellbore fluid having an oleaginous phase and an additive for increasing the density of the wellbore fluid. The additive comprises solid colloidal particles coated with a dispersant during the comminution process of forming the particles. Exemplary starting materials for the colloidal particles include commonly known weighting agents as well as mixture and combinations thereof. The dispersant in one embodiment, is selected from carboxylic acids of molecular weight of at least 150 Daltons. Alternatively, the dispersant coating may be made of compounds including oleic acid, polybasic fatty acids, alkylbenzene sulfonic acids, alkane sulfonic acids, linear alpha-olefin sulfonic acid or the alkaline earth metal salts of any of the above acids, and phospholipids as well as mixtures and combinations of these compounds. In another embodiment the dispersant is a polyacrylate ester having an average molecular weight from about 10,000 Daltons to about 200,000 Daltons.

The invention relates to water based wellbore 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 ensuring reduced damage to the formation, yet simultaneously is permeable to the back flow of hydrocarbons during a hydrocarbon recovery process.

Water based wellbore fluids

An additive which increases the density of wellbore fluids used during the construction or repair of oil, gas, injection, water or geothermal wells comprises solid colloidal particles of weight average particle diameter (D ) of less than 2 microns, the particles being deflocculated by the action of a dispersant, preferably incorporated during the process of grinding or communication of the particles to the specified particle size. The additives may be used in any wellbore fluid such as drilling, cementing, completion, packing, work-over (repairing), stimulation, well killing and spacer fluids as well as in a dense media separating fluid or in a ship's ballast fluid.

Growing community of inventors

Banchory, United Kingdom

Andrew J Bradbury