Drilling fluid companies have developed a variety of formulations for different drilling situations.

For every well there is a reason, and a fluid for every purpose under heaven, or rather, the earth. Here is a quick roundup of several new drilling fluids, each to be used for its own special time.
Olefins and esters
Halliburton's Baroid drilling fluids group has introduced a blend of internal olefins and ester-based synthetic fluids to keep equivalent circulating densities (ECDs) extremely low. This is to be used when it is not time to rend, or fracture, the formation.
Two specially formulated thinners, Coldtrol and ATC, work in conjunction with suspension agents and emulsifiers to reduce fluid viscosity in cold - 40°F (4°C) - environments. Called Accolade, this clay-free system is especially suited for deepwater drilling in the Gulf of Mexico, as it complies with the new NPDES Region 6 environmental regulations.
Accolade was first used to drill a 15,000-ft (4,570-m) Gulf of Mexico well in 4,000-ft (1,220-m) waters. There was only 0.1 lb/gal of mud weight between drilling ahead and severe loss of circulation, but the mud system lowered ECD and provided a greater margin of wellbore stability. "Literally straight from the lab to its first application, the Accolade fluid provided trouble-free performance on a tough well," said Jack Beasley, vice president of Baroid. It has been used on more than two dozen Gulf of Mexico wells. The fragile gel structure means low surge and swab pressures as well as minimal pressure spikes when breaking circulation in cold-water environments, resulting in reduced fluid losses.
Formates
Cesium-formate brines are the "big brother" in the family of water-based drilling fluids, said Bill Lang, president of Cabot Specialty Fluids. Using blends of sodium-, potassium- and cesium-formate brines, densities of 8.33 lb/gal to 19.2 lb/gal can be obtained. While traditional divalent chloride and bromide brines can be viscous and corrosive, the pH of organic, monovalent formate brines can be adjusted to make them noncorrosive. Because they are solids-free base fluids, downhole equipment experiences less wear. And compared to barite-laden muds, there is less torque and drag. Formate brine is a good fluid choice when barite sag is a problem. "And you don't need to treat the cuttings. There are no chlorides, so onshore the cuttings can be land-farmed. Offshore, the formate family of fluids has received the very best environmental rating in the North Sea - category E," Lang added. This formulation is specially designed for the time to cast away stones.
The industry is becoming more familiar with formate brines, especially in the North Sea, where 50 cesium-formate jobs have doubled well productivity. "Operators need to know that formate brines are an investment in their operations, not an expense," Lang said. "Although the cost per barrel might be several times as expensive, up to (US) $4,100/bbl, your well ends up twice as productive compared to those using traditional brines and oil-based muds, so real value is created."
In a multiwell project in the North Sea, drilling problems were experienced with conventional muds, and the best well achieved 10,000 b/d. Using $1 million worth of cesium-formate brine in the next well saved $200,000 in rig costs, and the well produced 50,000 b/d. That works out to an increase of $100 million more in oil revenue each year - not bad!
Cesium-formate brines are manufactured fluids, not byproducts of waste streams like other brine fluids. Cesium-bearing ore is ground to 200 mesh, digested with acid, neutralized and filtered, then the solution undergoes a chemical reaction to produce formate brine. Cabot mines the cesium-bearing ore at its Bernic Lake mine in Manitoba. The mine contains 82% of the known reserves of cesium ore. The company recently built a $30 million plant to convert this resource into formate drilling fluids.
Starch and polyglycerol
Newpark Drilling Fluids' DeepDrill fluid has matched penetration rates achieved with synthetic-based fluids in demanding directional wells through High Island gumbo. This blend of methyl glucoside (a starch derivative) and polyglycerol is nontoxic and water-soluble, so cuttings and fluid can be discharged without environmental liability. Its lower circulating density makes this fluid a good choice for deepwater wells and when "well breathing" is a concern. It acts as a shale inhibitor and forms a slick coating on the formation and a tough, thin filter cake.
Foams
It is a misconception that no drilling fluid enters the formation when drilling in underbalanced mode. The forces of imbibition and capillary suction virtually guarantee the fluid will enter the pores near the wellbore. Therefore, even underbalanced fluids must be compatible with reservoir rock and fluids.
Weatherford Underbalanced Drilling Services formed Weatherford Fluid Systems to design appropriate fluids for use in underbalanced drilling. One such fluid system is Trans-Foam, the first recyclable foam that can be turned back into a liquid by adjusting the pH and reinjected as a foam. Separate formulations are available for fresher water, saltier water and oil reservoirs. Building on that product's success, the company recently introduced its Weatherfoam system, which uses a different defoaming chemistry. This drilling fluid system has been used in underbalanced drilling projects in Canada, when it is not a time to kill the well.
The surfactants used in foam systems can interact with reservoir fluids to form emulsions that restrict the flow of hydrocarbons to the well. Weatherford has developed WFT-Net, a product for controlling emulsions when drilling oil reservoirs with foam.
Silicates
National Silicates, an affiliate of PQ Corp., is using sodium and potassium silicates in water-based mud to match the performance of oil-based muds without the associated environmental liabilities. These nontoxic EcoDrill silicates are an inexpensive way to maintain borehole stability and fast rates of production. Depending on the pH and solids content, the silicate anions can vary in size from monomers to chains and rings to complex structures. There are times you need to build up, and times you need to tear down the size of the structures. Gelation occurs when the silicate fluid contacts low pH (6 to 8) pore fluid, resulting in a cake that acts as a natural fluid-loss agent.

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