Earth boring – well treating – and oil field chemistry – Earth boring – Contains organic component
Reexamination Certificate
1999-10-29
2002-05-28
Tucker, Philip (Department: 1712)
Earth boring, well treating, and oil field chemistry
Earth boring
Contains organic component
C507S106000, C507S126000, C507S140000
Reexamination Certificate
active
06395686
ABSTRACT:
FIELD OF INVENTION
The field of the invention comprised an additive to reduce HPHT fluid loss in drilling fluids used in drilling subterranean wells.
BACKGROUND OF THE INVENTION
Drilling fluids, sometimes referred to as drilling muds, are complex mixtures of chemicals employed in drilling subterranean wells and perform a variety of functions. These drilling fluids generally comprise a liquid or slurry pumped down the down the drill string which exits through openings in the drill bit immediately adjacent the penetrated formation. The drilling fluid then flows upwardly in the annulus between the frill string and the wall of the hole to the surface and functions in a variety of ways. The drilling fluid both cools and lubricates the drill bit and because injected into the hole under pressure delivers power to te frill bit, carries cuttings upwardly out of the drill hole during circulation, suspends cuttings in the bore hole when circulation stops, prevents blow outs, minimized water loss into permeable formations along the length of the bore hole, and acts as a lubricant between the drill string and the bore hole wall.
The simplest drilling fluid comprises a mixture of drilled solids and water, sometimes referred to as “native” drilling mud. In some instances, the solids obtained consists of clays, which when finally ground, function as the solid component of the drilling fluid or drilling mud. These drilling fluids tend to function reasonably well for controlling normal pressures at shallow depths in many oil and gas wells.
Native drilling mud or fluids provide almost no control over the loss of water into permeable formations and tend to wash out, or enlarge the diameter of the hole, and accumulate shale balls on the bit. These difficulties prompted the addition of a wide variety of chemicals to the drilling fluid.
The standard drilling fluid therefore comprises a native drilling fluid combined with clays such as bentonite, and/or sodium hydroxide, chrome, lignosulfonates, lignite, weighting materials such as barium sulfate, hematite, calcium carbonate, silica and polymeric compounds.
The bentonite, along with the drilled solids and sometimes sub-bentonitic clays or mixtures, acts as a gelling agent which minimizes or prevents cuttings from the drilling operation from settling to the bottom of the well, especially during those periods which require stopping the drilling operation to add extra sections of drill pipe to the bit to allow increasing depth of the drilled hole.
The drilling fluid also creates a filter cake that imparts low permeability to the face of the permeable formation. The ideal filter cake comprises a relatively thin and hard layer as opposed to thick viscous coatings. The latter interfere with the drilling operation in that they have a tendency to entrain drilled solids moving up the annulus of the bore hole. Pressure in the bore hole exceeds the pressure in the permeable formation and thereby creates the filter cake which further results in liquid from the drilling fluid moving into the permeable formation. This leaves a layer of the filter cake on the face of the hole. Liquid permeating this filter cake and the formation is called filtrate. Large amounts of filtrate passing across the formation face result in the deposition of a thick filter cake whereas small amounts of filtrate passing across the fade result in a thin filter cake. The thin filter cake avoids or minimizes the problem of decreasing the bore hole diameter, a cause of concern since this decreases the flow of drilling fluid upwards and out of the well, slowing down the removal of cuttings from the bore hole.
As the thickness of the filter cake increases, the volume of fluid loss also increases. The thinner the filter cake, therefore, the lower the fluid loss. A thick wall cake will lead not only to high fluid loss, but also a reduction in the diameter of the well bore.
The ideal filter cake, therefore limits filtrate loss into the formation and minimizes any decrease in bore diameter. In addition to the inconvenience of having to continually add water to the drilling fluid because of filtrate loss, drillers have also found that excessive filtrate pumped into the formation not only interferes with electric logging of the well, but also causes swelling of the permeable formation which can reduce the permeability of a productive formation to the extent that the formation will not produce oil or gas, or only provide minimal production.
The addition of various art known compounds to the drilling fluid can minimize fluid loss into the formation. Additionally, the compounds added to the wells to prevent fluid loss must withstand the temperatures in the wells, generally from about 100 to about 500° F. The art refers to materials that function in this way as HPHT fluid loss control aids. Many, however, cannot function adequately at these extreme conditions of temperature and pressure.
Bore hole temperatures can vary from ambient up to about 500° F. and pressures from atmospheric up to about 20,000 psi. Temperature and pressure conditions such as these can have an adverse effect on bore hole fluids causing them to destabilize if they contain additives and furthermore, these pressures and temperatures have a very strong effect in forcing the drilling fluid not only to the surface, but also against the side of the bore hole causing either filtrate loss or a break through of the drilling fluid, as well as the oil or gas under pressure into the permeable strata considerably below the opening of the well at the surface. Accordingly, the industry has sought ways to prevent not only the adverse effect on drilling fluid additives encountered under these conditions, but also blowouts of the well and the subsequent loss of oil, gas or other materials produced in the well, by the use of HPHT additives to the drilling mud.
In addition to reducing HPHT fluid loss or filtrate loss, HPHT fluid loss control aids would also ideally stabilize troublesome shales and decrease bore hole erosion. By inhibiting the swelling of the formation; preventing the adhesion of gumbo shale and other clays to the drill string; coating clay formations to produce a gauged hole; hole problems are prevented, which significantly reduces downtime on the rig, thereby reducing the cost of drilling the wells, e.g., oil and/or gas wells.
The HPHT fluid loss control aid would preferably provide some bore hole lubrication in order to not only decease the friction on the cutting bit during drilling operations, but also the rotation of the drill shaft in the hole as well as the insertion of a drilling pipe into the hole during the drilling operation. Stated otherwise, bore hole lubricants reduce torque and drag applied to the drill sting during drilling operations.
Since some of the materials produced in a subterranean well come from sand formations, the depletion of oil, gas or other materials from the sand leaves the sand formation permeable, allowing it to take in oil, gas or other resources exiting the well from fluid bearing strata below the depleted sand. Providing a composition that would seal depleted sands as well as act as an HPHT fluid loss control aid would provide a marked advantage for these drilling operations.
Lastly, HPHT fluid loss control aids that also will act as a wall cake conditioner would have an advantage in drilling operations. The condition of the filter cake determines the ability of the drill sting to be differently stuck to the borehole wall. A thinner and less permeable cake, which contains a lubricant, will be less likely to adhere to the drill pipe.
Although many compositions when added to a drilling fluid can provide the various advantages sought in a drilling operation, they can cause adverse effects on the flow properties of a mud, such as, altering thixotropic or dilatant flow properties. Excessive thixotropy causes the drilling mud to lose its viscous character at high sheer rates which can cause drill cuttings to settle to the bottom of the bore hole rather than moving upwards to be separated from the drilling
Morgan, Lewis & Bockins LLP
Tucker Philip
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