Wells – Processes – Chemical inter-reaction of two or more introduced materials
Reexamination Certificate
2002-07-12
2003-03-04
Suchfield, George (Department: 3672)
Wells
Processes
Chemical inter-reaction of two or more introduced materials
C166S311000, C166S312000, C507S219000, C507S224000, C507S267000, C507S277000, C507S927000, C507S929000
Reexamination Certificate
active
06527051
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates to encapsulated water soluble chemicals for use in controlled time release applications, methods of encapsulating the water soluble chemicals and methods of using the encapsulated chemicals.
2. Description of the Prior Art
Water soluble particulate solid chemicals encapsulated with coatings of polymers and the like have been utilized heretofore. The encapsulating coatings on the water soluble chemicals have been utilized to control the times when the chemicals are released in aqueous fluids. For example, encapsulated particulate solid chemicals have been used in oil and gas well treating fluids such as hydraulic cement slurries, formation fracturing fluids, formation acidizing fluids and the like.
The methods of coating water soluble particulate solid chemicals have generally involved spray coating a solution of a polymer and a cross-linking agent onto the particulate solids while simultaneously fluidizing the solids with a hot gas such as air or nitrogen. The hot gas causes the polymer to cross-link and evaporates the water from the polymer solution leaving a porous film of cross-linked polymer on the particulate solids. When the coated solids are placed in an aqueous fluid, the water passes through the porous polymer film and dissolves the water soluble chemical inside. The time required for the water to pass through the polymer coating depends on its thickness, i.e., the thicker the polymer coating, the longer it takes for the water soluble chemical to leach out of the coating.
A problem has been encountered when using the prior art methods as described above to encapsulate hygroscopic or otherwise surface wet particulate solids. That is, because of the presence of the water, the sprayed on polymer solution in the presence of hot gas often fails to produce a dry encapsulating polymer coating on the solids. Problems have also been encountered when dry particulate solid chemicals which are chemically incompatible with the encapsulating polymer are encapsulated. That is, the incompatible chemicals prevent or quickly deteriorate the polymer coatings.
An example of a need for improved encapsulated chemicals in well operations involves primary cementing in deep water offshore wells. Hydraulic cement compositions are used in primary cementing operations whereby casing and other pipe strings are cemented in well bores. That is, a hydraulic cement composition is pumped into the annular space between the walls of a well bore and the exterior of a pipe string disposed therein. The cement composition is permitted to set in the annular space thereby forming an annular sheath of hardened impermeable cement therein. The objective of the cement sheath is to physically support and position the pipe string in the well bore and bond the pipe string to the walls of the well bore whereby the undesirable migration of fluids between zones or formations penetrated by the well bore is prevented.
Primary cementing operations in deep water offshore wells are particularly difficult in that they are carried out in well bores which penetrate formations between the sea floor or mud line and a depth generally under about 2,000 feet below the mud line. Such formations are often not well consolidated, readily fracture and often have highly pressured water flows therethrough. Another problem is the temperature at which the cement composition must set. Deep water off shore wells typically have sea bottom temperatures ranging from about 32° F. to 55° F. depending on their geographical location. The cement compositions utilized for performing cementing operations at such temperatures must set and provide enough compressive strength to proceed with drilling without involving long waiting on cement (WOC) times, preferably less than 24 hours. Accordingly, the cement compositions must include set and strength accelerating agents to allow the cement compositions to set at the low temperatures involved and to develop early compressive strengths. However, a problem in the use of cement set and strength accelerating agents is that they often cause the cement compositions to have thickening times which are too short to allow placement of the cement compositions in the formations or zones to be cemented. Thus, the cement compositions used in deep off shore wells must have adequate pumping times to allow placement, but at the same time they must set and develop sufficient compressive strengths to allow further drilling as quickly as possible.
In cementing high temperature wells which shorten the thickening times of cement compositions, a cement set retarder must be added to the cement composition to allow adequate placement time. The presence of the set retarder lengthens the WOC time of the cement composition making it necessary to add a set and strength accelerating agent to the cement composition if the WOC time is to be reduced. The presence of the set and strength accelerating agent in the cement composition increases the risk that the cement composition may thicken or set before placement.
Particularly suitable cement set and strength accelerating agents are calcium salts such as calcium chloride. If such set and strength accelerating agents were encapsulated whereby their release in cement compositions would take place after the safe placement of the cement compositions in the formations or zones to be cemented, the WOC times could be shortened appreciably. However, because calcium chloride-and other similar salts are hygroscopic, effective controlled time release encapsulation has heretofore not been possible.
Another example of a need for improved encapsulated chemicals in well operations involves dissolving drilling fluid filter cake and the like in well bores penetrating subterranean producing formations with acid or acid forming chemicals. Oil and gas wells are commonly drilled utilizing water or oil based drilling fluids. During the drilling process substantial damage to the well bore surfaces adjacent to producing formations takes place. The damage is usually in the form of a build-up of drilling fluid filter cake and gelled drilling fluid on the surface of the well bore and in the near-well bore porosity of adjacent producing formations. Unless removed, the presence of the filter cake and gelled drilling fluid hinders the flow of oil and gas into the well bore. Heretofore, the filter cake and gelled drilling fluid have been removed by the expensive and time consuming process of circulating a corrosion inhibited aqueous acid solution through the well bore and into contact with the drilling fluid and gelled drilling fluid whereby they are dissolved. An encapsulated acid or acid producing chemical which could be released adjacent to the producing formations after placement would save considerable time and money.
Thus, there are continuing needs for improved encapsulated water soluble chemicals useful in controlled time release applications, improved methods of encapsulating water soluble chemicals and methods of utilizing the encapsulated chemicals.
SUMMARY OF THE INVENTION
The present invention provides methods of encapsulating chemicals for use in controlled time release applications, encapsulated water soluble chemicals and methods of using the encapsulated chemicals which meet the above described needs and overcome the deficiencies of the prior art. The methods of this invention for encapsulating water soluble particulate solid chemicals basically comprise the following steps. A first coating is formed on the particulate solid chemical which is a dry hydrophobic film forming material or a dry sparingly soluble material. The hydrophobic material or the sparingly soluble material is present in the first coating in an amount such that it provides a dry shield on the encapsulated chemical and preferably provides a short delay in the release of the encapsulated chemical in the presence of water. A second coating is next formed on the first coating which is a porous cross-linked hydrophilic polymer. The porous hydrophilic polymer is pr
Crook Ronald J.
Fitzgerald Russell M.
Gray Dennis W.
Laramay Steven B.
Reddy Baireddy R.
Dougherty, Jr. C. Clark
Halliburton Energy Service,s Inc.
Roddy Craig W.
Suchfield George
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