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Well treatment fluid

Inactive Publication Date: 2005-05-26
BSA ACQUISITION
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  • Summary
  • Abstract
  • Description
  • Claims
  • Application Information

AI Technical Summary

Benefits of technology

[0010] Thus, there is provided in accordance with the present invention a method of enhancing the thermal stability of a fluid for drilling, drill-in, completion, work-over, packer, well treating, testing, spacer, or fluid loss control that includes polymers such as polysaccharides. The method includes providing said fluid that includes water, a polyol, a viscosifying agent and a weighting agent. This fluid for drilling, drill-in, completion, work-over, packer, well treating, testing, spacer, or fluid loss control is added to the wellbore and preferably a polyol concentration of greater than about 15 wt % based on the fluid is maintained in the wellbore. The fluid is particularly useful in very deep wells that exert extreme pressure and temperature on wellbore treatment fluids. Use of this fluid for drilling, drill-in, completion, work-over, packer, well treating, testing, spacer, or fluid loss control provides a fluid that does not significantly change viscosity under the extreme conditions found in very deep wells. Furthermore, use of said fluid provides a fluid that inhibits stress cracking and pitting corrosion on the carbon and stainless steel components of the drill strings, well-drilling and related fluid handling equipment.

Problems solved by technology

It is difficult to maintain a fluid having the desired lubricity and viscosity under the extreme shear, pressure and temperature variances encountered during drilling operations, especially when drilling very deep wells that descent 15,000 to 30,000 feet (4,500 to 10,000 meters) or more below the earth's surface.
Under these conditions many of the viscosifying agents, particularly polysaccharides such as starch, cellulose, galactomannan gums and polyacrylates, are not stable at such high temperatures and tend to un-crosslink and de-polymerize, thus losing their effectiveness.
The degraded polysaccharides can cause the drill string to bind in the wellbore and induce formation damage.

Method used

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Examples

Experimental program
Comparison scheme
Effect test

example 1

Radial Fluid Loss for Newtonian Fluids

[0043] To demonstrate the effect of increased viscosity on radial fluid loss for a Newtonian fluid, the fluid loss of two solids-free weighted fluids are compared. The viscosity data for weighted fluids, which were used to simulate completion brines, were obtained from Foxenberg, W. E., et al., “Effects on Completion Fluid Loss on Well Productivity”, SPE 31137, presented at the SPE International Symposium on Formation Damage Control 14-15 February 1996, Lafayette, La., USA to be used in Eq. (1) and (2). Viscosity data for weighted fluids solutions other than completion brines were obtained from Perry and Green, Perry's Chemical Engineers' Hand book, 6th edition, 1984, p. 3-251 and 2-352.

[0044] The rate of fluid loss of both types of pills can be approximated by calculating the fluid loss of a Newtonian fluid according to the following Equation (1) as discussed in “Power-Law Flow and Hydrodynamic Behavior of Biopolymer Solutions in Porous Media...

example 2

Radial Fluid Loss for a Glycerol Fluid

[0051] Using the methods described in Example 1, the fluid loss rate for a NaCl brine solution and a polyglycol solution can be compared. For a well formation that has permeability of 10 md, porosity of 0.3, and bottom hole temperature of 425° F. (218° C.), a fluid density of 9.2 ppg (1.1 g / ml) is required to maintain an overbalanced pressure of 300 psig during the completion process. The well that has an interval length of 100 ft. (30 m) and the wellbore radius of 3 inches (7.6 cm), requires 3.5 bbl (556 1) of fluid to fill the wellbore. At 425° F. (218° C.), 10.0 ppg, (1.2 g / ml) NaCl brine has a viscosity of about 0.28 cp and 8.334 ppg (1 g / ml) NaCl brine (less than 10 g / L NaCl) has a viscosity of less than 0.1 cp. Therefore, for a 9.2 ppg (1.1 g / ml) NaCl, a viscosity of 0.2 will be used. The data listed in Table 2 indicates this polyglycol based fluid controls fluid loss much better than the brine. For example, in one hour about 175 bbls (27...

example 3

Viscosity of Polyglycol Fluid with Added Hydroxypropyl Cellulose

[0053] The viscosities of a polyglycol with and without added viscosifying agents were measured and compared. One barrel (159 1) of a polyethylene glycol fluid having an average molecular weight of 200 grains / mole and sold under the trade name Polyglycol E2000 by Dow Chemical, Inc. was admixed with 5 pounds (1.9 kg) hydroxypropyl cellulose (HPC). After mixing for 1 hour at room temperature, the viscosity was measured on a variable speed rheometer at 120° F. (49° C.) and 180° F. (82° C.) under a wide range of shear conditions. The results of the viscosity measurements for both the polyglycol fluid and the polyglycol fluid with added HPC are listed in Table 3. Analysis of the results underscores the enhanced viscosity that can be achieved by the addition of a viscosifying agent. The fluids prepared according to this invention demonstrate non-Newtonian characteristics. These fluids exhibit increased viscosity at low shear...

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Abstract

This invention relates to a wellbore treatment fluid and a method of enhancing wellbore treatment fluids to increase efficiency and productivity of wells. More specifically this invention provides methods for enhancing the thermal stability of wellbore treatment fluids such as drill-in, completion, workover, packer, well treating, testing, spacer or hole abandonment fluids. The methods include providing a wellbore treatment fluid that comprises polyol, polysaccharide, weighting agent, and water, wherein the fluid is solids free.

Description

RELATED APPLICATIONS [0001] This application is a divisional of U.S. Ser. No. 09 / 676,396 filed Sep. 29, 2000, which is a continuation-in-part of U.S. Ser. No. 09 / 226,682 filed Jan. 7, 1999. This application is also related to two continuations of U.S. Ser. No. 09 / 226,682, filed on Sep. 21, 2000.FIELD OF THE INVENTION [0002] This invention relates to the exploitation of subterranean formation using drilling, drill-in, completion, work-over, packer, well treating, testing, spacer, fluid loss control or hole abandonment fluids. More specifically, this invention is directed to a method of enhancing wellbore treatment fluids, particularly fluids used in deep wells, by enhancing the thermal stability of the treatment fluid. A fluid for use in the present invention preferably comprises water, a weighting agent, a viscosifier and a solvent. The solvent, which includes a polyol, e.g., a glycerol, glycol or polyglycol, provides a medium that increases fluid viscosity, dissolves a variety of w...

Claims

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Application Information

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IPC IPC(8): C09K8/08C09K8/12C09K8/20C09K8/22C09K8/514
CPCC09K8/08C09K8/12C09K8/514C09K8/22C09K8/206
Inventor VOLLMER, DANIEL PATRICK
Owner BSA ACQUISITION
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