AU6808400A - Hydrate preventing well treating fluids having reduced fluid loss and methods - Google Patents

Description

P/00/011 Regulation 3.2

AUSTRALIA

Patents Act 1990 COMPLETE SPECIFICATION .c *5*S FOR A STANDARD PATENT

ORIGINAL

Name of Applicant: Actual Inventors: TO BE COMPLETED BY APPLICANT HALLIBURTON ENERGY SERVICES, INC.

Sanjay Vitthal; Fouad Fleyfel; Richard Dubois; Slabaugh; Mark A. Parker; C. Michael Gideon *5 S. S S S

S.

Blaine Spies; Billy Address for Service: Invention Title: CALLINAN LAWRIE, 711 High Street, Kew, Victoria 3101, Australia HYDRATE PREVENTING WELL TREATING FLUIDS HAVING REDUCED FLUID LOSS AND METHODS The following statement is a full description of this invention, including the best method of performing it known to me:- 25/1 0/00,tdl 1670.cs.doc,l HYDRATE PREVENTING WELL TREATING FLUIDS HAVING REDUCED FLUID LOSS AND METHODS Background of the Invention 1. Field of the Invention The present invention relates to hydrate preventing well treating fluids having reduced fluid loss and methods of treating subterranean zones using such treating fluids.

2. Description of the Prior Art Viscous aqueous well treating fluids are utilized in a variety of treatments performed in oil and gas wells. Examples of such treatments include, but are not limited to, fluid loss control treatments, production stimulation treatments, formation permeability conformance treatments and treatments to reduce water production.

A production stimulation treatment which is performed in wells and which often utilizes a viscous aqueous treating fluid is hydraulic fracturing. In hydraulic fracturing treatments, the viscous treating fluid is utilized as a fracturing fluid and also carries particulate solid proppant, sand, into the fractures formed. That is, the fracturing fluid is pumped through the well bore into a o subterranean zone to be stimulated at a rate and pressure such that fractures are formed and extended in the formation. Particulate solid proppant is suspended in the viscous fracturing fluid so that it is deposited in the fractures when the treating fluid is broken into a thin fluid and returned to the surface. The particulate solid proppant deposited in the fractures functions to prevent the fractures from closing whereby conductive channels are formed through which produced fluids can S° readily flow to the well bore.

It is important that the viscous aqueous treating fluids utilized in 30 treatments carried out in oil and gas wells have low fluid loss properties. That is, when the treating fluids come into contact with permeable subterranean zones or formations, the treating fluids must resist the loss of water to the zones or formations. If too great an amount of water is lost from the viscous treating fluids, fracture extension may discontinue.

02/02/01.al 1670.spc 1 -1- Another problem than can occur in the use of viscous aqueous treating fluids in subterranean zones and formations is the formation of hydrates in the treating fluids, particularly when the treating fluids are utilized in offshore wells.

For example, in fracturing a subterranean zone in an offshore well, once the fractures are created and extended the viscous aqueous treating fluid utilized is broken into a relatively thin fluid and produced back to the surface. Under certain conditions of pressure and temperature, when the thin aqueous fracturing fluid is mixed with gas from the fractured zone solid gas hydrates can be formed. Such solid hydrates can plug off the production string disposed in the well bore which in turn causes significant safety hazards and costly delay.

Thus, there are needs for improved viscous aqueous well treating fluids and methods of using such fluids whereby the treating fluids have low fluid loss properties and the formation of hydrates in the fluids is prevented.

Summary of Invention The present invention provides improved viscous aqueous well treating fluids and methods of using the treating fluids which meet the needs described above and overcome the deficiencies of the prior art. The well treating fluids of this invention are basically comprised of an aqueous liquid, a hydratable polysaccharide gelling agent for increasing the viscosity of the aqueous fluid and a fluid loss reducing and hydrate preventing agent selected from the group consisting of one or more of ethylene glycol, propylene glycol, butylene glycol and glycol ethers.

The treating fluids of this invention can optionally include a cross-linking agent for cross-linking the aqueous gel and further increasing the viscosity of the treating fluid. Also, the treating fluids can optionally include a delayed gel breaker for causing the treating fluid to break into a thin fluid in a predictable relatively short period of time.

The improved methods of the present invention for treating a 30 subterranean zone penetrated by a well bore are basically comprised of the following steps. A well treating fluid of this invention is prepared comprised of an aqueous liquid, a hydratable polysaccharide gelling agent and a fluid loss reducing and hydrate preventing agent described above. The treating fluid is pumped into the subterranean zone to be treated by way of the well bore at a rate and pressure 02/02/01,.al 1670.spc.2 -2sufficient to treat the zone. Thereafter, the well treating fluid is allowed to break into a thin fluid and is recovered from the zone.

Thus, it is a general object of the present invention to provide improved well treating fluids which have reduced fluid loss properties and in which the formation of hydrates is prevented and methods of using such treating fluids.

Other and further objects, features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of preferred embodiments which follows.

Description Of Preferred Embodiments As mentioned above, the improved viscous aqueous well treating fluids of this invention have low fluid loss properties and the formation of hydrates in the fluids when mixed with natural gas is prevented. The improved treating fluids of the present invention are basically comprised of an aqueous fluid, a hydratable polysaccharide gelling agent for increasing the viscosity of the aqueous fluid and a fluid loss reducing and hydrate preventing agent.

The aqueous fluids utilized to form the treating fluids of this invention can be fresh water, unsaturated salt solutions, saturated salt solutions such as brine or seawater or any other aqueous liquid which does not adversely react with components of the treating fluids. The water used in well treating fluids normally contains one or more salts for inhibiting the swelling of clays in the subterranean zones being treated. The most common clay inhibiting salt utilized is potassium 4 chloride, but other salts and clay treating agents such as tetramethyl ammonium chloride can also be used. The pH of the water is preferably in the range of from about 6 to about 8.5 to facilitate the hydration of the polysaccharide gelling agent utilized.

The polysaccharide gelling agents which can be used in accordance 0 with this invention include natural and derivatized polysaccharides which are soluble, dispersible or swellable in an aqueous liquid to yield viscosity to the liquid.

0 One group of polysaccharides which are suitable for use in the present invention •oo include galactomannan gums such as arabic gum, ghatti gum, karaya gum, tamarind gum, tagacanth gum, guar gum, locust bean gum and the like. Modified or derivatized galactomannan gums can also be utilized such as carboxyalkyl derivatives,-e.g., carboxymethyl guar, and hydroxyalkyl derivatives, e.g., 02/02/01, all 1670 spc,3 hydroxyethylguar and hydroxypropylguar. Doubly derivatized gums, such as carboxymethylhydroxyethylguar and carboxymethylhydroxypropylguar, can also be used.

Modified celluloses and derivatives thereof, cellulose ethers, esters and the like, can also be employed in the practice of this invention. In general, any of the water soluble cellulose ethers can be used, including, but not limited to, the various carboxyalkylcellulose ethers such as carboxyethylcellulose and carboxymethylcellulose, mixed ethers such as carboxymethylhydroxyethylcellulose and hydroxyalkylcelluloses such as hydroxyethylcellulose. Various other cellulose derivatives can also be utilized including alkylhydroxyalkylcelluloses, alkylcelluloses, alkylcarboxyalkylcelluloses, alkylalkylcelluloses, hydroxyalkylalkylcelluloses and the like. Hydroxyethylcellulose grafted with vinyl phosphonic acid such as disclosed in U.S. Patent No. 5,067,565 issued to Holtmeyer et al., on November 26, 1991 can also be utilized.

Of the various polysaccharide gelling agents which can be used, those selected from the group consisting of guar gum, hydroxyethylguar, hydroxypropylguar, carboxymethylguar, carboxymethylhydroxyethylguar and carboxymethylhydroxypropylguar are preferred, with hydroxypropylguar being the most preferred.

The hydratable polysaccharide gelling agent utilized is generally present in a treating fluid of this invention in an amount in the range of from about o 0.15% to about 0.75% by weight of the aqueous fluid in the treating fluid, more preferably in an amount in the range of from about 0.25% to about 0.55% and S most preferably in an amount of from about 0.4% to 0.45%.

0 The fluid loss reducing and hydrate preventing agent utilized in accordance with the present invention is comprised of one or more organic compounds selected from the group of ethylene glycol, propylene glycol, butylene lycol and glycol ethers such as dipropylene glycol methyl ether, dipropylene glycol ethyl ether and dibutylene glycol methyl ether. The one or more organic 30 compounds can be mixed with an alkali metal salt such as sodium chloride. A preferred fluid loss reducing and hydrate preventing agent is a mixture of sodium chloride and propylene glycol.

It has been discovered that when one or more of the above described salts and/or organic compounds are included in a well treating fluid comprised of 02/02/01.all 1670.spc.4 -4an aqueous fluid and a hydratable polysaccharide gelling agent, the fluid loss from the treating fluid in the environment of a subterranean zone is reduced and the formation of hydrates when the treating fluid has broken and been mixed with natural gas under hydrate forming conditions is prevented.

The fluid loss reducing and hydrate preventing agent utilized is generally included in a treating fluid of this invention in an amount in the range of from about 5% to about 50% by weight of aqueous fluid in the treating fluid, more preferably in an amount in the range of from about 5% to about 25% and most preferably in an amount of from about 9% to 13.5%.

The treating fluid of this invention may include a cross-linking agent to further enhance the development of viscosity by cross-linking the hydrated gelling agent. The cross-linking agent can comprise a borate releasing compound or any of the well known transition metal ions which are capable of creating a cross-linked structure with the particular gelling agent utilized. Examples of such cross-linking agents include a borate releasing compound such as sodium tetraborate, aluminium, zirconium or titanium chelates, antimony compounds and the like. The cross-linking agent can be'delayed to permit the introduction of the gelled treating fluid into a well bore before the viscosity of the gelled treating fluid significantly increases.

When used, the cross-linking agent is generally included in the treating 0 fluid in an amount in the range of from about 0.05% to about 1.5% by weight of the •0oo aqueous fluid therein, more preferably in an amount in the range of from about 0.075% to about 1% and most preferably in an amount of from about 0.7% to 0.75%.

While most viscous well treating fluids will break if given enough time at subterranean zone temperatures, it is most desirable to return the well to production as quickly as possible after a completion or stimulation treatment has been performed. That is, it is desirable to break a viscous treating fluid within 6 to S 24 hours after its introduction into a subterranean formation or zone. In order to 30 accomplish this, a gel breaker can be included in the treating fluid. Examples of suitable gel breakers which can be utilized include, but are not limited to, a mixture of sodium chlorite and a copper ion producing compound, enzymes, ammonium persulfate, sodium persulfate, acids and the like. Of these, sodium persulfate and a mixture of sodium chlorite and a copper ion producing compound are preferred.

02/02/01 .all 1670 When a delayed gel breaker is included in a viscous well treating fluid of this invention, it is generally present in an amount in the range of from about 0.001% to about 1% by weight of the aqueous fluid in the treating fluid.

A variety of other components which are well known to those skilled in the art can be included in the well treating fluids of this invention. For example, conventional additives such as pH control agents, bactericides, stabilizers, surfactants, weighting agents and the like can be included in the well treating fluids so long as they do not adversely affect other components in the treating fluids or otherwise inhibit the treatments performed therewith.

A particularly preferred viscous well treating fluid of this invention is comprised of fresh water, an unsaturated salt solution or a saturated salt solution, seawater, hydroxypropylguar gelling agent present in an amount in the range of from about .24% to about .55% by weight of the water in the treating fluid, a fluid loss reducing and hydrate preventing agent comprised of propylene glycol present in an amount in the range of from about 9% to about 13.5% by weight of water in the treating fluid, a cross-linking agent comprised of a borate releasing compound or a source of titanium ions, or both, present in an amount in the range of from about 0.05% to about 1.5% by weight of seawater in the treating fluid and a gel breaker comprised of a mixture of sodium chlorite and a copper ion producing compound present in an amount in the range of from about 0.005% to about 0.25% by weight of the water in the treating fluid.

The improved methods of the present invention for treating a subterranean zone penetrated by a well bore are comprised of the following steps.

A viscous well treating fluid of the present invention as described above is S: 25 prepared comprised of an aqueous fluid, a hydratable gelling agent and a fluid loss reducing and hydrate preventing agent. The treating fluid is pumped into the subterranean zone by way of the well bore at a rate and pressure sufficient to treat the zone. Thereafter, the treating fluid is allowed to break into a thin fluid and is S: recovered from the zone.

When the treatment performed in the subterranean zone is a fracture S stimulation treatment, the treating fluid is pumped at a rate and pressure such that S: one or more fractures are formed in the zone. In addition, a particulate solid propping agent is suspended in a portion of the treating fluid so that the proppant is deposited in thefracture or fractures. The fracture or fractures are propped 0202/01,al 11670.spc.6 open by the propping agent whereby fluid conducting channels are formed in the zone which communicate with the well bore.

As mentioned above, the treating fluid can include a cross-linking agent for increasing the viscosity of the treating fluid and/or a delayed gel breaker for causing the treating fluid to break into a thin fluid in a predictable period of time.

As also mentioned above, the viscous treating fluid of this invention has low fluid loss and if after breaking, the treating fluid mixes with natural gas from the subterranean zone under conditions of pressure and temperature whereby gas hydrates could from, such hydrate formation is prevented.

In order to further illustrate the improved well treating fluids and methods of this invention, the following example is given.

Example A test sample (Test Sample No. 1 of prior art well treating fluid was prepared comprised of fresh water, hydroxypropylguar gelling agent present in an amount of about 0.5% by weight of the water and a retarded borate cross-linking composition comprised of ulexite present in an amount of about 0.012% by weight of the water to provide a cross-linking time of from about 2 to 10 minutes. A second test sample (Test Sample No. 2) of a well treating fluid of the present invention was prepared which was identical to the first sample except that a fluid loss reducing and hydrate preventing agent of this invention comprised of propylene glycol was added to the second test sample in an amount of about 13.5% by weight of water therein, and additional cross-linker was added to maintain a cross-linking time of from about 2 to 10 minutes.

The test well treating fluid samples with and without the fluid loss reducing and hydrate preventing agent of this invention were tested for fluid loss in accordance with the following dynamic fluid loss test procedure.

S.Formation core samples were cut to fit a 1.5" diameter core holder. .*oo Each core was placed in a core holder with a 0.3" gap to allow fluid flow past the 30 core surface under dynamic test conditions. The treating fluid sample being tested was pumped through a length of 0.194" diameter tubing to provide preconditioning Sand simulate pumping shear to the treating fluid. From the 0.194" tubing, the treating fluid was caused to flow through a 0.402" diameter tubing section immersed in a heating bath.., The 0.402" tubing section simulated the lower shear 0202//01, al 11670.spc.7 rate of fluid flow in a fracture, a shear rate of about 50 sec and the treating fluid was heated to a temperature of 180°F to simulate the temperature of a subterranean zone being fractured. The sheared and heated treating fluid was then forced through a core sample in the above described core holder at a 1,000 psi pressure differential. The fluid which passed through the core sample was collected and fluid loss coefficients Cw and Spurt were determined as follows.

The fluid loss volume per area (cc/cm 3 is plotted versus time (min.

0 5 A linear regression analysis of the data is performed from the latest straight line portion of the data on the plot. The slope of the regression line and intercept are used to calculate Cw and Spurt in the following way: Cw (ft./min.

0 5 0.0164 x slope Spurt (gal./ft.

2 0.246 x intercept Each of the first and second treating fluids described above were tested for fluid loss through three separate cores having porosities of less than 200 millidarcies, between 200 and 400 millidarcies and 2,000 millidarcies, respectively.

The results of these tests are given in the Table below.

TABLE

Fluid Loss Tests Of Well Treating Fluids o.

0 0 0 00 00%.0 .0.00 0 0 0 0 .0 Core Permeability, md Test <200 200 400 2,000 Sample No.

Cw Spurt Cw Spurt Cw Spurt 1 (prior art) 0.00413 0.01198 0.00387 0.296 0.00613 10.507 2 (present 0.000424 0.0733 0.000416 0.1387 0.000359 0.7906 invention) From the Table it can be seen that the well treating fluid of the present invention has a decidedly lower fluid loss than the prior art treating fluid.

Thus, the present invention is well adapted to attain the objects and advantages mentioned as.well as those which are inherent therein. While numerous changes may be made by those skilled in the art, such changes are encompassed within the spirit of this invention as defined by the appended claims.

02/02/01.all 1670.spc,8 Where the terms "comprise", "comprises", "comprised" or "comprising" are used in this specification, they are to be interpreted as specifying the presence of the stated features, integers, steps or components referred to, but not to preclude the presence or addition of one or more other feature, integer, step, component or group thereof.

S *o *o 02/02/01,all 1670 spc.9

Claims (29)

1. An improved viscous well treating fluid comprising: an aqueous fluid; a hydratable polysaccharide gelling agent for increasing the viscosity of the aqueous fluid; and a fluid loss reducing and hydrate preventing agent selected from the group consisting of one or more of ethylene glycol, propylene glycol, butylene glycol, glycol ethers and aromatic hydrocarbons.

2. The treating fluid of claim 1 wherein said aqueous fluid is selected from the group consisting of fresh water, unsaturated salt solutions and saturated salt solutions.

3. The treating fluid of claim 1 wherein said hydratable polysaccharide gelling agent is selected from the group consisting of galactomannans, modified or derivatized galactomannans and cellulose derivatives.

4. The treating fluid of claim 1 wherein said hydratable polysaccharide gelling agent is selected from the group consisting of guar, hydroxyethylguar, hydroxypropylguar, carboxymethylguar, carboxymethylhydroxyethylguar and carboxymethylhydroxypropylguar.

5. The treating fluid of claim 1 wherein said hydratable polysaccharide gelling agent is hydroxypropylguar.

6. The treating fluid of claim 1 wherein said hydratable polysaccharide gelling agent is present in an amount in the range of from about 0.15% to about 0.75% by weight of said aqueous fluid in said treating fluid.

7. The treating fluid of claim 1 wherein said fluid loss reducing and hydrate preventing agent is selected from the group consisting of ethylene glycol, propylene glycol, butylene glycol, glycol ethers, alkali metal salts and mixtures thereof.

8. The treating fluid of claim 1 wherein said fluid loss reducing and S 30 hydrate preventing agent is a mixture of sodium chloride and propylene glycol.

9. The treating of claim 1 wherein said fluid loss reducing and hydrate preventing agent is present in an amount in the range of from about 5% to about 50% by weight of said aqueous fluid in said treating fluid. 02/02/01.all 1670 spc.

The treating fluid of claim 1 which further comprises a cross- linking agent.

11. The treating fluid of claim 10 wherein said cross-linking agent is selected from the group consisting of one or more of a borate releasing compound, a source of titanium ions, a source of zirconium ions, a source of antimony ions and a source of aluminum ions.

12. The treating fluid of claim 11 wherein said cross-linking agent is present in an amount in the range of from about 0.05% to about 1.5% by weight of said aqueous fluid in said treating fluid.

13. The treating fluid of claim 1 which further comprises a gel breaker for causing said treating fluid to break into a thin fluid.

14. The treating fluid of claim 13 wherein said gel breaker is selected from the group consisting of a mixture of sodium chlorite and a copper ion producing compound, enzymes, sodium persulfate, ammonium persulfate and acids.

The treating fluid of claim 14 wherein said gel breaker is present in an amount in the range of from about 0.001% to about 1% by weight of said aqueous fluid in said treating fluid.

16. An improved method of treating a subterranean zone penetrated by a well bore comprising the steps of: preparing a well treating fluid comprised of an aqueous liquid, a hydratable polysaccharide gelling agent and a fluid loss reducing and hydrate preventing agent selected from the group consisting of ethylene glycol, propylene glycol, butylene glycol, glycol ethers, alkali metal salts and mixtures thereof; pumping said well treating fluid into said zone by way of said well bore at a rate and pressure sufficient to treat said zone; allowing said well treating fluid to break into a thin fluid; and 30 recovering said well treating fluid from said zone. :i

17. The method of claim 16 wherein said pumping of said well treating fluid in accordance with step is at a rate and pressure such that one or more fractures are. formed in said zone. 02/02/01,all 1670 spc, 11 -11-

18. The method of claim 17 wherein said well treating fluid includes particulate solid propping agent suspended therein.

19. The method of claim 16 wherein said aqueous fluid in said treating fluid is selected from the group consisting of fresh water, unsaturated salt solutions and saturated salt solutions.

The method of claim 16 wherein said hydratable polysaccharide gelling agent in said treating fluid is selected from the group consisting of galactomannans, modified or derivatized galactomannans and cellulose derivatives.

21. The method of claim 16 wherein said hydratable polysaccharide gelling agent in said treating fluid is selected from the group consisting of guar, hydroxyethylguar, hydroxypropylguar, carboxymethylguar, carboxymethylhydroxyethylguar and carboxymethylhydroxypropylguar.

22. The method of claim 16 wherein said hydratable polysaccharide gelling agent in said treating fluid is hydroxypropylguar.

23. The method of claim 16 wherein said hydratable polysaccharide gelling agent in said treating fluid is present in an amount in the range of from about 0.15% to about 0.75% by weight of said aqueous fluid in said treating fluid.

24. The method of claim 16 wherein said fluid loss reducing and hydrate preventing agent in said treating fluid is selected from the group consisting of ethylene glycol, propylene glycol, butylene glycol, glycol ethers, alkali metal salts and mixtures thereof. .d

25. The method of claim 16 wherein said fluid loss reducing and hydrate preventing agent in said treating fluid is a mixture of sodium chloride and propylene glycol.

26. The method of claim 16 wherein said fluid loss reducing and hydrate preventing agent in said treating fluid is present in an amount in the range of from about 5% to about 50% by weight of said aqueous fluid in said treating .c fluid. 30

27. The method of claim 16 wherein said treating fluid further comprises a cross-linking agent.

28. The method of claim 27 wherein said cross-linking agent in said treating fluid is present in an amount in the range of from about 0.05% to about by weight of said aqueous fluid in said treating fluid. 02/02/01.al 1670 spc. 12 12-

29. The method of claim 16 wherein said treating fluid further comprises a gel breaker for causing said treating fluid to break into a thin fluid. The method of claim 29 wherein said gel breaker in said treating fluid is present in an amount in the range of from about 0.001% to about 1% by weight of said aqueous fluid in said treating fluid. DATED this 2 nd day of February 2001 HALLIBURTON ENERGY SERVICES, INC. By their Patent Attorneys: CALLINAN LAWRIE p WJ C *0 0 0. 0 0 Oroc 0b 0* 0*00 0 *090 0* 0 0*00 0 0 02/02/01.al11670.spc,13 13