Drilling fluid additive containing high pyruvate xanthan

A drilling fluid additive comprises high pyruvate xanthan and locust bean gum in a weight ratio of about 40:60 to 80:20. The additive increases the viscosity of the drilling fluid at low shear, has improved thermal stability, and increases the capacity of the fluid to suspend high density weighting materials.

BACKGROUND OF THE INVENTION 
The present invention is concerned with water-based fluids employed in the 
drilling of oil, gas and other wells such as geothermal wells. The 
invention is also concerned with an additive for such drilling fluids and 
with methods for drilling wells employing such fluids. 
Water-based drilling fluids, often called "drilling muds" since many 
comprise clay particles in aqueous dispersion, are commonly employed as 
follows. The fluid is pumped down a hollow drill pipe and, at high 
velocity and high shear (more than 500 sec.sup.-1), through the orifices 
or "jets" of the drill bit located at the bottom of the drill pipe. In 
this way the fluid cools and lubricates the drill bit and rapidly removes 
rock cuttings made by the cutting action of the bit. To accomplish this 
task, the fluid should ideally have little or no resistance to flow, i.e. 
low viscosity. The drilling fluid must then carry out of the bore-hole the 
rock cuttings and other solids incorporated into the drilling fluid, e.g. 
weighting materials such as barite added to the drilling fluid to increase 
its density. This is done by pumping the fluid back to the well surface at 
lower velocities and lower shear rates (less than 200 sec.sup.-1) through 
the "annulus," the hole outside the drill pipe made by the drill bit. To 
prevent cuttings, weighting materials, and other solids from slipping back 
down the annulus during both drilling and drilling interruption periods, 
the fluid should have a relatively high viscosity during this phase of the 
drilling fluid circulation. Such fluids which exhibit low viscosities 
under high shear and high viscosities under low shear are commonly called 
"pseudoplastic" fluids. 
In addition, because downhole temperatures may exceed 150.degree. F., e.g. 
may range from 150.degree. to 400.degree. F. (65.degree. to 204.degree. 
C.), the fluid's components should not degrade on exposure to these higher 
temperatures. The latter is particularly important during the drilling 
phase where successful transport of cuttings and other solids up the 
annulus depends on a fluid's capacity to yield high viscosity at low shear 
following exposure to high downhole temperatures. It should be noted that 
the drilling fluid cools significantly during its return trip to the 
surface as well as on reaching surface "mud pits" or fluid storage tanks. 
This permits the use of fluids which may lose most of their viscosity on 
brief exposure to high downhole temperatures provided substantial 
viscosity is regained on the return trip to the surface. At the surface, 
cuttings are removed, the drilling mud is cooled to near-ambient 
temperature and additional additives are mixed into the mud to restore the 
mud to initial properties. 
Many drilling fluids have been described in the art. For instance, U.S. 
Pat. No. 4,322,301 describes a water-based drilling fluid which is used at 
high drilling temperatures occurring during deep drilling. 
In general, currently used drilling fluids which employ materials other 
than clays as viscosifiers lose their low shear viscosity imparting 
properties after brief exposure to temperatures of about 300.degree. F. 
(about 150.degree. C.) or higher. Such high temperatures are commonly 
found in deep wells where weighting additives are needed to prevent the 
influx of downhole formation water into the drilling fluid as well as in 
more shallow hot wells, such as geothermal wells. In general, these same 
drilling fluids do not possess sufficient low shear viscosity to 
adequately suspend moderate levels of weighting materials (e.g. 12 lb/gal 
barite) in surface tanks where mean shear rates are substantially reduced 
(e.g. to 1-10 sec.sup.-1) and there is little "forward movement" of the 
fluid to help maintain high density weighting materials like barite in 
suspension. 
It is an object of the invention to provide a pseudoplastic drilling fluid 
having increased thermostability as well as increased capacity to suspend 
solids present during both shallow and deep well drilling. It is a further 
object of the invention to provide a drilling fluid with increased 
capacity to suspend high density weighting materials while said fluid is 
being held in a surface mud pit or storage tank. 
U.S. Pat. No. 3,557,016 describes a composition comprising Xanthomonas 
hydrophilic colloid and locust bean gum. The patent discloses a medium 
pyruvate xanthan containing medium amounts of pyruvic acid of less than 5 
percent by weight. The composition disclosed forms a gelatinous product 
with water and is utilized in the production of a variety of food 
products. Application of the composition in well drilling is not 
disclosed. 
SUMMARY OF THE INVENTION 
This invention relates to a drilling fluid additive comprising high 
pyruvate xanthan and locust bean gum, generally in a ratio ranging from 
about 40:60 to 80:20, preferably about 60:40. In accordance with the 
invention, high pyruvate xanthan is a xanthan containing a high percentage 
of pyruvic acid, generally about 5 to 9 percent by weight, preferably 
about 7 to 8 percent by weight. For comparison, medium pyruvate xanthan 
has a pyruvic acid content of about 2 to 4% more typically from 3 to 4% by 
weight. 
The invention also relates to drilling fluids containing an additive 
comprising high pyruvate xanthan and locust bean gum and to a well 
drilling process recovering water, oil, or gas from water-bearing, 
oil-bearing, or gas-containing formations by use of drilling fluids 
containing the additive comprising high pyruvate xanthan and locust bean 
gum.

DETAILED DESCRIPTION OF THE INVENTION 
The high pyruvate xanthan present in the additive of the invention may be 
prepared from the Xanthomonas fermentation broth described in U.S. Pat. 
No. 4,119,546. Other methods of obtaining the high pyruvate xanthan are 
described in the prior art, e.g. Phillips et al., Soc. Pet. Eng. Paper 
10617, Dallas, Tex., Symposium on Oil field and Geothermal Chemistry, 
January 1982. The percentage pyruvic acid in xanthan may be determined by 
standard assay described in Duckworth and Yaphe, Chem. Ind., 747 (1970). 
The blends of high pyruvate xanthan and locust bean gum are generally 
prepared by dry blending finely divided powders of each of the above 
components. The solid blend is added, as usual, by pouring into a mud 
hopper down a shoot into a mud pit equipped with a mechanical low shear 
stirrer. 
The drilling fluid additive is present in the drilling fluid in amounts 
which are conventional in the drilling industry when adding viscosity 
control additives to drilling fluids. The amounts usually range from about 
0.2 to 5 pounds per barrel of drilling fluid. One pound of additive per 
barrel of fresh water corresponds to about 2850 ppm. 
One or more other additives may be added to the drilling fluid of the 
invention. These additives are known, for instance polymeric materials, 
shale tailings, bentonite clays, weighting agents to increase the drilling 
fluid density, lubricating oil for bit lubrication, anti-scalants to 
prevent corrosion and dispersants to disperse clay particles to avoid 
aggregation thereof. Examples of known preferred weighting agents are 
barite, bentonite and iron carbonate. Preferred fluid densities of 
drilling fluids used in deep well drilling and drilling for geothermal 
wells range from 10 to 18 pounds of solids per gallon of drilling fluid. 
After circulation of the drilling fluid through the borehole and back to 
the surface, the solids suspension is passed over vibrating pans and 
filtered through a very coarse filter to separate the bigger particles of 
about 0.25 inch diameter or more. Smaller particles may be removed by 
passage of the fluid through finer filters or by centrifugation. 
After removal of these particles, the drilling fluid is passed to a mud pit 
of re-use. The viscosity of the drilling mud is measured and new additive 
is added if necessary. Different muds are used dependent on the particular 
drilling use, e.g. for deeper wells, weighting agents are generally 
necessary to prevent influx of downhole formation water into the drilling 
fluid. 
The drilling fluid additive of the invention may also be used in completion 
fluids. Before recovery of oil or gas from a well, a completion fluid is 
used for a final clean-up of the drilling pipe and bit, and for 
counteraction of formation fluid pressures downhole in the final stages 
just before the well is allowed to flow. Also, as is well-known, 
completion fluids may be used during well-bore stimulation and setting of 
production casing. 
The following Examples illustrate the properties of the drilling fluid 
additive of the invention. 
In each Example, the additive of the invention comprises 40% locust bean 
gum (LBG) and 60% high pyruvate xanthan (HPX) containing 7.8% pyruvic acis 
and the comparative additive comprises 40% locust bean gum and 60% medium 
pyruvate xanthan (MPX) containing 4% pyruvic acid. 
EXAMPLE 1 
The viscosity of North Sea brine containing an additive of the invention or 
a comparative additive was measured as a function of temperature to 
determine the thermostability of each additive. 
The North sea brine contained 3.5% total dissolved salts as follows: 
23.84 g/l NaCl 
1.24 g/l CaCl.sub.2 
10.76 g/l MgCl.sub.2.6H.sub.2 O 
4.29 g/l Na.sub.2 SO.sub.4 
0.21 g/l NaHCO.sub.3 
FIG. 1 presents the curve resulting from plotting the viscosities in 
centipoises against the temperature in degrees Fahrenheit. 
The viscosity was measured at a constant shear of 100 rpm (170 sec.sup.-1) 
with a Fann 50 HT viscometer. The brine solutions were heated from 
75.degree. F. (24.degree. C.) to 300.degree. F. (149.degree. C.) over one 
hour and then cooled to 75.degree. F. over 25 minutes. The viscosities 
were measured at the temperatures indicated in FIG. 1. 
The viscosity control additive of the invention and the comparative 
additive were used each in an amount of 1 pound per barrel (2850 ppm) of 
North Sea brine. 
At 75.degree. F., the additive of the invention imparted a viscosity of 40 
cps and the comparative additive imparted a viscosity of 22 cps. At 
300.degree. F., the viscosities of the fluids were both virtually zero. On 
subsequent cooling to 75.degree. F., the original viscosity of the brine 
containing the additive of the invention was regained whereas there was 
74% viscosity regain for the brine containing the comparative additive. 
Thus, the blend containing medium pyruvate xanthan gum was less thermally 
stable. The drilling fluid containing the additive of the invention can be 
used again since there is virtually no loss of viscosity on cooling after 
heating. 
EXAMPLE 2 
The viscosity effectiveness at low shear was measured for the additive of 
the invention and the comparative additive. The viscosities of the 
different brines having the different additives are listed in Table 1. The 
viscosity was measured in a Brookfield LVT viscometer, spindle No. 1, at 
1.5 rpm (about 0.3 sec..sup.-1) at 25.degree. C. 
The synthetic seawater was water containing 3.5% total dissolved salts. The 
high hardness synthetic brine contained 7.3% total dissolved salts in 
water and had the following salt composition: 
64.22 g/l NaCl 
5.51 g/l CaCl.sub.2 
7.23 g/l MgCl.sub.2.6H.sub.2 O 
0.01 g/l BaCl.sub.2.2H.sub.2 O 
0.14 g/l NaHCO.sub.3 
The data below clearly show that the viscosity of the solutions containing 
the additive of the invention was substantially higher than the viscosity 
of the same solutions containing the comparative additive. 
The additives were added in a concentration of 1 pound per barrel of brine. 
TABLE 1 
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Viscosity 
Sample Brine (cps) 
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60/40 HPX/LBG 
Synthetic Seawater 3320 
60/40 MPX/LBG 
" 480 
60/40 HPX/LBG 
High hardness synthetic brine 
2440 
60/40 MPX/LBG 
" 560 
60/40 HPX/LBG 
Distilled Water 7100 
60/40 MPX/LBG 
" 1000 
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EXAMPLE 3 
The suspension capabilities of the additive of the invention and the 
comparative additive were determined. 
A 500 ml sample was taken from a barite suspension containing 12 pounds of 
barium sulfate per gallon of brine and 1 pound of the additive per barrel 
of brine. 
The density of the top 100 ml of the 500 ml sample suspension was 
determined and the density was again measured after aging of the 
suspension for 84 hours at room temperature. 
The HPX-containing suspension did not show any change in density on aging 
evidencing that no settling of the barite had occurred. 
The MPX-containing suspension showed a decrease in density from 1.44 to 
1.01 g/cc in deionized water evidencing almost total settling of the 
barium sulfate. The MPX-containing suspension showed a decrease in density 
from 1.44 to 1.19 g/cc in 26% by weight NaCl solutions evidencing almost 
total settling, the density of 26% by weight NaCl being about 1.2 g/cc. 
TABLE 2 
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Density (g/cc) 
Sample Brine Initial After 84 hours 
______________________________________ 
60/40 HPX/LBG 
Deionized Water 
1.43 1.43 
60/40 MPX/LBG 
" 1.44 1.01 
60/40 HPX/LBG 
26% w/w NaCl 1.43 1.43 
(saturated) 
60/40 MPX/LBG 
26% w/w NaCl 1.44 1.19 
(saturated) 
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