Well completion and workover method

A well completion and workover method wherein a subterranean formation is contacted with a high density, nondamaging treating fluid which comprises a saturated, aqueous solution having finely divided particles of a water soluble salt suspended therein. The saturated aqueous saline solution should have a density of at least about 1.2 g/cc and the suspended salt particles should be present in sufficient quantities to substantially increase the overall density of the treating solution. The preferred fluid comprises a suspension of pulverized sodium chloride in a saturated calcium chloride solution. Dispersants and viscosifiers can be added in minor amounts to help maintain the salt particles in suspension.

BACKGROUND OF THE INVENTION 
1. Field of the Invention 
This invention generally relates to the drilling and servicing of wells in 
subterranean formations. In one aspect, it relates to contacting 
subterranean formations with aqueous well completion and workover fluids 
which are used in the drilling and servicing of wells. 
2. Description of the Prior Art 
In the drilling of a well into a subterranean formation, it is necessary to 
cool the drill bit as it cuts into the formation and to remove drill 
cuttings away from and out of the borehole. A drilling fluid, therefore, 
is normally circulated downwardly, through the drill pipe, outwardly 
through nozzles located in the drill bit and upwardly through the wellbore 
annulus to the surface. Most drilling fluids, commonly referred to as 
drilling muds, contain suspended particles of hydrated clay in water. Clay 
based fluids, in addition to cooling the drill bit and transporting 
cuttings, prevent cave-ins in poorly consolidated wellbores and gas 
blowouts in high pressure formations. The colloidal properties of the 
suspended clay, such as high gel strength and high density, contribute 
significantly to the functions performed by the clay based drilling 
fluids. A weighting material such as barite is frequently added to the 
drilling fluid to increase its density so that formation pressures can be 
contained. 
During the well completion phase of the drilling operation, when the drill 
bit bores through the producing interval, the insoluble materials of the 
drilling mud, such as clay and barite, cause a filter cake to be laid down 
on the formation face. Such a filter cake or sheath tends to seal off the 
formation and may result in a permanent reduction in the permeability of 
the producing interval. The embedded clay and barite particles can 
sometimes be removed by acidization. However, even expensive acid 
treatments are frequently unable to overcome well damage because clay and 
barite solids have low solubility in acid. 
To avoid impairment of permeability, it is necessary to use a "clean" 
drilling fluid which will not damage the formation but which has 
sufficient density to contain formation pressures. Similarly, during well 
servicing and workover operations, such as gravel packing, in which a 
permeable, production interval will be contacted with a workover fluid, it 
is also desirable to employ a dense but nondamaging fluid. 
Commonly used nondamaging fluids are high density, aqueous saline solutions 
such as saturated calcium chloride solutions. Although calcium chloride 
solutions are nondamaging, they possess a maximum density of only 1.38 
g/cc (11.5 pounds per gallon) and may not be suitable for all well 
treatment operations. Mixtures of calcium bromide and calcium chloride 
solutions can achieve densities as high as 1.81 g/cc (15.1 pounds per 
gallon), but such mixtures are very costly. Blends of calcium chloride 
solutions with other high density solutions such as sodium nitrate, 
calcium nitrate, and zinc chloride have been proposed, but these solutions 
are highly corrosive and require the addition of expensive inhibitors. In 
addition, such solutions may be environmentally hazardous. 
The addition of insoluble, suspended solids, such as calcium carbonate, can 
be used to increase the density of aqueous saline solutions, but these 
solids can invade the formation and can result in the same type of 
formation permeability damage which is caused by the clay based fluids. 
Thus, there is a need for a high density, nondamaging well completion and 
workover fluid. 
SUMMARY OF THE INVENTION 
The present invention broadly comprises an improved well completion and 
workover method wherein a subterranean, hydrocarbon-producing formation is 
contacted with a high density, nondamaging treating fluid. The treating 
fluid comprises a saturated, aqueous saline solution having a density of 
at least about 1.2 g/cc (10.0 pounds per gallon) at 10.degree. C. 
(50.degree. F.) and having finely divided particles of a water soluble 
salt suspended therein. The suspended salt particles should be added in 
sufficient quantities to substantially increase the overall density of the 
treating fluid. 
One such fluid is a suspension of pulverized sodium chloride particles in a 
saturated solution of calcium chloride. Whereas a solution of calcium 
chloride has a maximum density of 1.38 g/cc (11.5 pounds per gallon), a 
suspension of sodium chloride in a saturated calcium chloride solution can 
be prepared which has a density as high as 1.68 g/cc (14.0 pounds per 
gallon). 
Contacting a formation with the fluids of the present invention will not 
cause any permanent well damage. Should any of the salt particles, 
suspended in the fluid, invade and plug the formation, they can be readily 
dissolved by the flow of produced field brine or by the injection of water 
or an unsaturated saline solution. 
Preferably, the average size of the suspended salt particles should be less 
than about 10 microns. Pulverized particles of that size are more readily 
suspended in the aqueous saline solution and will be easily dissolved 
should they invade the formation. It is also preferable to add chemical 
agents to the fluids of the present invention to help maintain the finely 
divided salt particles in suspension. Dispersants and water soluble 
polymers are especially useful in preventing settling of the salt 
particles.

DESCRIPTION OF THE PREFERRED EMBODIMENTS 
The well completion and workover fluids useful for the purposes of the 
present invention are essentially aqueous slurries comprising suspensions 
of finely divided particles of a water soluble salt suspended in a 
saturated aqueous saline solution. Such slurries form high density, 
nondamaging well completion and workover fluids. Since the aqueous 
solution is saturated to begin with, the particles of the water soluble 
salt will remain in suspension almost indefinitely, especially if there 
are ions which are common to the solution and the suspended salt 
particles. Thus, a saturated solution of calcium chloride will be unable 
to dissolve suspended particles of sodium chloride without the concurrent 
precipitation of calcium chloride. The ionic equilibration, however, will 
proceed very slowly and the slurry will remain stable for a long period of 
time. 
The suspended salt particles behave as nondamaging weighting agents. Unlike 
particles of calcium carbonate, clay or barite, the suspended salt 
particles used in the method of the present invention are water soluble 
and can be subsequently removed from the formation should the particles 
become lodged in the formation. Thus, the particles can cause no permanent 
damage to formation permeability. Field brine, which normally flows from a 
producing formation, is usually well below the salt saturation level and 
will dissolve any residual particles of salt remaining in the formation 
after a well treatment operation. In most instances, the produced field 
brine will effectively dissolve the residual salt particles it comes in 
contact with. However, if no brine is produced from the well (as, for 
example, in a gas well) the water soluble salt particles can be easily 
removed by spotting the formation with water or unsaturated brine. 
Any water soluble salt can be selected as the weighting agent. However, the 
salt which is highly preferred for the present invention is sodium 
chloride. Sodium chloride is inexpensive, abundant and very water soluble. 
Furthermore, it is the major salt component of field brine and sea water 
and is, therefore, ecologically desirable for both onshore and offshore 
well completions and workovers. 
It is highly preferred to use salt particles that are very finely divided 
since the finer the particle size, the greater the amount of salt which 
can be suspended in the saturated solution. Smaller particles are also 
more readily dissolved should they invade the formation. 
Finely divided sodium chloride can be made using conventional pulverization 
techniques. For example, in jet pulverization, coarse sodium chloride 
particles are fluidized in a vessel and are impinged with two high 
velocity jets of air which cause the particles to collide with one another 
with sufficient impact to promote pulverization of the particles. A 
product of desired particle size distribution is then withdrawn from above 
the fluidized zone. Other commercial size reduction processes can also be 
used to obtain the properly sized comminuted particles. For purposes of 
the present invention, the pulverized salt particles should have an 
average size of under about 10 microns and substantially all (99.9%) of 
the particles should be under 25 microns. As a basis of comparison, 
ordinary table salt has an average particle size of nearly 200 microns. 
The saturated solution component of the fluid of the present invention can 
be selected from any of the aqueous saline solutions which are commonly 
used for well completions and workovers. The salt used in the preparation 
of the solution should have substantial solubility in water so that a 
density of at least about 1.2 g/cc (10.0 pounds per gallon) can be 
attained. Saturated solutions of sodium chloride, calcium chloride, 
potasssium chloride, zinc chloride, calcium bromide, calcium nitrate and 
sodium nitrate are all possible candidates. However, as previously 
mentioned, calcium nitrate, sodium nitrate and zinc chloride solutions are 
avoided where possible because of their corrosive nature and the possible 
adverse environmental hazards which they pose. The solutions which are 
usually selected are saturated solutions of calcium chloride, calcium 
bromide and sodium chloride or mixtures thereof. 
Sodium chloride solutions are the least expensive but will yield a maximum 
density at saturation of only about 1.2 g/cc (10.0 pounds per gallon) at 
10.degree. C. This should be the lower density limit of the saturated 
solutions selected for use in the present invention. The perferred 
solution for purposes of the present invention is a saturated solution of 
calcium chloride which has a density of 1.38 g/cc (11.5 pounds per 
gallon). This solution also offers the advantage of being relatively 
inexpensive. A saturated calcium bromide solution is very dense but has 
the disadvantage of having a high freezing point. However, mixtures of 
calcium bromide and calcium chloride solutions can be formulated with 
densities as high as 1.91 g/cc (15.1 pounds per gallon) and with freezing 
points below 20.degree. C. (68.degree. F.). 
As previously mentioned, sodium chloride, being a major component of field 
brine and sea water, is environmentally safe. Calcium chloride and calcium 
bromide solutions are also desirable from an environmental standpoint. In 
addition to being safe to use and handle on land, they are also well 
suited for use offshore since both calcium chloride and calcium bromide 
are present in sea water in small quantites. Therefore, accidental 
spillage of either salt solution into offshore waters will cause no 
damage. Heavy calcium chloride and calcium bromide brines also exhibit low 
corrosivity rates and will not significantly damage drilling equipment. 
To minimize any corrosivity problems associated with the saline solution 
component used in the method of the present invention, it is preferable to 
add small quantities of a corrosion inhibitor to the saline solution. 
Inhibitors, such as ethylene oxidized organics, act as oxygen scavengers 
and thereby reduce corrosivity rates. A preferred inhibitor is a water 
soluble mixture of organic inhibitors which is manufactured by Exxon 
Chemical under the tradename of Corexit 7720. A concentration of about 
5000 parts per million is recommended when the saline solution is utilized 
as a packer fluid or when it will be left in the wellbore for extended 
periods of time. A pH of between about 3 and 11 is generally preferred 
when the well completion or workover fluid is to remain in contact with 
tubular well equipment. 
A preferred well completion and workover fluid for use in the method of the 
present invention is a combination of the two preferred components, i.e., 
a saturated solution of calcium chloride having pulverized particles of 
sodium chloride suspended therein. Such a slurry is inexpensive and can 
have a density as high as 1.68 g/cc (14.0 pounds per gallon). It is almost 
totally nondamaging and exhibits a very low corrosivity rate. Another 
useful fluid is a suspension of particles of sodium chloride in a 
saturated sodium chloride solution. This fluid has a density as high as 
1.5 g/cc (12.5 pounds per gallon) and is very inexpensive, and since the 
sodium chloride is present in both the saturated solution and the 
particles, the fluid is in permanent ionic equilibrium. A slightly 
expensive, but highly dense fluid, can be prepared by suspending sodium 
chloride particles in a mixture of saturated solutions of calcium chloride 
and calcium bromide. The density of such a solution can be made as high as 
2.1 g/cc (17.5 pounds per gallon). 
The suspended salt particles are, therefore, effective weighting agents 
which, when added in sufficient quantities, significantly increase the 
density of the treating fluid. For example, effectively suspended sodium 
chloride particles contribute as much as 0.3 g/cc (2.5 pounds per gallon) 
to the overall density of the fluid. Naturally, the density increase will 
depend on the type of water soluble salt selected, the amount of salt used 
and the suspensive properties of the saturated aqueous solution. 
It should be pointed out, however, that adding salt particles to the 
saturated solution will increase its viscosity as well as its density. The 
drawing is a plot of viscosity at 511 reciprocal seconds versus density 
for slurries of sodium chloride suspended in saturated calcium chloride 
solutions. The drawing shows that viscosity rapidly increases at a density 
of around 1.60 g/cc for the fluid. The avoidance of pumping difficulties 
resulting from increased viscosity may, therefore, place an upper limit on 
the amount of salt particles which can be used. For example, in the 
preferred solution of sodium chloride particles suspended in saturated 
calcium chloride, it is probably desirable to maintain density at not more 
than about 1.60 g/cc (13.3 pounds per gallon). 
Altering the rheological properties of the saturated saline solution by 
adding chemical agents is a preferred technique for increasing the amount 
of salt which can be suspended in the solution. The addition of 
dispersants and viscosifiers (such as water soluble polymers) can 
significantly increase the amount of salt particles which can be 
maintained in suspension for long or indefinite periods of time. 
Dispersants which can be used include sodium salts of alkyl naphthalene 
sulfonic acid and polymerized carboxylic acid, polyphosphate acid esters 
and nonylphenyl polyethylene glycol ethers. Generally, any of the 
commercially sold dispersants which help disperse particles in aqueous 
media and which prevent preflocculation are suitable for the fluid of the 
present invention. 
Viscosifiers useful in the present invention include synthetic water 
soluble polymers such as acrylic and vinyl polymers and the cellulose 
derivatives such as hydroxyethylcellulose and carboxymethylcellulose. Also 
suitable are the natural gums such as quar gum, gum arabic, gum tragacanth 
and the microbial fermentation gums such as dextran and xanthomonas gum. 
Tests were conducted to determine a preferred suspending agent for the 
fluids of the present invention. Dispersants and viscosifiers were tested 
individually and in combination. The most effective product was a 
combination of xanthomonas gum and Visco 950. Visco 950 is the tradename 
for a polyphosphate acid ester which is manufactured and sold commercially 
by Nalco Inc. A weight ratio of 1 part xanthomonas gum to 3 parts Visco 
950 was found to be the preferred mixture, but weight ratios of from 1 to 
5 to about 1 to 1 will provide adequate suspension. Only minor amounts of 
the suspending agents need be added to the slurry. For example, 1000 
pounds of a saturated calcium chloride solution containing 2 pounds of 
xanthomonas gum and 6 pounds of Visco 950 would be able to suspend, in a 
stable slurry, over 450 pounds of sodium chloride to form a fluid having a 
density of 1.6 g/cc (13.3 pounds per gallon), thereby keeping viscosity at 
around 200 centipoises. 
The nondamaging fluids mentioned above can be used in any number of well 
treatments where it is necessary to contact the formation with a fluid 
which will not permanently impair well permeability. For example, in the 
well completion phase of a drilling operation, the fluids used in the 
present invention would be substituted for conventional drilling muds. 
A suspension of sodium chloride particles in a saturated sodium chloride or 
calcium chloride solution could be prepared in advance and stored in tanks 
or drums. If the slurry is stabilized with a dispersant and viscosifier it 
can be stored almost indefinitely until needed. 
When the producing interval is reached, the slurry would be used in the 
same manner as a drilling mud, i.e., downward circulation through the 
drill string, outwardly through the drill bit nozzles and upwardly through 
the wellbore annulus to the surface. The slurry prepared in accordance 
with the present invention should have sufficient density to provide a 
hydrostatic head which can contain formation pressures and should be 
formulated to have such a density. 
If the particles of sodium chloride or other soluble salt are, as 
suggested, very fine (under 25 microns) then the slurry can be passed 
through conventional mud cleaning equipment to remove drill cuttings. The 
most thorough mud cleaning equipment available will only separate 
particles having a size of 50 microns or greater. Therefore, conventional 
mud cleaning equipment such as shale shakers and desilters will separate 
most drill cuttings from the fluids of the present invention without the 
concurrent loss of suspended salt particles, thereby permitting 
recirculation of the fluid. 
Similarly, the fluids used in the present invention can be used for all 
types of well servicing and workover operations. Dense fluids are 
frequently needed for such operations because it is necessary to maintain 
a wellbore pressure of 200 to 300 psi above reservoir pressure. 
Furthermore, well servicing and workover operations such as gravel 
packing, well killing, cleaning out, and perforating require very "clean," 
nondamaging fluids because such operations tend to cause extensive contact 
of the fluid with the producing zone of the formation. Unless the workover 
fluid is nondamaging, formation permeability will invariably be impaired. 
Thus the fluids used in the present invention are ideally suited for such 
operations. 
The principle of the invention and the best mode in which it is 
contemplated to apply the principle have been described. It is to be 
understood that the foregoing is illustrative only and that other means 
and techniques can be employed without departing from the true scope of 
the invention.