Method and composition for controlling fluid loss in high permeability hydrocarbon bearing formations

A chemical system and method to stop or minimize fluid loss during completion of wells penetrating hydrocarbon formations are provided. The inventions relates to formulating a highly stable crosslinked hydroxyethyl cellulose (HEC), control released viscosity reduction additives, and user friendly packaging. The chemical system contains a linear HEC polymer solution, a low solubility compound which slowly raises the fluid pH, a chelating agent which further increases the pH level beyond the equilibrium achievable by the low solubility compound, a metal crosslinker which crosslinks HEC at elevated pH, a crosslink delaying agent which allows fluid viscosity to remain low until the fluid reaches the subterranean formation, and optionally an internal breaker. The chemical additives are packaged as an integrated pallet and transported to a field location which allows operators to conveniently mix them before pumping. There is also provided a dry granulated crosslinked polysaccharide for use as a fluid loss control agent.

FIELD OF THE INVENTION 
In one aspect, the present invention relates to novel fluid loss control 
agents for use in drilling, completion and stimulation fluids. More 
particularly, the present invention relates to the use of a dry 
crosslinked polymer particulate system to form a filter-cake to reduce 
treatment fluid loss to permeable formations. In another aspect, the 
present invention relates to a chemical system for use in providing a 
crosslinked polymer pill to form a filter-cake to reduce treatment fluid 
loss to permeable formations, wherein the chemical system is preferably 
palletized. 
BACKGROUND 
During the drilling of an oil well, a usually aqueous fluid is injected 
into the well through the drill pipe and recirculated to the surface in 
the annular area between the wellbore wall and the drill string. The 
functions of the drilling fluid include: lubrication of the drill bit, 
transportation of cuttings to the surface, overbalancing formation 
pressure to prevent an influx of oil, gas or water into the well, 
maintenance of hole stability until casings can be set, suspension of 
solids when the fluid is not being circulated, and minimizing fluid loss 
into and possible associated damage/instability to the formation through 
which drilling is taking place. 
Proper overbalancing of formation pressure is obtained by establishing 
fluid density at the desired level usually via the addition of barite. 
Transportation of cuttings and their suspension when the fluid is not 
circulating is related to the fluid viscosity and thixotropy which depend 
on solids content and/or use of a polymer. Fluid loss control is obtained 
also by the use of clays and/or added polymers. 
Fluid properties are constantly monitored during the drilling operations 
and tailored to accommodate the nature of the formation stratum being 
encountered at the time. When drilling reaches the producing formation 
special concern is exercised. Preferentially, low solids content fluids 
are used to minimize possible productivity loss by solids plugging. Proper 
fluid density for overbalancing formation pressure may be obtained by 
using high salt concentration aqueous brines while viscosity and fluid 
loss control generally are attempted by polymer addition, and/or soluble 
particulates such as calcium carbonate or size salt in saturated brine 
solution. 
When high permeability and/or poorly consolidated formations are penetrated 
as the zone of interest, a technique referred to as "under-reaming" often 
is employed in the drilling operations. In this process, the wellbore is 
drilled through the hydrocarbon bearing zone using conventional techniques 
and drilling muds. A casing generally is set in the well bore to a point 
just above hydrocarbon bearing zone. The hydrocarbon bearing zone then is 
redrilled using an expandable bit that increases the diameter of the hole. 
The purpose of the under-reaming is to remove damage from the permeable 
formation introduced during the initial drilling process by particles of 
the drilling mud and to increase the exposed surface area of the wellbore. 
Typically, under-reaming is effected utilizing special "clean" drilling 
fluids to minimize further formation damage. The high permeability of many 
hydrocarbon zones allows large quantities of the clean drilling fluid to 
be lost to the formation. Typical fluids utilized in under-reaming 
comprise expensive, aqueous, dense brines which are viscosified with a 
gelled or crosslinked polymer to aid in the removal of the drill cuttings. 
Such dense brines have been reported as being difficult to unload from 
formations once losses have occurred. Calcium and zinc-bromide brines can 
form highly stable, acid-insoluble compounds when reacted with some 
formation brines. Because of the high density of these brines, 
stratification tends to further inhibit the removal. The most effective 
means of preventing this type of formation damage is to limit completion 
brine losses to the formation. 
Providing effective fluid loss control without damaging formation 
permeability in completion operations has been a prime requirement for an 
ideal fluid loss-control pill. Conventional fluid loss control pills 
include oil-soluble resins, calcium carbonate, and graded salt fluid loss 
additives have been used with varying degrees of fluid loss control. These 
pills achieve their fluid loss control from the presence of 
solvent-specific solids that rely on filter-cake build up on the face of 
the formation to inhibit flow into and through the formation. However, 
these additive materials can cause severe damage to near-wellbore areas 
after their application. This damage can significantly reduce production 
levels if the formation permeabilities is not restored to its original 
level. Further, at a suitable point in the completion operation, the 
filter cake must be removed to restore the formation's permeability, 
preferably to its original level. 
A major disadvantage of using these conventional fluid loss additives is 
the long periods of clean up required after their use. Fluid circulation, 
which in some cases may not be achieved, is often required to provide a 
high driving force, which allows diffusion to take place to help dissolve 
the concentrated build up of materials. Graded salt particulates can be 
removed by circulating unsaturated salt brine to dissolve the particles. 
In the case of a gravel pack operation, if this occurs before gravel 
packing, the circulating fluid often causes sloughing of the formation 
into the wellbore and yet further loss of fluids to the formation. If 
removal is attempted after the gravel pack, the gravel packing material 
often traps the particles against the formation and make removal much more 
difficult. Other particulates, such as the carbonates can be removed with 
circulation of acid, however, the same problems may arise. Oil-soluble 
resins, carbonate and graded salt particulate will remain isolated in the 
pores of the formation unless they are in contact with solvent. In the 
cases where the solid material cover a long section of wellbore, the rapid 
dissolution by solvent causes localized removal. Consequently, a thief 
zone forms and the majority of the solvent leaks through the thief zone 
instead of spreading over the entire wellbore length. 
The use of conventional gel pills such as linear viscoelastic or heavy 
metal-crosslinked polymers in controlling fluid loss requires pumping the 
material through large-diameter tubing because of high friction pressures. 
These materials are typically prepared at the well site. 
Among the linear polymers used to form fluid loss control pills is 
hydroxyethylcellulose (HEC). HEC is generally accepted as a polymer fluid 
affording minimal permeability damage during completion operations. 
Normally, HEC polymer solutions do not form rigid gels, but control fluid 
loss by a viscosity-regulated mechanism. Such polymer fluids may penetrate 
deeper into the formation than crosslinked polymers. Permeability damage 
may increase with increasing penetration of such viscous fluids. 
According to conventional wisdom, in high permeability reservoirs, a highly 
crosslinked gel is needed to achieve good fluid loss control. Though HEC 
is known for its low residue content, it is difficult to crosslink 
particularly in regards to on-site or in situ formulations. However, 
according to M. E. Blauch et al. in SPE 19752, "Fluid Loss Control Using 
Crosslinkable HEC in High-Permeability Offshore Flexure Trend 
Completions," pages 465-476 (1989), while there are chemical methods to 
crosslink standard HEC, these methods have generally been found to be 
inapplicable to most completion practices. 
Therefore, much effort has been expended to modify HEC to make it more 
easily crosslinkable, which adds to the expense and in some cases 
complexity of such systems. U.S. Pat. No. 4,552,215 to Almond et al. 
discloses a cellulose ether which is chemically modified to incorporate 
pendant vicinal dehydroxy groups which assume or can assume cis geometry. 
These modified celluloses can be crosslinked by zirconium (IV) metal ions 
and are useful for fluid loss control. 
In SPE 29525, "A New Environmentally Safe Crosslinked Polymer for Fluid 
loss Control," pages 743-753 (1995), R. C. Cole et al. disclosed a polymer 
which has been prepared by grafting crosslinkable sites onto an HEC 
backbone. The polymer can be transformed into a rigid, internally 
crosslinked gel if the pH of the solution is adjusted from acidic to 
slightly basic through the use of a non-toxic metal oxide crosslinker. No 
divalent or trivalent metals are associated with the polymer or included 
in its crosslinking chemistry. The crosslinking is effected by the use of 
a slowly soluble, non-toxic metal oxide. The resulting crosslink fluid is 
said to demonstrate shear-thinning and rehealing properties that provide 
for easy pumping. The rehealed gel is said to provide good fluid loss 
control upon placement. The polymer is referred to as a double-derivatized 
HEC (DDHEC). Instead of being a dry polymer in a bag, the DDHEC is a 
dispersion in an environmentally safe, non-aqueous, low-viscosity carrier 
fluid. The non-flammable carrier fluid is initially soluble in most 
brines. Hydration occurs only at specific, highly acidic conditions. At 
near neutral pH, the DDHEC polymer is dispersed into the mixing brine. 
When required, the pH is lowered, encouraging hydration to rapidly occur. 
In SPE 36676, "Development and Field Application of a New Fluid Loss 
Control Material," pages 933-941 (1996), P. D. Nguyen et al. disclosed 
grating crosslinked, derivatized hydroxyethylcellulose (DHEC) into small 
particulates kept in a brine solution. Details of the chemistry and 
properties of the ungrated crosslinked DHEC were described in SPE 29525 
discussed above. In SPE 36676, crosslinked DHEC was placed in a pressure 
chamber to which a perforated disk, cylinder or screen was attached to its 
end. Air was introduced at the other end of the pressure chamber to push 
the crosslinked material into and through the grating device and shredded. 
The shredded material is provided as a slurry concentrate and is said to 
be stable enough to store in this form. The slurry concentrate is then 
dispersed in a completion fluid. 
U.S. Pat. No. 5,372,732 to Harris et al. discloses a dry, granulated, 
delayed crosslinking agent for use as a blocking gel in a workover 
operation comprising a borate source and a water-soluble polysaccharide 
comprising at least one member selected from the group of guar gum, 
hydroxypropylguar and carboxymethylhydroxypropylguar. The blocking gel 
forms a relatively impermeable barrier cordoning off the production zone 
from the area undergoing the workover operation. The crosslinking agent is 
prepared by dissolving one of the water-soluble polysaccharides identified 
above in an aqueous solution. To the aqueous solution is added a borate 
source to form a crosslinked polysaccharide. The borate-crosslink 
polysaccharide is then dried and granulated. The delayed crosslinking 
agent is admixed with an aqueous gel containing a second-water soluble 
polysaccharide solution. As is well known in the art, the borate crosslink 
is a reversible crosslink in that the borate/polymer crosslink at basic pH 
is in equilibrium with the borate ion and polymer crosslink sites (i.e., 
cis oriented hydroxyl groups), wherein the borate ion detaches from one 
site and then reattaches to another or the same site of the same or 
different polymer. Such crosslinked polymers are said to be self-healing 
since if the crosslink is broken it will reform at the same or different 
location. However, it is also known that HEC is not crosslinkable with 
borates. This is one reason why HEC has been derivatized by others to 
incorporate hydroxyl groups which can be in a cis orientation relative to 
one another. 
Thus, there is a need to be able to use unmodified HEC in fluid loss 
control situations to thereby avoid the cost associated with derivatizing 
HEC for use in such systems. There is also a need to reduce the complexity 
of such systems for ease of use at a field site, preferably without the 
use of a chemist to prepare the fluid loss control pill composition. 
Further, there is also a need for a reliable viscous fluid loss control 
system containing no conventional fluid loss control solids. 
SUMMARY OF THE INVENTION 
In one aspect of the invention, there is provided a dry crosslinked polymer 
particulate system which can be quickly spotted into a wellbore to control 
fluid loss. The dry crosslinked polymer particulate system may be used as 
a fluid loss control agent, for example, during drilling, completion, 
workover and stimulation operations. Examples of stimulation operations 
include hydraulic fracturing, fracture acidizing and matrix acidizing. The 
material is easily mixed and pumped on location. The particulate system 
bridges the formation face and rehydrate in situ to form a filter-cake. 
The particulate system is prepared by first making a batch of crosslinked 
gel, shredding the crosslinked gel into small particles by extrusion, 
coating the shredded particles with a polymer powder, hardening the coated 
particles by drying, and then grinding the hardened particles into fine 
grained material. The polymer to be crosslinked can be guar, derivatized 
gars, cellulose and derivatized celluloses, e.g., hydroxyethylcellulose 
and derivatized hydroxyethylcellulose. The crosslinking agents are those 
that provide zirconium, titanium, aluminum or antimony ions. The 
crosslinked gel can be extruded and shredded through a perforated disk, 
cylinder or screen and, preferably, tumbled in a polymer powder-filled 
roller tank. Preferably, the polymer powder is of the same polymer to be 
crosslinked. The material can be coated with the polymer powder and dried 
at the same time. The lumped dry particles can then be ground into fine 
particles or granules having a size of from about 10 to about 200 meshes 
on the U.S. Sieve Series. The fine particles can be added to a blender 
tank on location. These particles do not hydrate and thicken the water 
immediately, hence low friction pressure is observed while pumping. An 
advantage of this system is that the material behaves as a solid fluid 
loss control material, such as the often used carbonate pill, but the 
particles form a tighter network on the face of the rock once they start 
to hydrate and expand. There is no solid invasion and permanent formation 
damage like that usually associated with the calcium carbonate pills. 
In another aspect of the present invention, a chemical system and method to 
stop fluid loss during the completion or workover of wells penetrating 
hydrocarbon formations are also provided. The invention relates to 
formulating a highly stable crosslinked hydroxy ethyl cellulose (HEC), 
control released viscosity reduction additives, and, preferably, user 
friendly packaging. The chemical system contains a linear HEC polymer 
solution, a low solubility compound which slowly raises the fluid pH, a 
cheating agent which further increases the pH level beyond the equilibrium 
level achievable by the low solubility compound, a metal crosslinker which 
crosslinks HEC at elevated pH, and a crosslinking delaying agent which 
allows fluid viscosity to remain low until the fluid reaches the 
subterranean formation. Preferably, the components of the chemical system 
are packaged as an integrated pallet and transported to the field location 
which allows an operator to conveniently mix these components before 
pumping. Transition metal ions such as titanium and zirconium ions are 
used to crosslink the HEC fluid system. Difficulty in forming stable 
crosslinks on HEC linear chains has limited its application in the oil 
field completion as stimulation operations of the past. The titanium 
crosslinked systems may under certain conditions suffer shear and thermal 
instability. Therefore, a zirconium compound which yields zirconium ions 
at pH levels of 8 and greater is a preferred choice as a crosslinking 
agent. In a preferred embodiment, the crosslinker used in the system is a 
zirconium compound, the slow pH raising compound is magnesium oxide, the 
cheating agent is tetrasodium ethylenediaminetetra-acetate (Na.sub.4 
EDTA), and the crosslinking delaying agent is sodium lactate. As a result, 
a highly rigid gel is formed by these chemicals. Various oxidizing 
breakers and catalysts may be applied to produce the most effective 
viscosity reduction at specific temperatures. 
In this aspect of the invention, all the components of the chemical system 
preferably are premeasured and organized onto a palletized package, which 
may also contain easy-to-follow mixing instructions so that equipment 
operating personnel can perform the well treatment without having to have 
extensive chemical knowledge about the materials. Preferably, an on-site 
quality control kit is also included.

DETAILED DESCRIPTION OF THE INVENTION 
In one aspect of the present invention, a chemical system and method to 
stop fluid loss during completion and workover of wells penetrating 
hydrocarbon formations are provided. The invention relates to formulating 
a highly stable crosslinked hydroxy ethyl cellulose (HEC), control 
released viscosity reduction additives, and user friendly packaging. The 
chemical system contains a linear HEC polymer solution, a low solubility 
compound which slowly raises the fluid pH, a cheating agent which further 
increases the pH level beyond the equilibrium level achievable by the low 
solubility compound, a metal crosslinker which crosslinks HEC at elevated 
pH, and a crosslinking delaying agent which allows fluid viscosity to 
remain low until the fluid reaches the subterranean formation. Preferably, 
the components of the chemical system are packaged as an integrated pallet 
and transported to the field location which allows an operator to 
conveniently mix these components before pumping. Transition metal ions 
such as titanium and zirconium ions are used to crosslink the HEC fluid 
system. Difficulty in forming stable crosslinks on HEC linear chains has 
limited its application in the oil field completion and stimulation 
operations of the past. Under certain conditions, the titanium crosslinked 
systems may suffer shear and thermal instability. Therefore, a zirconium 
compound which yields zirconium ions at pH levels of 8 and greater is a 
preferred choice as a crosslinking agent. In a preferred embodiment, the 
crosslinker used in the system is a zirconium compound, the slow pH 
raising compound is magnesium oxide, the cheating agent is EDTA, and the 
crosslinking delaying agent is sodium lactate. Various oxidizing breakers 
and catalysts may be applied to produce the most effective viscosity 
reduction at specific temperatures. 
In this aspect of the invention, all the components of the chemical system 
are preferably premeasured and organized onto a palletized package, which 
also contains easy-to-follow mixing instructions so that equipment 
operating personnel can perform the well treatment without having to have 
extensive chemical knowledge about the materials. Preferably, an on site 
quality control kit is also included. 
The chemical system can be used as a fluid-loss-control pill during 
completion or workover operations or as a temporary blocking gel for zone 
isolation. The system is particularly useful in high permeability 
formations where excessive losses of heavy brines or linear gels are not 
acceptable. In this aspect of the invention, the system is a delayed, 
crosslinked-gel system that contains low-residue hydroxyethylcellulose 
(HEC) polymer, preferably at about 80 to about 120 lbm of HEC per 1000 
gallons of carrier fluid to achieve controlled fluid loss. External or 
internal breakers may be used for clean up. The system is batch-mixed at 
the wellsite using commonly available mixing equipment. 
The system is stable for more than a week at 200.degree. F. (93.degree. 
C.), and at least 48 hours at 290.degree. F. (143.degree. C.). Fluid 
stability is controlled by varying the polymer, crosslinker, crosslink 
activator and, if present, internal breaker concentrations for given 
temperatures. One or two internal combination breaker systems can be used 
depending on the temperature. The fluid can also be broken with external 
breakers such as acid, for example, inorganic acids, such as hydrochloric 
acid, and organic acids such as formic acid, acetic acid and citric acid. 
The system crosslinks at pH values greater than 9.5 and the crosslink 
system rigidity increases with increasing pH. The pH level is preferably 
about 12.5 to about 13. This preferred pH range produces the most stable 
and rigid crosslinked gel. 
Retained permeabilities in the polymer-invaded region remain high due to 
the use of low-residue HEC polymer, and the polymer invasion depth is much 
shallower due to the highly-crosslinked polymer network. The total 
fluid-loss volume is much lower compared to linear HEC systems because of 
the crosslink. Once the system is broken, there is a rapid response when 
the well is put back on production, even at low driving pressure. 
The system can be used at temperatures ranging from about 80.degree. F. to 
about 290.degree. F. (about 27.degree. C. to about 140.degree. C.). The 
system can be used in formations ranging from 0.1 to about 2 darcies. 
The system is compatible with KCl, NaCl, NaBr, CaCl.sub.2, CaBr.sub.2, and 
CaCl.sub.2 /CaBr.sub.2 brines. A wide range of brine densities (from about 
9 to about 14.8 lbm/gallon) can be used. This system is incompatible with 
NH.sub.4 Cl, MgCl.sub.2 and ZnBr.sub.2 brines and seawater. Please note 
that all CaBr.sub.2 and CaCl.sub.2 /CaBr.sub.2 brines must be free of any 
ZnBr.sub.2. HEC will not hydrate if CaBr.sub.2 fluids contain ZnBr.sub.2 
at 0.5% (wt/wt) or greater. The system works best with KCl, NaCl, and NaBr 
brines. Therefore, these brines are recommended when the required density 
permits. 
The crosslink delay time can be varied from 0 to about 35 minutes without 
substantial adverse effects on stability at higher temperatures. 
Typically, the shorter the delay time, the longer the high-temperature 
stability. A delayed time of about 10 to about 15 minutes is recommended 
for most applications. Crosslinking is also temperature-accelerated, which 
provides flexibility for batch-mixing of all ingredients including the 
activator at surface temperature. 
As noted before, the materials for this system are preferably palletized 
and shipped as a complete package. The pallet contains enough materials to 
prepare, for example, 10 barrels of fluid for all applications. Table A 
lists the pallet materials for a particular embodiment along these lines. 
The materials in the system are application specific, meaning that not all 
the materials identified in Table A will be used. A premarked breaker 
container is preferably included on each pallet and is used to measure the 
proper amounts of material for specific temperature and permeability 
applications. 
TABLE A 
______________________________________ 
Palletized Material 
Material Amount 
______________________________________ 
15% HCl 1 each, 1-gallon container 
Caustic (NaOH) 100 grams, 1,8-oz container 
Methanol 2 each, 5-gallon containers 
Liquid HEC slurry 3 each, 5-gallon container 
Crosslinker (e.g., zirconium lactate) 1 each, 5-gallon container 
Delaying Agent (e.g. 60% active sodium 1 each, 
5-gallon container 
lactate) 
Magnesium Oxide (e.g., Magchem 20M) 2 each, 5-lbm bag 
Magnesium Oxide (e.g., Magchem 10-325) 2 each, 5-lbm bag 
Breaker.sup.a 1 each, 1-gallon container 
Breaker Aid 1 each, 1-gallon container 
Cheating Agent (e.g., Na.sub.4 EDTA) 1 each, 50-lbm bag 
______________________________________ 
.sup.a Different oxidizers are used as breakers for different temperature 
applications. A premarked empty container is preferably included on each 
pallet. The container should be filled with the appropriate breaker and 
rewrapped with the pallet before being transported to the wellsite. 
The optimum pH value for HEC hydration is about 8. At pH values less than 
8, HEC hydrates slowly. At pH values ranging from 8.2 to 8.5, HEC starts 
to rapidly hydrate. The system is compatible with a variety of salt types 
for a wide range of densities. Table B provides the recommended salt type 
for the fluid density requirement. NaCl or NaBr is recommended when the 
density requirements is less than 12.3 lbm/gal. CaCl.sub.2 or CaBr.sub.2 
are preferably used when the density requirements is greater than 12.3 lbm 
per gallon due to cost considerations. 
TABLE B 
______________________________________ 
Recommended Brine for Required Density 
Salt Density (PPG).sup.a 
______________________________________ 
KCl 8.5-9.7 
NaCl 9.4-10 
NaBr 10-12.3 
NaCl/NaBr 10-12 
CaCl.sub.2 10.1-11.5 
CaBr.sub.2 11.5-15 
CaCl.sub.2 /CaBr.sub.2 11.7-13.4 
______________________________________ 
.sup.a lbm/gallon. 
The HEC concentration in the liquid HEC gelling agent is about 40% by 
weight. The specific gravity of the liquid HEC slurry is about 0.96. 
Therefore, to mix 120 lbm per 1000 gallons linear gel requires 36 gallons 
of liquid HEC slurry. For the liquid HEC gelling agent identified above, 
Table C provides the volume equivalents of different polymer loadings. One 
skilled in the art is able to modify Table C for such gelling agents 
having different HEC concentrations. 
TABLE C 
______________________________________ 
HEC SLURRY METERING 
HEC Concentration 
Liquid HEC Volumetric Concentration 
(lbm/1000 gal) 
gal/1000 gel gal/10 bbl 
______________________________________ 
40 12 5 
60 18 8 
80 24 10 
100 30 13 
120 36 15 
______________________________________ 
The fluids are preferably crosslinked with a zirconium crosslinker, i.e., a 
crosslinking agent which supplies zirconium ions in solution. Thus, the 
crosslinking agent can be any convenient source of zirconium ions. A 
preferred crosslinking additive is a zirconium chelate such as zirconium 
lactate. Other suitable zirconium compounds include zirconyl chloride, 
sodium zirconium lactate and zirconium acetylacetonate. The delay agent is 
preferably the sodium counterpart of these zirconium compounds. 
The crosslink can be delayed up to about 35 minutes by adjusting the delay 
agent concentration and activator concentrations. Magnesium oxide (e.g., 
Magchem 20M) is recommended for delay times less than 20 minutes. A slower 
release magnesium oxide with larger particle size (e.g., Magchem 10-325) 
is recommended for delay times greater than 20 minutes. The recommended 
activator aid (Na.sub.4 EDTA) concentration is at least about 80 lbm. per 
1000 gallons, preferably from about 80 to about 120 lbm per 1000 gallons. 
A preferred quantity is about 100 lbm per 1000 gallons. 
FIG. 3 shows the effect of magnesium oxide (e.g., Magchem 20M) 
concentrations on crosslink delay times with a delay agent sodium lactate 
(60% active) concentration of 15 gallons per 1000 gallons. The magnesium 
oxide concentrations were 20 lbm/1000 gal., 15 lbm/1000 gal., and 10 
lbm/1000 gal. The other components of the composition as added thereto 
were 2% by volume methanol, 36 gal/1000 gal HEC polymer slurry (40% by 
weight HEC polymer in the slurry), 12 gal/1000 gal. zirconium lactate and 
100 lbm/1000 gal. Na.sub.4 EDTA. 
FIG. 4 shows the effect of the sodium lactate (60% active) concentrations 
at 0 gal/1000 gal, 0.3 gal/1000 gal, 0.5 gal/1000 gal, 0.7 gal/1000 gal 
and 1.0 gal/1000 gal at 70.degree. F. (21.degree. C.) with a slower 
release magnesium oxide (larger particle size; e.g., Magchem 10-325) 
concentration of 25 lbm per 1000 gallons. The concentrations of KCl, 
methanol, HEC slurry, zirconium lactate and Na.sub.4 EDTA were the same as 
that used in regards to FIG. 3. 
Depending on the reservoir temperature, different types of breakers may be 
used to reduce the fluid viscosity and to enhance flowback during oil and 
gas production. Breaker systems and concentrations are designed to reduce 
the crosslinked fluid viscosity to nearly water viscosity after about 24 
hours. If desired, the internal breaker may be omitted, and an inorganic 
acid (e.g., hydrochloric acid) or organic acid (e.g., formic acid, acetic 
acid and citric acid) soak used an external breaking mechanism. 
Different breakers may be used for different temperature applications. 
Further, long break times may require using encapsulated breakers in 
aggressive concentrations at temperatures below 175.degree. F. At 
200.degree. F., a catalyst preferably used to activate bromate breakers 
effectively, if used. For example, at temperatures ranging from about 
80.degree. F. to about 125.degree. F. (27.degree. C. to 52.degree. C.), 
ammonium persulfate is preferred as the internal breaker system. At 
temperatures ranging from about 125.degree. F. to about 175.degree. F. 
(52.degree. C. to 79.degree. C.), an encapsulated ammonium persulfate is 
preferred as the internal breaker. At temperatures ranging from about 
175.degree. F. to about 225.degree. F. (79.degree. C. to 107.degree. C.), 
the preferred internal breaker is sodium bromate used in conjunction with 
a breaker aid such as copper chloride and ferrous sulfate. Breaker aids 
lower the activation energy of the breaker, e.g., sodium bromate, in order 
to effectively operate in this temperature range. At temperatures ranging 
from about 225.degree. F. to about 250.degree. F. (107.degree. C. to 
121.degree. C.), an encapsulated sodium bromate is preferred as the 
internal breaker. Above 250.degree. F. (121.degree. C.), an internal 
breaker is not preferred. The encapsulating coating for the encapsulated 
ammonium persulfate and the encapsulated sodium bromate is preferably a 
vinylidene chloride/methylacrylate copolymer with an optional coating of 
talc (magnesium silicate hydrate). The copolymer coating ranges from about 
10 to about 30% by weight of the total breaker weight. 
Preferred internal breaker concentrations for 24 hour break times are 
provided in Table D. Laboratory testing is preferably conducted to 
determine breaker concentrations for other break times. 
TABLE D 
__________________________________________________________________________ 
Fluid-Loss Control Viscous Pill 
Recommended Breaker Types and Concentrations 
for Different Temperatures 
Note: For 24 hours break time. 
Breaker Type and Concentration 
(lbm/1000 gal [lbm/10 bbl]) 
Copper 
Encapsulate Chloride or Encapsulated 
Temperature Ammonium Ammonium Sodium Ferrous Sodium 
(.degree. F.[.degree. C.]) Persulfate Persulfate Bromate Sulfate 
__________________________________________________________________________ 
Bromate 
75 to 100 (24 to 38) 
15[6] -- -- -- -- 
100 to 125 (38 to 52) 10[4] -- -- -- -- 
125 to 135 (52 to 57) 5[2] -- -- -- -- 
135 to 150 (57 to 66) -- 8[3.5] -- -- -- 
150 to 165 (66 to 74) -- 6[2.5] -- -- -- 
165 to 175 (74 to 79) -- 4[1.5] -- -- -- 
175 to 185 (79 to 85) -- -- 15[6] 3[1.5] -- 
185 to 200 (85 to 93) -- -- 12[5] 3[1.5] -- 
200 to 225 (93 to 107) -- -- 10[4] 3[1.5] -- 
225 to 250 (107 to 121) -- -- -- -- 15[6] 
&gt;250(&gt;121) -- -- -- -- -- 
__________________________________________________________________________ 
The system exhibits excellent fluid-loss control properties and minimal 
formation damage when used with an internal breaker system because of the 
leakoff properties of the crosslinked fluids of the present invention and 
the use of low-residue HEC polymer. 
In a preferred embodiment, the pallet contains all of the materials 
required to mix a ten barrel batch. The system using the chemical 
components on the pallet may be prepared using the following procedure: 
1. Add the mixed-water to a clean mixing tank. 
2. Agitate the mixed-water and add the delayed agent (60% active sodium 
lactate), temperature stabilizer (methanol) and salt. Please note that 
methanol is a hazardous U waste. The methanol container should be handled 
using an approved hazardous waste handling procedure. 
3. Continue agitation and add the liquid HEC slurry. 
4. Continue agitation and add the pH adjusting material, e.g., sodium 
hydroxide (NaOH), to achieve maximum hydration of the HEC (pH value of 7.5 
to 8.0). 
5. Mix the linear gel for about 30 minutes. 
6. Continue agitation and add the zirconium crosslinker. Mix thoroughly. 
7. Immediately before pumping, add the appropriate breaker or breakers (and 
breaker aid if required) and mix thoroughly. 
8. Add the crosslinking activator magnesium oxide, and the activator aid 
Na.sub.4 EDTA, mix thoroughly and begin pumping. 
FIG. 10 shows the viscosity of linear HEC at 120 lbm/1 000 gallon at 
75.degree. F. (24.degree. C.) measured with FANN 35 viscometer. The 
initial ingredients and concentrations thereof is the fluid composition 
used for FIG. 10 were 500 ppm sodium bicarbonate, 1.25 ml 15% HCl, 0.047 
gm NaOH, 9 ppg KCl, 2% by volume methanol, 36 ml of lignin HEC slurry (40% 
by weight HEC), 8 ml of zirconium lactate, 219.4 gm KCl and 1000 ml of 
deionized water. A quality control kit is preferably included with the 
palletized materials to check the linear gel viscosity before crosslinking 
and pumping. The quality control kit preferably contains a 60 ml syringe 
and a 65 mm funnel. 
After the HEC gel has hydrated for about 30 minutes, extract about 60 ml 
from the mixed tank and fill the funnel with the outlet of the funnel 
plugged. Open the funnel plug and the let the gel gravity feed into the 
empty syringe. Measure the time required to flow 50 ml of gel. Depending 
on the temperature, the time preferably falls within the ranges provided 
in FIG. 11. 
The breaker schedule given in Table D is designed to reduce the crosslinked 
gel viscosity to less than 10 cp in about 24 hours. Softening of the 
crosslinked strength actually begins about 6 hours after the fluid has 
reached bottom-hole static temperature. The viscosity will slowly decrease 
to nearly water-like during the 6 to 24 hour time period. The fluid-loss 
control is provided by the filter-cake formed during the first 6 hours. If 
desired, the internal breaker may be omitted, and an acid soak (e.g., 
hydrochloric, formic, acetic or citric acid) soak used as an external 
breaking mechanism. 
The polymer of choice in this aspect of the present invention is 
hydroxyethyl cellulose (HEC). HEC is referred to as a "clean" polymer in 
that once the need for the fluid loss control agent is completed and 
broken, little residue is left on the formation surface. Guar, on the 
other hand, is regarded as a "dirty" polymer in that significant amounts 
of residue are left on the formations surface affecting the permeability 
of the formation, thereby affecting production. Guar is typically used in 
fracturing operations in that the exposed surface area of the formation is 
being enlarged or expanded by forcing a fracturing fluid containing guar 
at elevated pressures sufficient to crack the formation leaving proppants 
to sustain the openings created by the fracturing operation. Once the 
fracturing operation is completed, the guar material is broken. In this 
situation, surface area is much greater and so the residues of guar 
remaining are not as significant a problem as compared to nonfractured 
formation faces which have limited surface area exposed to the wellbore 
via the perforation sites. 
In order to form strong crosslinks within the HEC, the system pH must be 
maintained at or greater than 12 at formation temperature. Though sodium 
hydroxide or other similar type bases can be used to increase the pH to 
above 12, once added to the polymer and the crosslinker, the polymer 
immediately crosslinks, which greatly increased the viscosity of the 
system making it difficult to pump down the wellbore. Accordingly, a slow 
dissolving base, for example, magnesium oxide, is used to slowly increase 
the pH. However, the equilibrium pH for magnesium oxide is a maximum of 
10.5 at room temperature. Accordingly, even though additional magnesium 
oxide is added, the pH will not be raised above this maximum. Other 
suitable bases include calcium hydroxide and potassium fluoride. Calcium 
hydroxide is slower than NaOH, but faster than MgO. Potassium fluoride 
will also slowly increase pH with temperature increase. Further, 
encapsulated bases may be used to delay the increase in pH until the 
formation is reached. 
Therefore, according to the present invention, a chelating agent is added 
to tie up the magnesium reducing the concentration of the magnesium ion. 
This drives the equilibrium of the disassociation of magnesium oxide in 
water toward producing more magnesium ions and hydroxyl ions. This, in 
effect, raises the pH to the levels necessary to achieve strong 
crosslinking of the HEC with the crosslinker, i.e., a pH greater than or 
equal to 12. At this pH level, the crosslinked HEC can stop, or at least 
substantially minimize, fluid loss in formations having a permeability up 
to about 1.8 Darcy. 
However, at this stage, there is the interplay of two equilibrium states 
with the first being the equilibrium of magnesium oxide and water with the 
magnesium ions and hydroxyl ions, and the second equilibrium condition 
existing between a chelating agent, e.g., Na.sub.4 EDTA plus the magnesium 
ion to yield a chelate between the magnesium ion and the EDTA.sup.4- ion. 
The chelating agent is preferably in a base form which has a pH of 10.5. 
In this manner, pH is not decreased as a result of adding the 
EDTA-containing compound. This chelating mechanism also improves the high 
temperature stability of the crosslinked gel to about 290.degree. F. 
Therefore, the chelating agent is used to help pH increase beyond the 
equilibrium value that MgO can provide and still maintain the delay. The 
chelant dissolves in water rapidly and raises the pH to 10.5-11.0. When 
low MgO concentration is used, the early pH profile will be dominated by 
the chelant, and the late pH profile will be dominated by the MgO 
dissolution. However, when high MgO concentration is used, the chelant has 
minimum effect on the early pH profile of the system, i.e. it will follow 
the pH profile given by the release of MgO, but the equilibrium pH is much 
higher. Therefore, the delay mechanism at high MgO concentration is not 
altered by the chelating agent, and the crosslink strength is dramatically 
improved. 
The mechanism of increasing pH can be described by the following reactions: 
EQU MgO+H.sub.2 O.revreaction.Mg(OH).sub.2 .revreaction.Mg.sup.2+ +2 OH.sup.-(1 
) 
EQU 2 Mg.sup.2+ +EDTA.sup.4- .revreaction.Mg.sub.2 (EDTA) (2) 
Since the solubility of Mg(OH).sub.2 is low, when reaction (1) reaches 
equilibrium, a relatively low concentration of hydroxyl ion (OH.sup.-) is 
present in the solution. By forming complexes with magnesium ions, EDTA 
will drive reaction (1) to the right; a higher pH is therefore achievable. 
The complexation rate in reaction (2) is faster than the dissociation rate 
in reaction (1) at a high pH level, so the overall reaction rate is 
controlled by reaction (1). 
Now having the crosslinking of the HEC occurring at the necessary high pH, 
there is still a need to slow down or delay the crosslinking of the HEC. 
In a preferred embodiment, the HEC is crosslinked with zirconium ions from 
a zirconium compound at a pH greater than 12. In order to control the rate 
of crosslinking, the concentration of the zirconium ion is controlled by 
use of a delaying agent. For example, if the zirconium compound is 
zirconium lactate, the zirconium lactate and the zirconium ion and lactate 
ion exist in equilibrium in the high pH of the system. Accordingly, in the 
present invention, to drive the equilibrium reaction from the ion state to 
zirconium lactate, the system is manipulated to overload on lactate ions. 
This reduces the concentration of the zirconium ions thereby slowing or 
delaying the crosslinking of the HEC by the zirconium ion. A preferred 
delaying agent in this regard is sodium lactate. The sodium lactate more 
easily disassociates into sodium ions and lactate ions than zirconium 
lactate to zirconium ions and lactate ions, thereby overloading the system 
with lactate ions. 
As the HEC slowly crosslinks as a result of any available zirconium ion, 
the equilibrium reaction between zirconium lactate and its zirconium ion 
and lactate ion is driven toward the side of producing more zirconium ion. 
In this manner, the HEC crosslinking is delayed until the appropriate time 
as it reaches close to or at the location where fluid loss control is 
needed. The crosslinked HEC forms a filter-cake at these locations 
effecting fluid loss control. 
The crosslinked HEC pill can also be used as a formation sealer during 
fracturing. For example, in a vertical gas well penetrating two zones of 
sandstone where only the lower zone is to be hydraulically fractured, the 
pill serves two purposes: (1) to seal the upper zone while fracturing the 
lower zone; and (2) to prevent the fluid in the annulus from leaking into 
the upper zone, so a full column of fluid is maintained in the annulus. 
Casing pressure is monitored during the fracturing treatment. If no casing 
pressure increase is observed, this indicates that the pill functioned as 
desired or that the fracture failed to extend vertically into the upper 
zone. Referring now to FIG. 5, there is shown a subterranean formation 20, 
a casing 22 penetrating an upper zone 24 and a lower zone 26 with 
corresponding perforations 28 and 30, respectively, through the casing 22. 
A packer 32 is set to isolate the two zones 24 and 26. The fracture 
treatment is executed down the tubing 34. The objective is to fracture 
only the lower zone 26. After the lower zone 26 is fractured, the packer 
32 is moved up to above the upper zone 24 to produce both zones 24 and 26 
at the same time (not shown). During the fracture operation, the fluid and 
proppant are confined in the fracture 36. Communication between the 
annulus 38 and the lower zone 26 around the packer 32 would be 
undesirable. In order to prevent the fracturing fluid and slurry from 
entering the annulus 38 above the packer 32, a viscous pill 40 is used to 
stop the fracture extrusion into the upper zone 24. 
The crosslinked HEC pill is pumped down the casing 22 within the annulus 38 
and spotted, for example, by a 2% KCl displacement fluid before fracturing 
is conducted. The pump rate, for example, may be 3 barrels per minute down 
the annulus 38 between the casing 22 and the tubing 34. When spotting the 
pill 40, the treatment pressure is low (for example, about 600 psi) due to 
the delay crosslink mechanism. As a result, no difficulty in pumping is 
experienced throughout the job. During the fracturing treatment, the 
casing pressure is monitored to determine if the pill 40 is maintaining 
the seal relative to the upper zone 24. No casing pressure increase means 
no communication around the packer 32. 
In another aspect of the invention, there is provided a dry crosslinked 
polymer particulate system which can be quickly spotted into a wellbore to 
control fluid loss. The material is easily mixed and pumped on location. 
The particulate system bridges the formation face and rehydrates in situ 
to form a filter-cake. The particulate system is prepared by first making 
a batch of crosslinked gel, shredding the crosslinked gel into small 
particles by extrusion, coating the shredded particles with a polymer 
powder, hardening the coated particles by drying, and then grinding the 
hardened particles into fine grained material. In order to prepare the 
crosslinked gel, an aqueous gel is first prepared by blending a hydratable 
polymer into an aqueous fluid. The aqueous fluid could be, for example, 
water, brine or water alcohol mixtures. A number of hydratable polymers 
are familiar to those in the well service industry. Polysaccharides are 
hydratable polymers capable of gelling in the presence of a crosslinking 
agent to form a gelled base fluid. For example, hydratable polysaccharides 
include the galactomannan gums, guars, derivatized guars, cellulose and 
cellulose derivatives. Specific examples of galactomannan gums and guars 
are guar, locust bean gum and caraya gum. Examples of derivatized guar 
include propylguar and carboxymethylhydroxypropylguar. Examples of 
derivatized celluloses include alkylcelluloses and mixed ethers. The alkyl 
group(s) thereof preferably has from 1 to about 3 carbon atoms, for 
example, methylcellulose, ethylcellulose, hydroxyethylcellulose, 
hydroxypropylcellulose, carboxymethylcelluose and 
carboxymethylhydroxyethylcellulose. The crosslinking agents are those that 
provide zirconium, titanium, aluminum or antimony ions. The crosslinked 
gel can be extruded and shredded through a perforated disk, cylinder or 
screen and, preferably, tumbled in a polymer powder-filled roller tank. 
Preferably, the polymer powder is of the same polymer to be crosslinked. 
The material can be coated with the polymer powder and dried at the same 
time. The lumped dry particles can then be ground into fine particles or 
granules of from about 10 to about 200 meshes on the U.S. Sieve Series. 
The fine particles can be added to a blender tank on location. These 
particles do not hydrate and thicken the water immediately, hence low 
fliction pressure is observed while pumping. An advantage of this system 
is that the material behaves as a solid fluid loss control material, such 
as the often used carbonate pill, but the particles form a tighter network 
on the face of the rock once they start to hydrate and expand. There is no 
solid invasion and permanent formation damage like that usually associated 
with the calcium carbonate pills. Another advantage of this system is that 
the slow reaction with breakers allows uniform treatment of a long 
wellbore interval, in which a thief zone usually forms when acids are used 
to cleanup the carbonate pill. 
In a preferred embodiment, the polymer to be crosslinked is 
hydroxyethylcellulose (HEC). Since this polymer is going to be 
pre-crosslinked prior to reaching the wellsite, there is no need to 
utilize a delay agent or chelating agent as in the previously discussed 
system. Rather, the crosslinker is added to the hydrated HEC and the pH 
adjusted by adding, for example, sodium hydroxide. The resulting 
crosslinked gel can then be extruded through a perforated disk, cylinder 
or screen and shredded. The gel particles are preferably tumbled in a 
roller tank filled with a polymer powder, preferably the same polymer that 
is being crosslinked, in this case HEC. The material can be coated with 
the polymer powder and dried at the same time. The lump dried particles 
are then ground into fine particles up from about 10 to about 200 meshes 
on the U.S. Sieve Series. 
In another example, the procedure of U.S. Pat. No. 5,439,057 is modified 
such that rather than shearing (i.e., extruding and then shredding) the 
crosslink gel into aqueous fluid directly, the crosslink gel thereof is 
sheared and tumbled in a polymer powder-filled roller tank, preferably 
utilizing the polymer being crosslinked as the polymer powder. The 
material is then dried or can be coated with a polymer powder and dried at 
the same time. Again, the lump dried particles or granules are then ground 
into fine particles of about 10 to about 200 meshes on the U.S. Sieve 
Series. The fine particles can be added to a blender tank on location. 
U.S. Pat. No. 5,439,057 is hereby incorporated by reference. Please note 
that the crosslinking agent does not include borates. This invention 
utilizes the dried crosslinked particles in a similar fashion as solid 
fluid loss control additives. An advantage of the present invention is 
that once these particles are in place they swell as a result of being 
hydrated and more readily seal the formation and minimize fluid loss. Once 
there is a back flow of the formation up through the wellbore, the 
filter-cake readily disassociates since the particles thereof are not 
crosslinked to each other. If a borate crosslinker were used, the 
filter-cake particles would tend to crosslink with each other due to the 
rehealing of borate crosslinks and require a breaker system. 
In another aspect of the present invention, there is provided a method to 
enhance the effectiveness of an acidizing treatment. Acidizing is used to 
either stimulate a well or to remove damage. There are two types of 
acidizing treatments: (1) matrix acidizing and (2) fracture acidizng with 
the difference between them relating to injection rates and pressures. 
Fracture acidizing is acidizing at injection rates above fracture 
pressure. Fracture acidizing is used for stimulation. Acidizing at 
injection rates below fracture pressure is termed matrix acidizing. Matrix 
acidizing is primarily used for damage removal and to restore the 
permeability to original reservoir permeability or higher. The damage is 
primarily skin damage caused by drilling, completion and workover fluids 
and precipitation of deposits from produced water or oil (such as scale). 
Removal of severe plugging in carbonate and sandstone formations can 
result in very large increases in well productivity. Oil well flow 
behavior is greatly affected by the geometry of radial flow into the 
wellbore. The pressure gradient, for example, psi per foot, is 
proportional to the flow velocity and is very small at large distances 
from the wellbore. At points close to the wellbore, the flow area is much 
smaller and the flowing pressure gradient is much higher. Because of this 
small flow area, any damage to the formation close to the wellbore, say 
within 20 feet thereof and sometimes within as little as 3 feet therefrom, 
may be the cause of most of the total pressure draw down during production 
and thereby dominate well performance. 
A conventional acidizing treatment for a sandstone formation normally will 
consist of sequentially injecting three fluids--a preflush, a hydrofluoric 
acid-hydrochloric acid mixture, and an afterflush. For a carbonate 
formation, a conventional acidizing treatment normally will involve 
sequential injection of at least two fluids--an acid and an afterflush. A 
preflush may also be included. 
The effectiveness of matrix and fracture acidizing treatments is often 
dictated by the ability to divert the acid into the areas where it can be 
most beneficial in opening up pore structures to the production of 
hydrocarbons. In many cases, acid will increase permeability in a small 
region. This makes it easier for sequential quantities of acid to follow 
this same higher permeability "path of least resistance". The dry, 
granulated fluid loss control agent of the present invention is also 
useful to temporarily plug off areas most susceptible to fluid movement in 
order to divert acid away from higher permeability zones. Therefore, the 
step added to conventional acidizing methods, whether matrix acidizing or 
fracture acidizing, is the step of providing a dry, granulated fluid loss 
control agent mixed in a carrier fluid to selectively retard migration of 
acid into high permeability zones. The steps of adding the fluid loss 
control agent of the present invention and then of adding the acid can be 
repeated as necessary during the treatment. 
Productivity restrictions caused by oil wetting of formation and fines 
often can be removed by making the solids water wet. This may be done with 
surface-active materials provided they contact the solid surface and 
replace the agent making the surface oil wet. Unfortunately, most 
surface-active materials alone cannot cause the oil wetting agent to be 
desorbed. Some chemicals (such as the low molecular weight glycol ethers) 
can strip the oil wetting surfactant from the surface and leave it water 
wet. Ethylene glycol monobutyl ether (EGMBE) is often preferred for this 
application. When used at a concentration of 10 percent by volume in the 
afterflush, this material is most effective. Low molecular weight alcohols 
are sometimes used for this purpose, although they appear less effective 
than the glycol ethers. However, compatibility tests should be performed 
with acid, formation fluids, and formation solids to assure damage will 
not occur. 
In the acidizing of sandstone formations, the preflush is usually 
hydrochloric acid, ranging in concentration from 5 to 15 percent and 
containing a corrosion inhibitor and other additives as required. The 
preflush displaces water from the wellbore and formation, i.e., connate, 
water from the near-wellbore region, thereby minimizing direct contact 
between sodium and potassium ions in the formation brine and fluosilicate 
reaction products. Normally, this will eliminate redamaging the formation 
by precipitation of insoluble sodium or potassium fluosilicates. The acid 
also reacts with calcite (calcium carbonate) or other calcarious material 
in the formation, thereby reducing, or eliminating, reaction between the 
hydrofluoric acid and calcite. The preflush avoids waste of the more 
expensive hydrofluoric acid and prevents the formation of calcium 
fluoride, which can precipitate from a spent HF-HCl mixture. 
The HF-HCl mixture (usually 3-percent HF and 12-percent HCl) then is 
injected. The HF reacts with clays, sand, drilling mud or cement filtrate 
to improve permeability near the wellbore. The HCl will not react and is 
present to keep the pH low, preventing precipitation of HF reaction 
products. Because the depth of permeability alteration is severely limited 
in HF-HCl treatments, a way to extend the action of acid deeper into the 
formation is to generate the HF acid in situ by injecting methyl formate 
and ammonium fluoride. Methyl formate hydrolyzes in the presence of 
formation water to produce formic acid, which then reacts with ammonium 
fluoride to yield hydrogen fluoride. 
The step of providing a dry, granulated fluid loss control agent in a fluid 
carrier, for example, an aqueous carrier, is added to the conventional 
acidizing treatment method of sandstone formations either before the 
preflush step or before the step of adding the acid. 
An afterflush is required to isolate the reacted HF from brine that may be 
used to flush the tubing and to restore water wettability to the formation 
and the insoluble-acid reaction products. Normally, hydrocarbon producing 
wells one of two types of afterflush is used (1) for oil wells, either a 
hydrocarbon afterflush, such as diesel oil, or 15-percent HCl is used and; 
(2) for gas wells, either acid or a gas (such as nitrogen or natural gas) 
is used. With a liquid after flush, chemicals usually are added to aid in 
removing treating fluids from the formation, restoring water wettability 
to formation solids and precipitated acid reaction products, and 
prevention of emulsion formation. A glycol ether mutual solvent has been 
shown to be useful for this purpose. When a gas is used as an afterflush, 
cleanup additives are added to the HF-HCl stage of the treatment. 
In a carbonate matrix acidizing treatment, the acid used (usually 
hydrochloric acid) is injected at a pressure (and rate) low enough to 
prevent formation fracturing. If the pressure is above the fracture 
pressure, the treatment is a fracture acidizing treatment. The goal of the 
treatments are to achieve more-or-less radial acid penetration into the 
formation to increase the apparent formation permeability near the 
wellbore. 
The treatment usually involves acid injection followed by a sufficient 
afterflush of water or hydrocarbon to clear all acid from well tubular 
goods. A corrosion inhibitor is added to the acid to protect wellbore 
tubulars. Other additives, such as antisludge agents, iron chelating 
agents, de-emulsifiers, and mutual solvents, are added as required for a 
specific formation. 
When acid is pumped into a carbonate (limestone or dolomite) formation, the 
acid flows preferentially into the highest permeability regions (that is, 
largest pores, vugs or natural fractures). Acid reaction in the 
high-permeability region causes the formation of large, highly conductive 
flow channels called wormholes. The creation of wormholes is related to 
the rate of chemical reaction of the acid with the rock. High reaction 
rates, as observed between all concentrations of HCl and carbonates, tend 
to favor wormhole formation. Acids normally used in field treatments are 
highly reactive at reservoir conditions and tend to form a limited number 
of wormholes. A low reaction rate favors the formation of several 
small-diameter wormholes. 
The rate of fluid loss from a wormhole often can be reduced with a 
fluid-loss additive, thereby increasing wormhole length. Normally, the 
most effective additives are solids or acids swellable polymers used as 
acid-fracturing, fluid-loss additives. The dry, granulated fluid loss 
agent of the present invention initially acts as a solid fluid loss 
additive and then as a swellable polymer, typically after the particulates 
of the fluid loss control agent have bridged an area of high permeability. 
After the particles swell, the bridged particles provide a more effective 
seal and control the rate of fluid loss from a wormhole. 
The productivity increase that can result from a matrix acid treatment in 
carbonate normally is limited to damage removal. Without a fluid-loss 
additive, acid penetration distances will be limited to a few feet at 
most. The maximum stimulation expected from a matrix treatment will be 
about 1.5-fold above damage removal. The exact stimulation ratio from 
matrix acidizing of a carbonate cannot be predicted because the number and 
location of wormholes cannot be predicted. However, by using the dry, 
granulated fluid loss control agent of the present invention, the number 
of wormholes is expected to increase or at least the wormhole length 
attained is greater. 
The following are some of the known method of acidizing hydrocarbon bearing 
formations which can be used as part of the present method: U.S. Pat. Nos. 
3,215,199 to R. E. Dilgren; 3,297,090 to R. E. Dilgren; 3,307,630 to R. E. 
Dilgren et al.; 2,863,832 to R. L. Perrine; 2,910,436 to I. Fatt et al.; 
3,251,415 to C. C. Bombardieri; 3,441,085 to J. L. Gidley; and 3,451,818 
to J. L. Gidley et al., which are hereby incorporated by reference. These 
methods are modified to incorporate the separate step of providing the 
dry, granulated fluid loss control agent of the present invention prior to 
the acidizing step thereof, whether matrix acidizing or fracture 
acidizing. Again, the steps of adding the fluid loss agent and adding the 
acid can be repeated as necessary. 
EXAMPLES 
In the following examples, the following materials are used and/or 
referenced: 
______________________________________ 
Description Purpose 
______________________________________ 
methanol temperature stabilizer 
60% sodium lactate delaying agent 
liquid HEC polymer gelling agent 
30% NaOH pH adjusting agent 
NaOH pH adjusting agent 
Na.sub.4 (EDTA) chelating agent 
zirconium lactate crosslinker 
magnesium oxide slurry crosslinker activator 
magnesium oxide crosslinker activator 
magnesium oxide larger crosslinker activator 
particle size 
sodium bicarbonate buffer 
hemicellulase enzyme breaker 
alpha amylase high temperature enzyme 
breaker 
polyglycolic acid breaker 
encapsulated ammonium encapsulated breaker 
persulfate 
encapsulated calcium encapsulated breaker 
peroxide 
sodium bromate breaker 
encapsulated ammonium high temperature encapsulated 
persulfate breaker 
ammonium persulfate oxidizer 
surfactant alcohol blend breaker aid 
triethanolamine breaker aid 
copper (II) chloride breaker aid 
dihydrate 
______________________________________ 
Example 1 
Lab Scale Tests 
Fluid Mixing and Testing Procedure 
1. Preparation of the HEC Linear Gel. 
A 9 lbm/gal KCl brine was used for most of the samples, although 12.3 
lbm/gal NaBr and 9.8 lbm/gal NaCl were also used successfully. The method 
used to hydrate the linear HEC gel is outlined below: 
The required volume of brine was measured. Two percent of temperature 
stabilizer (methanol) and 1.5% of delaying agent (60% active sodium 
lactate) by volume were added. Thirty-six gal/1000 gal of liquid HEC 
polymer (40% by weight HEC) were added to the brine, the equivalent HEC 
concentration was 120 lbm/1000 gal. A base (30% NaOH) was added drop by 
drop to adjust the pH of the fluid to about 7.5 to about 8. Rapid 
hydration could be observed by the closing of the vortex in the blender. 
The blender was a Waring blender (100 ml cup) with adjustable speed 
controller. The initial diameter of the vortex was about 1.5 inches. The 
blender speed was about 1500 to about 2000 rpm. The linear gel was allowed 
to stand for about 30 minutes to allow complete hydration of HEC polymer. 
2. Preparation of the Crosslinked HEC Gel. 
Several experiments were performed in which the concentrations of 
crosslinker, activator and chelate were varied in order to produce the 
strongest possible delayed crosslink gel. Magnesium oxide slurry (17% by 
weight MgO and 83% by weight mineral oil) concentrations between 0 and 20 
gal/1000 gal, and Na.sub.4 (EDTA) concentrations between 0 and 100 
lbm/1000 gal of fluid were used. Gels with various strengths and crosslink 
times were produced. The most satisfactory gel in terms of crosslink 
strength, delay time, and thermal stability contained the following 
composition: 
2% methanol--temperature stabilizer. 
1.5% sodium lactate (60% active)--delaying agent. 
36 gal/1000 gal HEC polymer slurry (40% by weight)--gelling agent. 
0.35 gal/1000 gal 30% NaOH--pH adjusting agent. 
12 gal/1000 gal zirconium lactate-crosslinker. 
20 gal/1000 gal MgO slurry or 15 lbm/1000 gal to 25 lbm/1000 gal 
MgO--crosslinker activator. 
100 lb/1000 gal Na.sub.4 (EDTA)--crosslinker enhance agent. 
The above order is also the preferred mixing sequence of preparing the 
crosslinked HEC pill. However, the order of addition may be varied. When 
breakers are used, they are preferably added right before the crosslinker. 
3. Determination of Crosslink Times. 
After blending together the gel ingredients for about 20 seconds, the gel 
was poured out into ajar. At intervals, the jar was tipped slightly so 
that a small amount of gel was poured out. The jar was then returned to 
its original position. The time taken for the gel to reach the degree of 
crosslinking to where the gel returned to the jar after being poured out 
was called the crosslink or delay time. The strength of the gel was 
qualitatively observed after it was allowed to fully crosslink, usually 
between 20 to 30 minutes after it was prepared. When the gel is fully 
crosslinked, it does not flow even when the jar is positioned upside down. 
The crosslink time was also observed by using a Brookfield viscometer 
connected to a automated chart recorder. A constant rpm was used to 
measure the steady shear viscosity of the fluid. The Brookfield readings, 
corresponding to the fluid viscosity, as a function of elapsed time was 
recorded on the chart recorder. An "S" profile of viscosity development 
was monitored by the Brookfield viscometer, and the time to the inflection 
point was defined as crosslink time. The time to reach inflection point of 
the "S" shape profile corresponds to the previously mentioned "crosslink 
delay time" determined using the jar technique. 
4. Stability Testing 
After the crosslinked gel was prepared, it was tested for temperature 
stability by being placed in 150.degree. F., 200.degree. F., 290.degree. 
F. and 350.degree. F. ovens over a period of 2 to 7 days, and being 
observed every 24 hours. The gel was considered to be stable if it 
remained crosslinked over the required length of time. It was considered 
unstable if it broke to a water-like consistency or linear gel. 
5. Internal Breakers 
After a suitable gel formula had been found, experiments were conducted to 
find suitable internal breakers which would decrease the viscosity of the 
gel to a value close to that of water in approximately 24 hours. In 
addition, it was desirable for the gel to remain strong for at least the 
first 4 hours after reaching the desired temperature. Systems at 
150.degree. F. and 200.degree. F. were studied in detail. Several breakers 
were used in varying concentrations including enzyme breakers such as 
cellulase, hemi-cellulase and alpha amylase, polyglycolic acid, ammonium 
persulfate, calcium peroxide, sodium bromate, with breaker aids 
trimethanolamine, copper chloride dihydrate, and ferrous sulfate. These 
internal breakers were added to the gel according to the mixing procedure 
described earlier. After mixing, the gels were allowed to fully crosslink 
and were then placed in an oven or water bath at the specified 
temperature. They were then observed every 30-45 minutes for the first 2 
hours and then every 1 or 2 hours thereafter for 24 hours. A gel was 
considered to have broken when by qualitative observation it appeared to 
have a viscosity similar to that of water. 
6. Leakoff Testing 
Static fluid loss tests were conducted using leakoff apparatus which 
consists of 1 inch diameter by 1 inch length core holder, a heat jacket, 
and a 250 ml fluid reservoir. The tests used 1 inch diameter by 1/4 inch 
length cores. The leakoff testing procedure used is as outlined below: 
(1) Two hundred ml of 2% KCl was loaded into a vertical static leakoff 
cell, with a 1000 md core at the bottom of the cell. 
(2) Once the fluid reached temperature, 100 psi drive pressure (no back 
pressure) was applied and the bottom valve was opened to let KCl flow 
through the core. The time required to flow 200 ml of 2% KCl was measured. 
(3) Two hundred ml of the crosslinked pill was loaded in the cell to heat 
the pill to the desired temperature. 
(4) Drive pressure of 150 psi (no back pressure) was applied to the top of 
the cell and fluid leakoff from the bottom was measured. 
(5) The core was shut in for 24 hours at 150 psi and at the desired 
temperature. 
(6) The bottom valve was opened. The broken fluid and residue were flushed 
through the core with 150 psi differential pressure. 
(7) The time required to flush all the broken gel through the core was 
measured. 
(8) If an external breaker was used, 200 ml of external breaker (about 10% 
HCl) was loaded into the cell and allowed to soak for 1 hour. 
(9) Drive pressure of 100 psi was applied to flush the external breaker 
through the core. 
(10) The cell was refilled w/200 ml 2% KCl, step (2) was repeated. 
Results and Discussions 
HEC System 
1. Fluid Chemistry 
In the preliminary tests, concentrations of magnesium oxide, zirconium 
crosslinker [zirconium lactate], and chelating agent [Na.sub.4 (EDTA)] 
were varied and the effects on the crosslink delay time were noted. 
Crosslink times were reduced by high concentrations of either magnesium 
oxide or Na.sub.4 (EDTA). It was observed that at low magnesium oxide 
slurry concentrations (less than 6 gal/1000 gal), the addition of the 
chelating agent Na.sub.4 (EDTA) had a significant effect on the crosslink 
time, i.e., reducing the crosslink time greatly. FIG. 1 shows the effect 
of Na.sub.4 (EDTA) on the crosslink delay time with different 
concentrations of magnesium oxide slurry (i.e., at 3 gallons/1000 gal (3 
gpt), 6 gpt, 10 gpt, 15 gpt and 20 gpt). The fluid otherwise contained 2% 
methanol, 9 ppg KCl, 36 gpt HEC slurry and 8 gpt zirconium lactate. At 
high concentrations of magnesium oxide slurry (greater than or equal to 6 
gal/1000 gal), the addition of Na.sub.4 (EDTA) had a much smaller impact 
on the crosslink time. This can be explained by the fact that at lower 
magnesium oxide concentrations, the early pH rise is due to the rapid 
dissolution of Na.sub.4 (EDTA). The pH of 1% tetrasodium EDTA solution is 
11. Hence, the addition of tetrasodium EDTA decreases the crosslink time 
because it rapidly causes the pH of the system to increase to 11 (FIG. 2). 
At higher magnesium oxide slurry concentrations, both magnesium oxide and 
tetrasodium EDTA contributed to early pH increase. Therefore, increasing 
tetrasodium EDTA does not significantly increase the already elevated pH. 
Thus, addition of tetrasodium EDTA has a much smaller impact on the 
overall rate of pH increase. However, it can be seen from FIG. 2 that when 
magnesium oxide slowly dissolves and releases Mg.sup.2+ and OH.sup.-, 
EDTA.sup.4- chelates the Mg.sup.2+ and causes the Mg(OH).sub.2 
dissolution reaction to shift to the right, resulting in a higher OH.sup.- 
ion concentration in the system, and therefore enhances the final 
strength of the crosslinked gel. 
The use of high concentrations of both magnesium oxide and tetrasodium EDTA 
produced the strongest gel. Thus, 20 gal/1000 gal magnesium oxide slurry 
(or 15 lbm/1000 to 25 lb/1000 gal magnesium oxide) and 100 lbm/1000 gal 
tetrasodium EDTA are recommended for the optimum gel in terms of strength 
and thermal stability. This formula was also tried with both 12.3 lbm/gal 
NaBr and 9.8 lbm/gal NaCl with similar results. The gel made with 12.3 
lbm/gal NaBr was stronger and had a longer crosslink delay than the one 
made with 9 lbm/gal KCl. An alternative crosslinker activator which 
contains magnesium oxide having a larger particle size (MagChem 10-325 
magnesium oxide available from Martin-Marietta) and therefore produces 
longer crosslink times, can also be used. Although gels made with 
magnesium oxide are somewhat weaker than those made with the smaller 
particle size magnesium oxide (MagChem 20M magnesium oxide available from 
Martin-Marietta), a concentration of 25 lbm/1000 gal of slow-release 
magnesium oxide produced a gel of almost comparable strength. 
The activator and chelant concentrations given above (20 gal/1000 gal 
magnesium oxide slurry and 100 lbm/1000 gal tetrasodium EDTA) produce a 
very strong gel with a crosslink time of approximately 6 minutes. To 
increase the crosslink time, it was discovered that adding 60% active 
sodium lactate solution resulted in a prolonged crosslink delay. The 
mechanism by which this delay occurs is unclear, but one possible 
explanation is as follows. In this embodiment, the crosslinker contains 
zirconium lactate. The addition of excess lactate ions to the system 
released from sodium lactate are believed to suppress the release of 
zirconium ions (Zr.sup.4+) from the crosslinker and decrease the 
concentration of zirconium ions in the system available for crosslinking 
the HEC. However, as EDTA.sup.4- ions chelate the Mg.sup.2+ ions present 
in the activator, there is an increase in the release of hydroxyl ions 
(OH.sup.-). As the pH of the system increases, crosslinking occurs more 
rapidly and the concentration of free zirconium ions in the system is 
further reduced. This eventually overrides the effect of the sodium 
lactate and causes the crosslinker to release more zirconium ions. As more 
zirconium ions are released, more crosslink bonds and a stronger 
crosslinked gel are formed. 
Crosslink delay is also affected by temperature. The higher the 
temperature, the faster the zirconium lactate disassociates, and, 
therefore, the faster the crosslink reaction occurs. This is why the 
crosslink said to be is temperature accelerated. Delay times are 
significantly shorter at 150.degree. F. and 200.degree. F. than at room 
temperature. 
Increasing the sodium lactate concentration causes the crosslink time to 
increase. However, when present in large concentrations, sodium lactate 
adversely affects the strength and stability of the crosslinked gel. A 
1.5% by volume of the 60% active sodium lactate in 9 lbm/gal KCl produces 
the optimum results, a crosslink delay of approximately 10 to 12 minutes 
at room temperature, without seriously affecting the strength of the 
crosslinked gel. It was also found that the concentration of sodium 
lactate must sometimes be varied to suit the characteristics of the brine. 
When 9.8 lbm/gal NaCl was used, it required only 1% of 60% active sodium 
lactate to produce a similar crosslink delay without affecting the 
strength of the final gel. The sodium lactate concentration may also be 
varied to suit the activator; less sodium lactate is needed when the 
larger particle size magnesium oxide is used. FIGS. 3 and 4 illustrate the 
achievable crosslink delay time by using various concentrations of 
delaying agent sodium lactate, various magnesium oxide concentrations, and 
recommended 25 lbm/1000 gal slow-release magnesium oxide, i.e., larger 
particle size MgO, concentration. FIG. 3 illustrates the effect of 
magnesium oxide concentration on crosslink delay time. FIG. 4 illustrates 
the effect of sodium lactate concentration on crosslink delay time when 
slow releasing magnesium oxide is used. 
The scale of "% crosslinked" is a response from the Brookfield viscometer 
readings. The Brookfield viscometer measurement procedure was: (1) load 
100 ml of fluid in a 4 oz. glass jar, (2) insert the Brookfield RV spindle 
No. 7 into the center of the fluid, and (3) turn on the motor on the 
Brookfield viscometer to rotate at 10 rpm, and automatically record the 
reading as time went on. The rpm and spindle were selected such that the 
full range (0 to 100) was used during the gel viscosity development to 
ensure the best resolution. Due to the highly elastic characteristics of 
the crosslinked gels, the readings obtained from the steady shear 
measurement may be distorted by slip and normal force. Hence, the recorded 
Brookfield viscosity magnitude could only serve as an indicator of 
qualitative viscosity development during crosslinking. The "% crosslinked" 
is taken as a fraction of the maximum Brookfield viscometer reading 
reached for the fluid. 
Thermal stability tests showed that the gel was stable for 14 days at 
150.degree. F. At 200.degree. F., the gel was stable for about a week. At 
290.degree. F., the crosslink gel was stable for at least 48 hours. At 
350.degree. F., the gel broke to a viscosity approximating water within 
about 24 hours. 
Crosslinked gels which contained excess bicarbonate ions showed no 
significant difference in terms ofthermal stability at 200.degree. F. and 
350.degree. F. from those which did not contain excess bicarbonate ions. 
Further, no significant difference was observed either whether or not the 
brine was pH treated to expel dissolved carbon dioxide. Because of 
presence of excess bicarbonate ions did not appear to adversely affect 
either strength or stability of the final crosslinked gel, it was 
generally not necessary for the water to be treated by first lowering the 
pH to 3 to expel carbon dioxide and then raising it back to a pH of 7. 
However, it was still necessary to adjust the brine pH to between 7 and 8 
for the HEC to successfully hydrate. 
At 150.degree. F., the encapsulated ammonium persulfate breaker produced 
the most satisfactory results. A concentration of 20 lbm/1000 gal was 
sufficient to break the gel in 24 hours at 150.degree. F. At 200.degree. 
F., while encapsulated ammonium persulfate could indeed break the gel to a 
water-like consistency, but it began to break the gel about an hour after 
being brought up to temperature, quickly makling the gel too weak to stop 
leakoff. Calcium peroxide was found to interfere with the crosslinkng 
process and produced a much softer crosslinked gel. It also left more 
precipitates once the gel was broken. 
Sodium bromate was also tested at 200.degree. F., but it is not effective 
by itself at temperatures below 250.degree. F. Past research has shown 
that the addition of small amounts of transition metal compounds, for 
example compounds of Fe.sup.2+ and Cu.sup.2+, catalyzes the reaction 
between sodium bromate and the crosslinked gel, making sodium bromate 
effective at lower temperatures. After testing copper, ferrous, cobalt, 
and nickel ions, it was found that Cu.sup.2+ compounds appeared to work 
the best with the crosslinked HEC system. The compounds tested were 
ferrous sulfate, nickel sulfate, cobalt sulfate and copper (II) chloride 
dihydrate. A concentration of 3 lbm/1000 gal of breaker aid (copper (II) 
chloride dihydrate) and 30 lbm/1000 gal sodium bromate produced the best 
results for a 24 hour break at 200.degree. F. The encapsulated sodium 
bromate was found to be effective at 250.degree. F. 
2. Fluid Loss and Cleanup 
The static fluid loss tests were conducted using two similar leakoff cells. 
The first test apparatus consisted of 1 inch diameter by 1 inch length 
core holder, a heat jacket, and a 250 ml fluid reservoir. The apparatus is 
similar to the second test apparatus called an HPHT (High Pressure High 
Temperature) static leakoff cell, which houses a 2.5 inch diameter by 1/4 
inch length core. The test results obtained from leakoff cells were 
compared and rendered comparable results. Table 2 shows the fluid loss and 
cleanup experiments conducted with the crosslinked pill using 1" diameter 
by 1/4" length cores in the first test apparatus. The core permeability 
used for all tests was 1000 md. The testing procedure was described in the 
previous section. It is notable that under a differential pressure of 150 
psi per 1/4", equivalent to 6000 psi per ft in terms of field units, only 
trace amounts of filtrate leaked through the disk. The observation means 
that the gel penetration depth is less than one quarter inch when an 
overbalance of 6000 psi differential pressure exists, which demonstrated 
the excellent fluid loss control capability of the crosslinked HEC gel. 
Table 2 also shows the regained permeability after the gel is broken by the 
internal breaker attacked for about 24 hours. Greater than 80% of regained 
permeability can be obtained using only the internal breakers. The gel can 
be easily removed by using an external breaker, for example, 10% HCl 
achieved 100% regained permeability. 
The test results obtained from the HPHT apparatus are described in Example 
1A. 
TABLE 2 
__________________________________________________________________________ 
Fluid Loss and Cleanup Tests in 1000 md Ceramic Cores Using the First 
Test Apparatus 
Core Length (Thickness) = 0.25 inch 
Core Diameter = 1.00 inch 
Core Area = 5.06 cm.sup.2 
All systems contained internal breakers 
Temper- 
Initial 
Cumulative Leakoff Volume 
Acid 
Regain 
ature time (ml/cm.sup.2) soak 1 time % 
(.degree. F.) 
(sec) 
0 min 
1 min 
15 min 
30 min 
hour 
(sec) 
regain 
__________________________________________________________________________ 
150 10.00 
0.24 
-- 0.29 
0.33 no 10.87 
92 
150 10.00 -- -- -- 0.20 no 11.38 88 
200 10.81 1.28 1.34 1.46 1.50 yes 10.59 100 
200 15.00 0.26 0.36 0.51 0.58 no 18.12 83 
200 10.50 0.01 0.06 0.16 0.20 no 9.12 100 
250 12.30 0.30 -- 0.51 0.59 no 
__________________________________________________________________________ 
Dried Crosslinked HEC Particulate 
It is often desirable to be able to quickly spot a fluid loss control pill 
downhole as soon as the formation is perforated and loss of completion 
fluid occurs. Mixing the pill from scratch may take too much time, 
therefore a pre-crosslinked particulate system is provided to achieve the 
rapid mixing and pumping purpose. The material is manufactured in a dry 
particulate form. These particulates will rehydrate when the particles 
reach formation, and form a filter-cake on the face of the wellbore. These 
polymer-based solid particles can be used in a fracturing treatment as 
fluid loss control additives. The advantage of these particles over 
insoluble particles commonly used in a fracturing operation is that these 
polymer-based particles will break to a water-like consistency with 
minimal residue by breakers commonly used to break fracturing fluids. 
The particulate system is produced by first making a batch of crosslinked 
gel, shredding the crosslinked gel into small particles by extrusion, 
coating the shredded particles with HEC powder, hardening the coated 
particles by drying, and then grinding the hardened particles to a fine 
grained material. The HEC is preferably crosslinked by zirconium, and 
since no delay is required, NaOH can be used to raise fluid pH and to form 
strong crosslinked gel. The gel can then be extruded through a perforated 
pipe and tumbled in a HEC powder-filled roller tank so that the material 
can be coated with HEC powder and dried at the same time. The lumped dry 
particles can then be ground to fine particles from 10 to 200, preferably 
from 60 to 100, meshes on the U.S. Sieve Series. 
The fine particles can be added to the blender tank on location. Since they 
do not hydrate and thicken the water immediately, low friction pressure 
will be observed while pumping. Once they reach the formation face, the 
particles start to hydrate and form a filter-cake to prevent fluid loss. 
The advantage of this approach is that the pill can behave as a solid 
fluid loss system, such as an often used carbonate pill, but the particles 
form a tighter crosslinked network on the face of the rock once they start 
to hydrate. Further, there is no solid invasion nor permanent formation 
damage usually associated with the calcium carbonate pills. Furthermore, 
the reaction between these particles and external breakers is slower 
compared to the instantaneous reaction between acid and calcium carbonate. 
This allows a more uniform removal of the filtercake in long vertical or 
horizontal intervals, and provides a means for breaker circulation, which 
is very difficult to achieve with the calcium carbonate system. The system 
of the present invention has advantages in shelf life and effectiveness on 
bridging large pore throats when very high permeability or fractured 
formations are encountered. 
Example 1A 
Leakoff and Cleanup Performance of Crosslinked HEC Pill Using HPHT Testing 
Equipment 
Summary and Remarks 
The crosslinked HEC viscous pill was lab tested using the second or HPHT 
leakoff test equipment. Two major performances of the pill were evaluated, 
first fluid loss control through high permeability formations (&gt;1000 md), 
and secondly the cleanup ofthe matrix after leakoff. The tests were 
conducted at 150.degree. F. and 200.degree. F. Each test consisted of an 
initial permeability measurement, a fluid loss control measurement, 
shut-in period, and a regained permeability measurement. External breaker 
treatment before regained permeability measurement was an optional step. 
The tests at both 150.degree. F. and 200.degree. F. showed good results. At 
150.degree. F., leakoff through a 1.8 darcy aluminum oxide core was 
approximately 0.2 ml/cm.sup.2. Regained permeability in the range of 80 to 
90% relying on internal breakers only was achieved. With an external acid 
breaker, regained permeability reached 100%. At 200.degree. F., leakoff 
was 0.29 ml/cm.sup.2 through a 800 md berea sandstone core and the 
regained permeability with only internal breaker was 83%. These test 
results obtained with the HPHT equipment were comparable to those 
performed in Example 1 using different equipment, which showed good 
consistency of the pill of the present invention and repeatability of the 
tests. Typically, core permeabilities used to test competitor systems were 
500 md and lower. Therefore, the crosslinked pill of the present invention 
passed more stringent conditions. 
Pill Composition and Mixing Sequence 
9 ppg KCl brine 
2% methanol--temperature stabilizer 
1.5% sodium lactate (60% active)--delaying agent 
0.35 gal/1000 pH adjusting agent (30% NaOH solution) 
36 gal/1000 gal liquid HEC (40% by weight HEC) gelling agent 
12 gal/1000 gal zirconium crosslinker (zirconium lactate) 
20 gal/1000 gal magnesium oxide crosslinker activator (17% MgO and 83% 
mineral oil) 
100 lb/1000 gal tetrasodium EDTA crosslinker enhance agent 
Breaker for 150.degree. F.: 
25 lbm/1000 gal encapsulated ammonium persulfate breaker 
Breaker for 200.degree. F.: 
3 lbm/1000 gal copper (II) chloride dihydrate as a breaker activator or aid 
30 lbm/1000 gal sodium bromate as a breaker 
For every 1000 ml of linear gel: 
Add 965 ml of 9 ppg KCl brine 
Add 20 ml of methanol 
Add 15 ml of sodium lactate (60% active) 
Add 36 ml of liquid HEC slurry (40% by weight HEC) 
Add 0.35 ml of 30% NaOH solution 
Hydrate for 30 minutes 
Extract 300 ml of linear gel for crosslinking. 
Add breakers 
Add 3.6 ml zirconium crosslinker (zirconium lactate) 
Add 6 ml magnesium oxide slurry (17% by weight MgO and 83% by weight 
mineral oil) 
Add 3.6 g tetrasodium EDTA 
Testing Equipment 
The second or HPHT test leakoff equipment consisted of a 400 ml stainless 
steel cylinder with a plastic lining. The cell was designed to hold a 2.5 
inch diameter core, with 1/4 inch thickness at the bottom ofthe 
cylindrical cell. The flow chamber had a smaller diameter than the core to 
avoid fluid flow around the outside edge of the core. A manual on-off 
valve was located at the bottom of the cell so the effluent would be 
collected. A pressure port on top of the cell was to connect with a 
pressure source so differential pressure could be applied. The cell was 
fitted into a BAROID controllable heat jacket for temperature control. 
Description and Discussions 
Local tap water was first checked for the effect on pill quality. A 9 ppg 
(12%) KCl brine was mixed using field grade KCl and tap water. Two percent 
methanol and 1.5% sodium lactate (60% active) were added to the brine in 
the blender and pH was measured to be 6. 120 lbm/1000 gal of liquid HEC 
was then added to the blender. After being well mixed, 0.35 gal/1000 gal 
of 30% NaOH was added to raise pH up to about 7.5. Rapid HEC hydration was 
observed by the closing of the vortex in the blender. The linear gel was 
then allowed to sit to fully hydrate for 30 minutes. The crosslinker and 
activators were then added to the linear HEC. A consistent delay time of 
12 minutes and crosslinked strength were observed. Therefore, the water 
source did not affect the chemistry of the pill. 
Test 1 
A KCl brine saturated aluminum oxide disk (marked FAO-10, 2.5" diameter, 
1/4" thick) was loaded into the HPHT cell. The mean pore throat diameter 
of this aluminum oxide core was 43 micron, which translated to about 1.8 
darcy in permeability. The cell was then filled with 350 ml of 3% ammonium 
chloride (NH.sub.4 Cl), heated to 150.degree. F., and 100 psi drive 
pressure was applied to the top of the cell. When the temperature of the 
fluid and the core reached the target temperature (150.degree. F.), the 
bottom valve was opened and the time required to flush 300 ml of the brine 
was recorded as an indication of the initial permeability. It took about 
5.5 seconds to flush 300 ml of 3% NH.sub.4 Cl brine. The remaining brine 
in the cell was drained out by gravity. The bottom valve was then closed 
and the cell was filled with 300 ml of the pill. The gel contained an 
internal breaker of 25 lbm/1000 gal encapsulated ammonium persulfate 
breaker. The cell was set for 40 minutes to let the gel heat up to 
temperature. The bottom valve was then opened to collect filtrate for 30 
minutes. Table 1A shows the accumulative filtrate volume over 30 minutes. 
Total leakoff volume was 6.2 mls, equivalent to 0.2 ml/cm.sup.2. This 
result was comparable to the result obtained in Example 1. It is 
comparable to the reported result for a competitor's system using a 500 ml 
core, which is only one third of the permeability used in this test. 
Therefore, the system of the present invention tested favorably under a 
more stringent condition. 
The cell was shut in for 24 hours for the gel to break by the internal 
breaker. A comparison sample was prepared and set in the water bath to 
observe the rheology. After 24 hours, the gel in the water bath was seen 
broken to the consistency of water with minor amount of residue floating 
on top. The bottom valve of the HPHT cell was opened to push all the 
broken gel and residue through the core, which is a more stringent test 
than reversing flow through the core. The cell was then refilled with 3% 
NH.sub.4 Cl, heated and flushed through the core with 100 psi drive 
pressure. The time to flush 300 ml of brine was 20.1 seconds, which 
translated to be a 27% regain (5.5/20.1). The core was flipped to measure 
the reversed permeability. The time was 15.37 seconds (36%). These were 
worse results and inconsistent with the result obtained in Example 1. 
Therefore, a 15% acid was used to treat the core. After 30 minute acid 
soak, the flow time was 13.02 seconds (42%). As the pressure inlet was 
disconnected to clean up the equipment, it was found the pressure port was 
plugged, so there was a restriction to the nitrogen flow even though the 
pressure gauge on the regulator showed 100 psi drive pressure. The 
equipment problem was then resolved and the post acid treatment 
permeability was re-run. The time to flow 300 ml was only 4.41 seconds. If 
the ratio of 13.02 to 4.41 seconds was assumed, the regain before 
acidizing would have been higher by a factor of about 3, which meant 80 to 
100%. 
Test 2 
The second test was run at 200.degree. F. with an 800 md berea sandstone 
disk. The internal breakers used were 3 lbm/1000 gal copper chloride 
dihydrate plus 30 lbm/1000 gal sodium bromate. All the other testing 
parameters were identical to the first test. The initial 3% NH.sub.4 Cl 
flow time was 4.94 seconds. The overall leakoff was 8.9 mls (0.29 
ml/cm.sup.2). After shutting in for 24 hours, the broken gel was pushed 
through the core. There was a thick filtercake formed by the residue on 
the face of the core. Hence, the core was flipped to measure the reversed 
permeability. The flow time was 5.91 seconds, which is equivalent to 83% 
cleanup. After opening the cell, it was observed that the filtercake was 
removed by the hydrodynamic force. This phenomena was also observed while 
testing in Example 1. No acidizing was required to restore the matrix 
permeability. 
Test 3 
The third test was a re-run of the first, so the test was run at 
150.degree. F. with another FAO-10 aluminum oxide disk. The internal 
breaker used was 25 lbm/1000 gal encapsulated ammonium persulfate. The 
initial 3% NH.sub.4 Cl flow time was identical to the first test, 5.5 
seconds. After 300 ml of brine was flushed through the core, the remaining 
50 ml in the cell was flushed out by 100 psi instead of hydrostatic 
pressure used in the first test. The purpose was to let air purge the 
core, and to see if the saturation of the core affected the filtrate 
volume. The overall leakoff was only 1.5 mls (0.05 ml/cm.sup.2). The core 
was acidize after a 24 hour shut in. The acidizing step was not necessary 
because of the already effective internal breaker. After shutting in for 
24 hours, the broken gel was pushed through the core. Three hundred fifty 
milliliters (350 ml) of 10% HCl plus 15 lbm/1000 citric acid was poured 
into the cell and soaked for 1 hour. After flushing acid through the core, 
the cell was refilled with 350 ml of 3% NH.sub.4 Cl. The final flow time 
was 5.08 seconds, which is above 100% regain. 
__________________________________________________________________________ 
Cumulative Leakoff Regain 
Initial Volume (ml) After 
Time 
0 1 15 30 Regain (sec) 
Acid 
% 
Core (sec) 
min 
min 
min 
min 
Forward 
Reverse 
(sec) 
regain 
__________________________________________________________________________ 
FAO-10 Aloxide, 
5.5 
2.5 
3.2 
5 6.2 
20.1* 
15.4* 
4.41 
100 
1855 md 
Berea Sandstone, 4.9 2.0 4.6 7.6 8.9 42.6 5.91 83 
800 md 
FAO-10 Aloxide, 5.5 1.1 1.2 1.4 1.5 5.08 100 
1855 md 
__________________________________________________________________________ 
*Pressure port was plugged - see explanation in the description of test 1 
The crosslinked HEC pill showed good consistency when mixed with the local 
water source. The fluid loss control capability through high permeability 
cores was excellent. According to the testing parameters and results, the 
gel penetration depth was less than 1/4" when subjected to 4800 psi/ft 
differential pressure. Accordingly, the formation would be undisturbed by 
the gel. The cleanup efficiency with only internal breaker was above 80 to 
nearly 100%. The gel can be easily cleaned up by acid, such that 100% 
permeability can be restored. 
(Prophetic) Example 2 
Open-Hole Isolation Method for Multi-frac Horizontal Well 
A crosslinked gel is used as an open-hole isolation plug for multi-frac in 
horizontal wells. The gel plug can be chemically removed by flushing with 
an acid. FIG. 6a, 6b and 6c show an embodiment for the frac-plug-frac 
operation in which the crosslinked gel is used. Step one is to set a low 
cost retrievable platform, e.g., an inflatable packer 120, at the end of 
gel plug 122, which is above the first set of fractures 124. This low cost 
retrievable platform could be an inflatable packer, petal basket, etc. The 
function of this platform is to serve as a back wall for the gel fluid, so 
the fluid will not keep flowing along the bottom of the horizontal 
wellbore 126. This way, a more uniform cylindrical gel plug 122 can form, 
leaving as little void space in the gel plug as possible after final 
crosslinked strength is attained. While spotting the gel (see FIG. 6a), 
the tubing 128 will be pulled slowly so the fluid can evenly fill the 
wellbore. 
As shown in FIG. 6b, step two is to set a second platform 130 where it will 
prevent extrusion of the gel when pressure is applied to fracture the next 
zone. The second platform 130 will also prevent or minimize the splitting 
of the crosslinked gel by the fracturing pressure. The fracturing pressure 
creates the second set of fractures 132 as shown in FIG. 6c. The function 
of this second platform 130 can be viewed as a spacer between the 
fracturing fluid and the gel plug 122. FIG. 7a illustrates that if the 
fracturing fluid comes in contact directly with the gel plug 122, it would 
create a tensile stress and may split the gel plug by tensile failure, 
then channels 140 may form. FIG. 7b illustrates that the spacer 130 will 
convert the force applied on the plug 122 and the first platform 120 to 
compressive stress. Since the compressive strength of the material is much 
higher than the tensile strength, the risk of plug failure is greatly 
reduced. 
To successfully separate the existing fractures and new target zone, the 
gel needs to have high viscosity and yield strength to withstand the 
differential pressure during fracturing process. The gel will fill a long 
section of the wellbore, so that the pressure gradient (psi/ft) can be 
balanced out by the gel resilience. Therefore, very little to no movement 
of the gel plug is achieved. To quantify the effective gel viscosity and 
length requirement, the gel plug is assumed to be a viscous fluid system 
which can flow under differential pressure in the wellbore after it is 
set. The equation of fluid flow in a pipe can be used to predict the 
viscosity requirement for the crosslinked fluid. FIG. 8 illustrates the 
viscous fluid (i.e., gel plug 122) flowing (Q) in a given diameter (D) 
wellbore 126 with a given pressure gradient (.DELTA.P), the viscosity 
requirement (.mu..sub.eff) can be calculated if very low gel flow rate is 
allowed by using Hagen-Poiseuille equation. FIG. 9 shows an example of the 
viscosity requirement versus gel plug length in a 41/2 inch diameter 
wellbore if only 12 ft/day of plug movement is allowed. Note that the 
viscosity seems to be unreasonably high. However, the crosslinked gel is 
elastic in nature, rather than being simply a viscous fluid. Therefore, it 
partially contains the rigidity and yield strength of a solid material. 
Experiments can be run to convert the crosslinked gel strength to the 
equivalent apparent viscosity. For example, one such experiment to be 
carried out in the lab is to fill a pipe or tubing with the crosslinked 
gel. After the crosslinked gel is set, apply differential pressure until 
the fluid starts to flow. The flow rate and differential pressure are 
recorded for effective viscosity calculation. To scale up from the lab 
testing to the horizontal open-hole, the effective viscosity obtained from 
the experiment will be used to back calculate the plug length required for 
operating differential pressure. 
The viscous pill is batch mixed so only a mixing tank and a pumping unit is 
needed. No additional metering equipment is required. The crosslink is 
delayed by both pH and thermal activation. 
Example 3 
Elasticity of the Zirconium Crosslinked HEC Fluid 
In this example, the elasticity of a zirconium crosslinked HEC fluid is 
measured with a Rheometrics Pressure Rheometer set at 2 radians per second 
with a 10% strain. The zirconium crosslinked HEC fluid was prepared using 
an HEC slurry (40% by weight HEC), 9 lbm of KCl per thousand gallons of 
fluid, 12 gallons of zirconium lactate (60% active) per thousand gallons 
of fluid, 20 lbm of magnesium oxide per thousand gallons of fluid and 100 
lbm of tetrasodium EDTA per thousand gallons of fluid. The elastic 
modulus, G'(dyne/cm.sup.2) versus time in minutes and the corresponding 
temperature in degrees Fahrenheit versus time in minutes is shown in FIG. 
12. 
A crosslinked gel behaves both as an elastic solid and a viscous fluid. The 
solid-like property can be measured by subjecting the gel to small 
amplitude oscillatory shear, and characterized by an elastic modulus, G'. 
The higher the value of G', the more elastic, i.e., more rigid the gel is. 
A common fracturing fluid containing 40 lbm of hydroxypropylguar (HPG) per 
thousand gallons of fluid crosslinked with borate exhibits a G' of 
approximately 25 dyne/cm.sup.2 at room temperature and decreases to 
approximately 10 dyne/cm.sup.2 at 149.degree. F. As FIG. 12 shows, the 
crosslinked HEC gel of the present invention possesses a G' of 
approximately 1,500 dyne/cm.sup.2 at 120.degree. F. This measurement shows 
the highly elastic, solid-like nature of the fluid system of the present 
invention.