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4702
Advances in Well Completion
And Stimulation During JPTs
First Quarter Century
R, F. Krueger, SPE-AIME, Union Oil Co. of California
Introduction
It is with pleasure, but some trepidation, that I re-
vie-w industry progress in well completion and well
stimulation for this Silver Anniversary celebration
of the lournaf of P et r ol eu m T ech nol ogy (J PT). I
am pleased because I would like to emphasize the
valuable role that JPT has played in engineering
communication. In my opinion, the sharing of re-
search advances and field developments in JPT has
provided a synergism that has had an important bear-
ing on the great technical achievements of the petro-
leum industry. Each sharing has triggered a chain
reaction of new ideas and new work that has re-
sulted in an explosion of technology,
On the other hand, I have some misgivings about
my task, because the areas of well completion and
stimulation are so broad in scope and the important
technical advances so numerous that it is impossible
to give proper recognition to all in a review article.
There are many hundreds of papers about these
operations, and anyone attempting to summarize ad-
vances in them certainly assumes the strong risk of
offending many important contributors by omission.
Undoubtedly, a different author with a different
background might emphasize different papers; how-
ever, I have attempted to minimize the risk by draw-
ing liberally on the. opinions of others to help me in
my task, Because of space limitations, in some in-
stances a choice of references had to be made be-
tween the original, idealized work on a given subject
and later work that extended the analysis to include
:onditions closer to actual well conditions. When
the original work was the basic study that opened
a new area for study, it was used as the primary
reference,
Since this issue of JPT commemorates a quarter
century of service, my objective will be to give a
broad overview of each main topic, with emphasis
on the role that JPT played in communicating new
technology. The discussion will not attempt to refer
to all the technology in well completion and stimula-
tion, but only to highlight a few of the important
developments and concepts. The importance of
JPTs role will become obvious from the number of
references cited in JPT relative to major technical
advances. However, in some areas for example,
formation damage by drilling fluids and sand con-
trol
some of the early basic work was published
in other journals and will be used. Nevertheless, as
one searches the literature, it soon becomes obvious
that the stature of JPT rapidly grew after its incep-
tion in 1949, and by the middle 1950s virtually all
of the major technical advances were appearing in
JPT,
Under the broad heading of Well Completion we
shall discuss completion mechanics, completion fluids,
cementing, perforating, and sand control. The empha-
sis in the discussion of drilling and completion fluids
will be r their effect on the formation; it is assumed
Jhe sharing oj research advances and field developments in JPT has provided a
synergism that has had an important bearing on the great technical achievements of the
petroleum industry Each sharing has triggered a chain reactipn of
new
ideas and new
work that has resulted in an explosion of technology
DECEMBER, 1973
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that the formulation and function of drilling fluids
wilt be covered elsewhere.
Under Well Stimulation, we shall discuss only
acidizing and fracturing because they are the two
main processes used. Space limitations preclude dis-
cussion of solvent stimulation, high-rate backflush-
ing, wellbore heating, explosive shooting and the
like, which are used to a lesser extent.
Completion Mechanics
In response to increasing demand and declining re-
serves, the oil industry has sought and successfully
found oil at greater depths and in more hostile en-
vironments, and simultaneously it has developed new
methods for stimulating wells and improving re-
covery from existing fields. The rapidly advancing
technology has placed more rigorous and specialized
demands on well completion mechanics. To meet the
technical and economic challenges, a steady stream
of new completion equipment and new procedures
has been developed and offered to the industry. At
times, advances have been so rapid that it has been
difficult for the practicing engineer to keep up with
them. Fortunately, JPT has provided a forum for
the discussion and technical evaluation of these new
developments.
During JPTs 25-year lifetime, the industry has
seen the development of many completion inno-
vations, such as permanent-type, concentric, and
tubingless completions, the rapid g,owth of multiple
completions, pioneering work in subsea completions,
new rigless workover technology, specialized tiesign
of pipe strings for hot wells at extreme depths or in
thermal stimulation projects, and special wellhead
and completion designs for floating drilling opera-
tions. The papers discussed below highlight a fcw of
the many important developments that JPT has
brought to the attention of the industry,
Permanent Completions
One of the most important of the new developments
was the permanent-type well completion reported in
1953 bv Huber and Tausch.: In this type, the tubing
and wellhead are set in place when the WCI1is first
completed, and all subsequent completion and
remedial work is done through the tubing with wire-
line tools. As a result of this simplification, the cost
of well completion and workover operations is con-
siderably less than that of conventional completions.
Because of the economic advantages and well con-
trol afforded, the permanent-type completion has
been widely accepted. The authors reported rig time
savings of 1 to 3 days during completion and a 75
percent reduction in the costs of certain types of
workovers, The use of solids-free, compatible fluid.
instead of drilling mud, during completion and work-
over results in better well productivity; and the high
degree of well control permits selective evaluation of
the reservoir without killing the well,
Some other advantages of permanent completions
are that (1) more reliable and accurate reservoir in-
formation is obtained; (2) actual oil and water con-
tacts may be determined economically with the well
on production; and (3) the use of tubing extensions
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permits cementing and well-treating operations with.
out an auxiliary rig.
Multiple Completions
The second paper included in this review of well
completion mechanics illustrates another important
service JPT provides the practicing engineerstate-
of-the-art awareness, I n 1958 Althouse and Fisher,s
in a state-of-the-art paper, managed to put the tech-
nology of multiple completions in perspective.
During Worid War 11, the use of multiple com-
pletions expanded rapidly as a means of maximizing
production with a minimum consumption of steel.
Through misapplication, multiple completion tech-
nology almost died; but with the advent of offshore
operations, the huge costs of field development and
well completion made multiple completions an eco-
nomic necessity. During the 1950s, the development
of multiple completion technology mushroomed so
rapidly that it bccamc almost impossible to keep up
to date on ncw techniques and equipment. Operating
engineers were faced with selecting multiple well
completion hookups that not only were practical but
also satisfied the economic limitations of their par-
ticular area. Probably in most cases multiple com-
pletions were not economically feasible, but it was
difficult to ferret out the facts.
Althouse and Fishers comprehensive review of
multiple completion technology provided operating
engineers with a rational basis for evaluating the
applicability of this technology to Lhcir own needs.
Their paper discussed the equipment available, the
general principles of various types of multiple com-
pletion. and the over-all economics to be cxpectcd.
A breakdown of costs for some typical offshore com-
pletions was shown.
For such high-cost operations,
nearly 90 percent of the completion costs arc in-
dependent of the special costs associated with mul-
tip]e completions; therefore, the dream of obtaining
two, three, or four completions for the price of one
is almost reality.
Subsea Completion System
As industry operations moved increasingly oflshorc,
the technical and economic aspects of well con~ple-
tions were magnified. In response to the new trend,
JPT published numerous papers dealing with these
problems. We shall discuss two developments that
should lUWCa strong economic impact.
One of tiie more difficult problenls is finding a
way to make subsea completions economically viable.
An important step toward this goal was the develop-
ment of technology for remote completion, produc-
tion, and workover of an underwater satellite well
without rig assistance. The first successful denlon-
stration of this development was described by Rig.g
et Il
n 1966. A suite of special completion and
workover tools that could be hydraulically pumped
down hole was developed to perform virtually all
operations in a remote satellite well; and the feasi-
bility of through-flowline operations was denlon-
stratcd successfully, first in simulated operations on-
shore and then in an actual underwater completion.
This pioneering work significantly extended the prac-
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tical and economic potential of underwater comple-
tions and provided the basis for new subsea technol-
ogy that may make previously unrecoverable reserves
profitable.
Offshore Concentric Tubing Workover Procedure
Franks introduction in 1968 of an improved concen-
tric tubing workover technique was an important con-
tribution toward reducing offshore workover costs. 3
The technique makes use of small-diameter tubing
run inside the production tubing to perform the work-
over operations, and is applicable in directional holes
as well as straight holes. Time savings and reduced
rig cost result from the elimination of the need to
retrieve and rerun tubing and packers. Frank de-
scribed special workover techniques for sand wash-
ing, sand consolidation, perforating, cementing, and
pipe repair, and the methods are now widely used.
The offshore concentric rig designed for this work
is completely self-contained and readily transport-
able. At first, the work strings used with concentric
tubing rigs were 1-in. N-80 pipe with tool joint con-
nections. In recent years, further rig savings have
been achieved through the use of continuous-string
workover rigs, described by Slater and Hansonr in
1965. This unit runs continuous, small-diameter tub-
ing inside production tubing at speeds far greater
than those for conventional workover pipe strings.
Prediction of Tubing Tension and Movement
Completions in deeper, hotter wells and the rapid
growth of thermal stimulation operations have made
it increasingly important to take into account the
effects of temperature and pressure when perforating
and treating wells through a tubing and packer. If the
tubing is free to move inside the packer, changes in
temperature and pressure in the well will increase or
decrease the Icngth of the tubing; if the tubing is
constrained in the packer, forces are induced in the
tubing and packer. Pipe collapse has been observed
when steam is injected into wells; tensile failure has
been reported when constrained tubing in a deep, hot
well is cooled down by injecting large volumes of
cool treating fluid, such as acid. If tubing pulls out
of a packer, well failure may occur; packer fluid
dumped onto the producing formation may damage
well productivity, and upper casing may be exposed
to excessive pressure.
In 1962, Lubinski et al. published a mathemat-
ical method for px:dicting the forces and pipe move-
ment caused by these condmons, taking into account
the effect of helical buckling. They showed that buck-
ling may occur even when the tubing is initially under
tension and that in deep wells tubing may take a
permanent helical set, particularly inside large casing.
Their paper provided a practical basis for solving the
many tubing problems associated with temperature
and pressure changes, and several common problems
mentioned above were examined. This basic study
has been extended and computerized by subsequent
workers, and the practicing field engineer now has
access to rapid solutions of particular and complex
problems in his own operations,
DECEMBER, 1973
Drilling-In and Completion Fluids
Forty years ago when new fields and gushers made
oil a glut on the market, there was ittle concern for
damage to well productivity. Today, however, it is
widely acknowledged that drilling and completion
fluids can, indeed, significantly affect well produc-
tivity and that serious damage can occur if proper
care is not given these fluids during the operating
procedure. As usual, the present highly developed
technology Mthe result of a succession of field obser-
vations and painstaking experiments, each building
upon previous ones. As a result we know today that
damage from drilling fluids results primarily from
(1) the effect of the filtrate from the fluid upon the
formation components, and (2) the invasion of the
pore space by solid particles from the fluid.
Formation Damage From Water and Mud Filtrates
In the early 30s, observers and far-sighted engineers
noted that the performance of some wells did not
come up (o expectations, and their findings led to
speculation and differences of opinion as to the cause
of the noted eflccts. During the following decade,
many laboratory studies demonstrated that the com-
position of a fluid flowing through a sandstone core
has a radical effect on the specific permeability to
water; for example, when a brine-saturated core is
flooded with fresh water, the specific permeability to
fresh water is often much Icss than the original per-
meability to brine. Field studies confirmed that a well
exposed to fresh water for only a short time could be
significantly and permanently damaged. The observed
permeability damage was ascribed to swelling of clays
and blockage of pore spaces in the rock. A natural
outgrowth of this work was the development of sal ine
and oil-base completion ffuids.
Recognizing the growing concern about formation
damage, Nowak and Krueger{ reported in 1951 on
the effects of various drilling ffuids on formation rock
under both static and dynamic conditions, Using
restored-state cores saturated with oil and interstitial
brine, they observed that permeability to oil was also
adversely affcctcd by invasion of fresh water and
fresh water mud filtrates. Permeability damage was
minimized with saline and oil filtrates; multivalcnt-
ion salts were found to be more effective than sodium
chforide for controlling permeability damage. An im-
portant observation was that, even in extreme cases
of water sensitivity involving almost complete loss of
the specific permeability to water. flow of oil follow-
ing water invasion restored permeability to oil to
practical Icvels that were usually many times greater
than the specific permeability to water. Nevertheless,
experience through the years has shown that essen-
tially all sandstones are water sensitive to some
degree, and permeability to on after lre~n water ;nva-
sion may range from 10 to 90 percent of the specific
air permeability, Fortunately, tke damage to well pro-
ductivity in a radial system can be minimized by
restricting the depth of invasion through good fl~lid-
10SScontrol. This work was the first to associate per-
meability damage with particle movement, as well as
with clay swelling, when water-sensitive sandstone
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cores were observed to discharge colloidal clays.
Influence of Chemical Composition on
Water Sensitivity
As a result of the early work on water sensitivity of
sandstones, fluids containing salts of sodium, calcium,
magnesium, zirconium, potassium. and other cations
have been used to control or restrict permeability
damage in aqueous systems. At first, it
w as
not
thought possible to take advantage of the inhibiting
properties of these salts when large volumes of water
are used for waterflooding. }Iowever, in 1969 Joncsge
reported a means of using small quantities of divalent
cations to control clay blockage in water-sensitive
formations. He showed that potentially sensitive for-
mations can be exposed to fresh water if at least 1/1 O
of the dissolved salts in both the formation water and
the invading water are calcium and magnesium salts .
Abrupt reductions in salinity can cause permeability
damage, whereas gradual changes may have little
effect. Jones practical approach to alleviating the
effects of water sensitivity is to select an effective ion
composition and concentration, and then gradually
reduce the concentration to an economic level, Many
applications of Jones work are apparent in drilling,
completion, workover, well stimulation, and water-
ffooding,
Formdion Damage From Particle Invasion
Before 1949, several studies investigated pore plug-
ging from drilling fluid invasion in water-saturated
cores exposed to fluid under static conditions.
Although invasion by mud solids was inferred, the
effect of the solids on permeability damage was ob-
scured by filt 1ate effects in the single-phase water
system and by an inability to relate the results to
down-hole dynamic conditions. To avoid these linli-
tations, several later studies simulated down-hole
conditions. using inert cores in the restored state and
dynamic mud flow. Underneath-the-bit conditions
were first simulated in tests reported~:~in 1951; above-
the-bit conditions were simulated in tests by Krueger
and Vogel in 1954. Glenn and SIussery ) further
extended this work and reported their results in JPT
in 1957.
These studies showed that submicron particles
from drilling fluids penetrated at least 2 to 5 cm into
the pore spaces; however, for certain particle-size/
pore-size relationships, particles were observed to
flow apparently unimpeded through the rock. An im-
portant conclusion from this work was that inter-
stitial invasion forms an internal mud cake inside
pore spaces. This cake is not entirely removed during
backflow and some permanent permeability damage
remains. The most severe invasion and damage
occurred during jetting and mechanical scraping
operations that simulated drilling conditions. The
degree of damage was observed to be a function of
time of exposure and total volume of filtrate flowing
through the rock. These results confirmed field obser-
vations in certain formations.
Check Valve Pore Blocking
Because of ~he observed swelling of clays in water,
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early investigators assumed that permeability dam-
age was caused by swollen clay particles obstructing
the pore spaces, Were this the only effect, one would
expect that injection of salt solu[ions to shrink the
clays would reverse permeability damage, However,
both laboratory and fie d results show that per-
meability damage. once formed. cannot usually be
reversed by injection of dcswelling solutions. This
apparent anomaly is explained by the work of Gray
and Rex and Krueger cl al. who postulated that
micron- and submicron-size fragments of clays and
other minerals are dislodged by shearing forces on
weakly bonded mineral or clay crystals when salinity
changes occur. These fragments then are entrained
with the flowing fluids.
Monaghan CI
al .
and Krueger et td. attributed
the irreversibility of permeability damage to brush
heap
arrangements of dislodged clay particles,
which cannot be reordered by chemical treatments.
Monaghan etal showed that clay deswelling by base
exchange, or changes in clay properties with chem-
ical flushes, do not restore the original permeability
to clay-damaged sand packs, However, Krueger et
al. showed that the effects of water sensitivity can
be drastically reduced by low-velocity formation
cleanup, and damaged well productivity can some-
times be improved substantially by a backflush fol-
lowed by restricted drawdown.
Nonplugging Completion and Workover Fluids
One aspect of completion fluids that has not been
covered in the previous discussion is the problem of
perforating wells. As wc shall see in a later section,
research has demonstrated that perforations may be
severc]y plugged when shots are made With driW?
mud in the wellbore. Perforation plugging results
in low well productivity, fai urc of squeeze cementing
and sand control treatments, and many other operat-
ing problems. To prevent these problems, a clean,
solids-free fluid with low filtration rate and con-
trollable density is required.
Priest and Allen developed an emulsion fluid
with the necessary properties and reported the re-
sults of field usage to JPT readers in 1958, In line
with previous permeability-damage studies, calcium
chloride solution was used as the external phase.
Density variations were achieved by changing the
hydrocarbon content in the internal phase; and
filtrate loss was reduced with lignosulfonates. Re.
ported field results show that the productivity in-
dices of wells completed with the new fiuid were
substantially higher than those for offset wells per-
forated in mud or water. Fewer difficulties were
experienced in servicing wells and bringing them
back on production when the emulsion fluid was
used to protect the formation,
Formation Damage ControI in
Present Day Operations
As a result of the work summarized above, engineers
now have the basic information to minimize fotma-
tion damage during completion and workover. Inas-
much as nearly all sedimentary sandstones apparently
contain clay minerals and therefore exhibit water
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sensitivity in varying degrees, drilling-in and com-
pletion fluids should be selected to minimize both
the interaction of filtrate with the formation and
the depth of particle invasion, The work discussed
has provided the fundamental background that has
ed to the development and wide use of oil-base
and saline drilling and workover fluids. For many
years, calcium-base fluids were popular; in recent
years, however, owing to their special advantages,
potassium fluids are increasingly used. Because of
the radial-system geometry that applies, the proper
choice of fluid properties can keep formation dam-
age to moderate levels. Well productivities of 85 to
90 percent t f undamaged values are attainable; and
under ideal conditions, nearly undamaged produc-
tivities can be achieved.
The technological advances derived from the above
formation damage studies have significant economic
impact because they not only bring about a material
increase in recovery of oil in place, but make it avail-
able in the shortest reasonable time.
Cementing
Probably no other operation in the producing life
of a well has a more critical effect than cementing.
Sealing of water zones,
isolation of producing in-
tervals, control of injected fluids during secondary
recovery, control of well stimulation treatments, and
many other operations all depend upon obtaining
a good-quality cement job. It is not surprising then
that considerable study has been devoted to cement-
ing materials and techniques, Yet one of the most
commonly heard comments is, We cannot treat
this well because fluid channels through the cement
behind the pipe.
Cementing was first introduced to the industry
in 1903 when it was used to shut off water above
an oil sand in the Lompoc field, Calif. In the early
1900s construction cement and high-early-strength
cement were used for cementing wells, and many
down-hole problems were thought to be associated
with variations in their properties. Thus the first
laboratory studies of cementing were aimed pri-
marily at determining properties such as compres-
sive strength and pumpability at down-hole tempera-
tures. As new and special cements were developed,
these tests became even more important.
One of the most significant steps forwaid was
Farris development*: in 1939 of a laboratory device
for measuring thickening time under both down-
hole temperature and down-hole pressure. His re-
sults quantized previous opinions that both high
pressure and high temperature would accelerate the
stiffening and setting of cement. With these data
it became possible to establish limits on the maxi-
mum recommended pumping time, Farris device
and the testing procedures developd with it provided
the basis for establishing quality standards and eval-
uating flow properties of cements.
A report on cementing technology would be in-
complete without mentioning the important role of
the API committees on standardization of cements
and cement testing procedures, and without recog-
DECEMBER, 1973
nizing the chairmen who guided their course: Carl
Dawson, Walter Rogers, George Howard, Francis
Anderson, William Bearden, and Robert Scott.
These committees brought quality control into ce-
menting operations, and established an orderly
basis for introducing the new types of cements re-
quired as well depths increased,
During the decade of the forties, several im-
portant studies were published on mud displace-
ment and mud-cake removal during cementing and
on the minimum waiting-on-cement time before
drilling out the cement. These studies provided the
basic engineering information necessary to place
sound cement with a good bond between casing
and formation. The basis for turbulent placement of
cement, use of scratchers or jets, and cement filtration
control was established during this time.
Special Cements
Through the years, many different types of cements
and cement additives have been developed to provide
special properties and to take care of particular down-
hole conditions. Retarders, accelerators, density mod-
ifiers, fluid-loss controllers, mud decontaminants
all have provided the engineer with important con-
trols over down-hole conditions, And at one time
or another all have been discussed in JPT publica-
tions, In the next few paragraphs, 1 should like to
highlight two papers dealing with special cements.
Cementing at High Temperatures.
First, let us look
at the problem of cementing deep wells. Recently,
a depth exceeding 30,000 ft was reached, and many
engineers are projecting depths of 50,000 ft in a
few years, Temperatures approaching 500F have
been encountered, and 700F is anticipated, Con-
ventional retarded cement compositions face many
problems at extreme temperatures: thickening time
will often be too short; although initial compressive
strength may be adequate, many compositions ex-
hibit strength retrogression, even
to
the point of
failure; permeability of the set cement may incrcasc.
In 1960, Ostroot and Walker undertook a com-
prehensive investigation of cementing materials and
techniques for use at temperatures of 500*F or
higher, They observed that most of the common
cementing compositions retrogress in strength after
prolonged exposure at these high temperatures, but
that the addition of high percentages of silica flour
inhibits this retrogression and results in compressive
strengths that are much higher than those of the
neat cement composition. Basic analytical studies
showed that the hydration products, calcium hy-
droxide and dicalcium silicate alpha hydrate, are
formed in cements in which strength retrogression
has occurred, and that the formation of the tober-
morite phase inhibits retrogression. The reported
data also showed that cements containing silica flour
had lower permeability than neat cement and that
they could be relarded effectively at extreme tem-
peratures with a modified lignin compound.
This paper was important to the industry because
it showed the nature of high-temperature cementing
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problems, and offered a means of combatting them
with readily available materials. By showing the
chemical changes associated with those problems,
the authors opened the way for basic improvements
in the composition of cements to be used at ex-
treme temperatures.
Cementing in Shales and Dirty Sands.
The second
paper deals with cementing in shale and bentonitic
sands. Cement jobs in such zones are often trouble-
some and expensive. Because of water sensitivity,
shale or bentonitic sand may deteriorate during ce-
menting with common fresh-water cements, and
isolation of zones may not be achieved. Remedial
squeeze cementing is often required. Although
brines and formation waters were used for many
years to combat the effects of water sensitivity for
well repair and well stimulation, the addition of
salt to cement to stabilize the formation or shales
during cementing had rarely been considered,
h 1962, Slagle and Smith- brought t o the indus-
trys attention the fact that salt cement could improve
both primary and squeeze cementing operations in
shales and dirty sands as well as in the salt formations
where they had been most widely used. Although
untreated cement slurry does contain calcium ions,
the low ionic content and high pH apparently permit
structural changes in clay-containing minerals. Addi-
tion of salt to cement slurry improves slurry proper-
ties, formation integrity, and bonding in shales and
clayey formations, Recognition of the value of salt
cements for cementing water-sensitive shales and
sands has broughi about wide usage,
Mechanics of Slurry Placeme~t
Much information has been published on the me-
chanics of mud displacement by cement, and on
techniques for maximizing displacement efficiency.
Despite this body of information, the reliability of
primary cementing is generally considered low. Re-
cently, two complementary investigations have re-
examined the displacement process.
The publications by McLean et al . and by Clark
and Carter are well worth careful study by anyone
interested in optimizing primary cementing opera-
tions in the field. McLean et al . investigated the dis-
placement process with both analytical and experi-
mental models, consisting of a single string of casing
eccentrically positioned in a round, smooth-walled
permeable borehole, Clark and Carter simulated
borehole conditions at 8,000 ft, including mud circu-
lation and filtration before cementing.
These studies illustrate pictorially the importance
of centralizing pipe and the critical effect of drag and
buoyancy forces on mud displacement, Mud on the
narrow side of an eccentric annulus is readily by-
passed, but moving the pipe, pumping in turbulent
flow, and minimizing density differences between
cement and mud promote etllcient mud removal.
Squeeze Cementing
For many years, the mechanism of squeeze cement-
ing remained somewhat of a mystery, and every
engineer had his own hypothesis as to where the
1452
cement goes during a squeeze job and how to make
the squeeze effective. In 1950, Howard and Fasta4
published in JPT the first basic study of the high-
-pressure squeeze cementing process, and their work
provided a more rational basis for improving field
procedures. They investigated squeeze cementing
theoretically and then field-tested their ideas, first in
shallow laboratory wells and then in commercial
oil wells. Their paper remains a basic reference
for all engineers wishing to become knowledgeable
in squeeze-cementing technology. Howard and Fasts
work provided graphic experimental evidence that
during squeeze operations formations break down in
an existing zone of weakness, and the cement slurry
then flows as a sheet through the fracture plane.
Although the cement squeeze produced horizontal
pancakes in their shallow-well tests, their general con-
clusions appear to be valid for deep-well vertical frac-
tures as well. In studies of squeeze procedures, water
or acid was a more effective breakdown agent than
drilling mud, and slow pumping of cement resulted in
higher final squeeze pressure with smaller volumes of
cement pumped.
Although the high-pressure squeeze method is
most commonly used, a low-pressure technique in-
troduced by Huber and Tausch2 in 1953 is used for
special applications in completion or workover op-
erations conducted through production tubing. The
method involves placing a small volume of cement
against open perforations at low pressure, Fractur-
ing is deliberately avoided, and excess cement is
circulated out of the well, leaving only small cement
filter-cake nodes inside the casing. A major advantage
is the ability to conduct the operation with small
pumps, which are often available at the well location.
Perforating
Before 1932 mechanical perforation devices were
the only means
of establishing communication
through cemented pipe from the wellbore into the
formation. However, in December of that year, the
first down-hole gun perforator was used in a Union
Oil Co. of California well in the Montebello field,
Los Angeles County, Calif. Since that time gun per-
foration has become the most widely used comple-
tion method because of the advantages of wireline
operation and the selective perforation and produc-
tion of a given zone. Plug-shaped bullets, ogival
bullets, burrless bullets, bear shots, and a wide
variety of shaped charge have been developed to
improve the process,
but wireline shaped-charge
devices are now used in more than 90 percent of all
perforating jobs done in the world today,
Despite the advantages of wireline perforating,
engineers questioned the down-hole efficiency of the
perforating process because well productivities were
often lower than predicted. In 1947 Oliphant and
Farris44 reported penetration depths of only O to
2 /2 in, into concrete targets perforated with con-
ventional bullet guns, At about the same time,
shaped-charge devices were being introduced to the
oil industry as a means of obtaining deeper pene-
tration in perforated completions. In the ensuing 25
years a steady flow of publications, primarily in JPT,
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advanced our understanding of the perforating proc-
ess and resulted in application of improved perforat-
ing technology in field operations.
Analog Studies of Productivities of
Perforated Weiis
In 1950 two almost identical analog studies of the
theoretical productivity of an ideal perforated well
were reported in JPT by McDowell and Muskatsg
and Howard and Watson, fi These studies provided
a new understanding of the relative importance oi
perforation depth and shot density, and stimulated
the design of improved perforators and down-hole
completions. The depth of penetration of the earlier
perforators was shown to be insufficient, even at
high shot densities,
to provide well productivity
equal to open-hole productivity. With nominal shot
densities of four per foot, a perforation depth of
about 6 in. or more is needed to provide productiv-
ities equal to or exceeding open-hole productivity.
The published curves also indicated that shot den-
sity is more important than perforation depth; four
holes per foot 2 in. deep are more effective than one
hole 12 in, deep,
Because analytical methods for predicting how
much fluid should flow through a perforation in a
mdial system are complex, these early investigators
used an analog model and assumed ideal, undam-
aged perforations and no formation damage from
drilling or completion fluids. Now, through compu-
ter technology, the effects of both perforation dam-
age and drilling damage can be taken into account.
The first exploratory step in this direction, by Bell
et al. showed that for a single perforation in a semi-
infinite medium, the flow efficiency of a typical dam-
aged perforation is only about 20 to 40 percent of
the flow efficiency of an undamaged perforation. A
further study by Klotz er
ai.,
as yet unpublished
but submitted to JPT, confirms the previous work
and, in addition, shows that in a system with both
drilling and perforation damage, a small number of
deeply penetrating perforations is more effective
than a large number of shallow perforations. To
overcome the effects of permeability damage from
drilling or workover,
the perforations must be of
high quality and must extend substantially beyond
the depth of the formation damage,
This continuing work provides additional insight
into the best ways of designing perforated comple-
tions, and also makes it possible to correlate core
flow efficiencies for commercial perforators as
determined by API test procedure RP 43 with
down-hole well productivities.
Productivity Method of Evaluating
Perforation Effectiveness
The experimental and analog results of the early
investigators stimulated the development of new,
improved gun designs that provided the penetrations
indicated to be necessary to achieve theoretical well
productivities. However, the expected results were
still not obtained. Exploratory tests with shots made
into large steel-encased cores under surface condi-
tions indicated that the flow capacity of the perfor-
DECEMBER, 1973
ated rock was strongly affected by factors associated
with the perforating process.
In 1953 Allen and Atterbury reported the results
of studies of the perforating process under simulated
wellbore conditions, Severe plugging and perforation
damage occurred when perforating was done in drill-
ing mud and with wellbore pressure higher than
formation pressure.
The dense, dehydrated mud
plugs that were created were almost impossible to
remove even at very high pressure drops.
This~work was extended by Allen and Worzel
and by Kruegers
to include other fluids besides
drilling mud and also other wellbore conditions.
Substantially higher core flow capacities were ob-
tained when perforating in a clean, solids-free fluid
and with the pressure in the wellbore lower than in
the core. However, even under the best conditions
the flow capacity of the perforation was restricted
by a damaged zone of pulverized rock surrounding
the hole. Little difference in core flow capacity was
found between jet- and bullet-perforated cores, but
in many cases severe perforation plugging resulted
from jet charge debris.
These important studies stimulated further ad-
vancements in perforating technology. Industry stan-
dards for evaluating gun perforators were adopted
under the auspices of the API, and it became pos-
sible for the engineer to select perforators on the
basis of penetrating power and a standardized flow
index. The standards provided a quantitative basis
for developing improved perforators, and an atten-
dant development was the elimination of debris
from the jet carrier and the slug in the perforation
through a redesign of the shaped charge. In addi-
tion, field results were improved by the adoption of
recommended perforating conditions. Development
of nonplugging emulsions, field filtering equipment
for oil and salt water, and permanent completions
have contributed to the effective optimization of
perforating conditions.
Factors Affecting Perforator Performance
Many factors influence perforator performance
down hole, and most of them have been discussed in
JPT publications. The effects of gun clearance and
positioning, compressive strength of tile formation,
and casing grade have been shown to critically affect
penetration. A good bond of cement to casing is
critical for selective control of producing and well-
treating operations. Experimental studies have shown
that the transient forces generated during perforating
can damage casing and disrupt the bond of the
cement to the casing; however, casing damage can
be prevented by providing good cement backup and
by using retrievable, hollow carrier guns. Godfrey
demonstrated that damage to the hydraulic cement
bond can be prevented if the casing is cemented in
place with a cement that has a compressive strength
greater than 2,500 psi.
The creation of a damaged zone around the per-
foration is well documented. Cleanup of this dam-
aged zone is critically affected by the type of for-
mation, the type and quality of the charge, the dif-
ferential pressure across the perforation, and the
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direction of flow. Bell et al. showed that high dif-
ferential pressures promote better cleanup of perfor-
ation debris and higher flow efficiencies, The rate
of injection of fluid into a perforation that has not
been previously cleaned up by backflow is only a
fraction of the backflow rate. White et al . showed
that still higher differential pressures are required
to clean up perforations in a gals-saturated core,
Drastically faster cleanup and higher well productiv-
ities are achieved in gas-saturated rocks when per-
forating is done under gas and at very high differen-
tial pressures into the wellbore.
Perforating in High Temperature Wells
The trend to deeper wells with very high bottom-
hole temperatures and pressures has extended per-
forating materials and equipment to their limits. Bell
and Auberlinder described the difficult problems
encountered in hot-well perforating and showed that
it is unrealistic to rely on temperature lags during
running in the hole as a means of extending the
depth range of conventional perforating charges. As
a workable alternative, they introduced a new explo-
sive charge and special cquipmerlt that were tested
successfully in wells above 340F.
Special Perforating Devices
Many special perforating devices have been intro-
duced to the industry through technical publications
in JPT. A few examples are high-temperature per-
forators, oriented perforators for multiple tubingless
completions, radial firing guns for limited-entv frac-
turing. and through-flowline perforators.
Hydraulic Jet Perforating
Hydraulic jet perforating was introduced to the in-
dustry in 1960 by Pittman er a/ . Penetration is
achieved by pumping abrasive-laden fluid through
tubing and then jetting it horizontally through a
nozzle. Although good penetration and hole size are
obtained with this method, time and cost have rele-
gated it to minor specialized usage. Recent field tests
by McCauley{ indicate that although well produc-
tivities obtained with this method are about the same
as for optimized gun perforating, the rate of decline
is more rapid.
Sand Control
In wells completed in shallow, recent sediments,
sand production is a major cause of wellbore pllg-
ging, reduced production, and erosion of mechanical
production equipment. Sand control methods to pre-
vent these problems have been known for a long
time, and the basic technology is well developed.
Nevertheless, up to now its application in oil and
gas wells has been only partially successful, and
therefore it deserves further study.
In early attempts at control, screen liners were
adapted from water-well use. Later, gravel packing
between screen and formation was used, and in 1947
consolidation with plastics was begun. These three
methods continue to be the principal means of con-
trol, although some useful combination methods,
such as the use of plastic-coated gravel slurries, have
1454
been developed.
All methods attempt to provide mechanical sup-
port for the formation, tmd all are potentially capable
of doing so. However, the proper design and execu-
tion of any of these methods are often not fully imple-
mented, and as a result, field treatments have been
unpredictable, Initial success ratios are reported to be
very high, but long-term results based both on control
of sand and maintenance of good well productivity,
are generally low.
Good sand control treatment cannot offset the
effects of formation damage caused by drilling,
cementing, or perforating. On the other hand, care
in preventing damage during drilling may be com-
pletely offset by careless handling of the sand-control
treatment, Unless clean and compatible treating fluids
are used in sand-control operations, formation dam-
age may be locked into place along with the loose
sand, thus resulting in loss of production and early
treatment failure. Many companies have demon-
strated the value of close quality control during
gravel packing and plastic consolidation treatments.
It is not the purpose of this paper to cover sand
control operations in detail, and the reader should
refer to the many excellent papers on this subject.
However, we shall review briefly some of the
background in sand-control technology and a few
of the important contributions made through JPT
publications.
Mechanical Screens
Slotted liners and wire-wrapped screens arc used suc-
cessfully when formation stability is not a severe
problem. In 1937, Coberly dctcrmincd that stable
bridges are formed on slots if the slot width is no
more than two times the diameter of the 10 per-
centile fraction of the formation sand taken from a
sieve analysis, and most engineers use this criterion
with variations for formations in particular areas. In
many areas, 0.050 in. is specified as the minimum
slot size needed to avoid slot plugging. However, in
recent years special wire-wrapped screens with open-
ings as small as 0.008 in. have been used successfully.
Prepacked liners filled with gravel have been used
extensively but have lost favor because of rapid plug-
ging with asphaltenes and silt. Recently, liners packed
with resin-bonded sand have been used in clean for-
mations containing medium- to high-gravity oil. Suc-
cessful usc depends critically on the nature of the
formation sand and fluids, and on the proper selec-
tion of sand size in the prepack.
Gravel
Packing
Open-hole gravel packing usually involves under-
reaming the productive interval, setting a slotted liner
or screen, and flow packing the annulus with gravel,
A similar effect can be achieved in a perforated com-
pletion by washing out the formation behind the pipe
and then pressure packing the void space to sand-out.
The gravel pack itself, if properly designed and
placed, will not impair well productivity because the
permeability of the graded sand is much higher than
that of formation sand. However, laboratory studies
and field experience indicate that the removal of
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solids from all fluids used in the gravel-packing
process is essential to maintaining a good pack with
high flow capacity. Invasion of the gravel by forma-
tion fines, drilling-mud solids, or solids from the
packing fluid can drastically reduce pack permea-
bility. Samples of pack sand recovered from wells
packed with dirty fluids have exhibited permeabil-
ities that are but small fractions of the formation
sand permeability, Plugged packs will restrict well
productivity, and the attendant high pressure drop
may lead to early pack and liner failures. To prevent
these problems, effective quality-control procedures
must be enforced throughout the entire drilling and
completion process.
The effectiveness of gravel packing for sand con-
trol depends critically upon the relationship of
formation-sand size to gravel size. The gravel used
to retain most formations is actually in the size range
of coarse sands. The classic work of Coberly and
Wagner I I repo~ed in 1937
established a Wantita-
tive basis for pack sizing, and gravel-pack perform-
ance substantially improved following this work.
Their gravel sizing rules specified a gravel diameter
of 10 times the 10 percentile fraction obtained from
formation-sand sieve analysis. Later experience indi-
cated long-term pack plugging and liner failure from
gradual invasion of the pack by formation sand, so
more conservative gravel/sand ratios of 4 to 6 are
now advocated by most investigators.
Until 1949, gravel-packing procedures changed
very little. Since that time, improved packing pro-
cedures have evolved, and applicatio]l of all the
known technology makes possible more effective
control of sand and a relatively ]ong-lived, productive
pack, Unfortunately, the optimum procedures are
not generally followed in their entirety, and conse-
quently the completions are usually not as effective
as they could be.
In 1968, Schwartz assembled the basic design
information on gravel packing and established a
comprehensive plan for designing gravel-packed
liner completions. His paper, along with the paper
by Rodgers related to pressure packing through
perforated casimz, provided the industry with a sound
basis for optimizing gravel-packed completions. The
essential steps involve (1) analyzing the producing
formation; (2) determining the proper gravel charac-
teristics: (3) exercising quality control on the fluids,
gravel, and procedures used during completion and
pack placement; and (4) stabilizing the pack.
Effect of Sampling Procedure on Gravel Selection
As pointed out earlier, the design of an effective
gravel screen will depend upon a knowledge of the
size distribution of the sand that will be encountered
in the producing interval, Maly and KruegerS7 have
demonstrated the critical effect of sample spacing
in the interval to be controlled. In heterogeneous
formations, the use of widely spaced samples for
determining gravel size is likely to lead to inade-
quate sand control, to gravel-pack plugging, and to
the attendant loss in well productivity. Composite
samples, flowline samples, and bailings can all lead
to serious errors in gravel-pack sizing.
DECEMBER, 1973
Modified Gravel Packiig Procedures
Several variations in the basic gravel packing proc-
ess have been introduced to the industry in JPT
publications, and have provided important ways of
taking care of special problems.
Layered Gravel Pack
One of the disadvantages of open-hole gravel pack-
ing is the lack of control over separate interbedded
intervals. In 1951, West described a method of
isolating individual zones and controlling he
producing depth in a gravel pack. His technique
involved depositing layers of permeable gravel alter-
nately with layers of low-permeability mixtures of
gravel and fine sand or mud. Fluid injection above
or below a packer assembly on the production tubing
permits control of water or gas coning between imp-
ermeable layers. Field trials demonstrated effeclivc
control of producing depth and elimination of coning
problems.
Pressure Packing
One variation of gravel-packing procedure that has
found rat?er wide application is the pressure-packing
method described by Rawlingsj in 1958. Sand is
pumped through perforations at pressures close to
or slightly above formation parting pressure, and
then is allowed to screen out. The size of the sand is
selected so that the sand will pass through the pipe
openings in low-concentration slurries, but bridge on
the formation side of the holes at screen-out. This
method has the advantage of providing well com-
pacted packs in loose formations or in formations
that have already produced considerable sand. An
additional advantage is the possibility of sand fin-
gering through zones of formation darnagc at the
wellbore face.
Williams cr ~11.ecently studied pressure packing
through perforations from a theoretical viewpoint,
and also analyzed field results. Their study showed
that this type of gravel pack reduces well productiv-
ity because of resistance to flow through the sand-
filled perforations. Productivity damage is often even
more severe because formation fines invade the
gravel pack outside the casing. To minimize produc-
tivity damage, gravel should be carefully selected to
retain the finest formation grain sizes, and it should
be of high quality that is, it should be strong
enough to minimize attrition, should be clean, and
should be free of fines, f lats, and conglomerates. The
preferred material is well rounded quartz. During
placement, the packing fluids must also be compat-
ible with formation fluids and free of particulate
matter.
Low=Rate Placement of Gravel Pressure Packs
In high-rate pressure packing, a l~w-permeability
pack may be formed by hydraulic erosion and mix-
ing of loose formation sand and injected gravel,
In 1969, Sparlin described a new gravel placement
technique that attacked the problem of gravel-pack
plugging during high-rate injection. By pumping a
viscous slurry containing a high concentration of
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sand at ~ery low rates, erosion of the formation sand
and mixing into the gravel slurry is minimized.
PJastic Consolidation
Plastic consolidation has become a widely used
method of sand control for thin producing intervals.
The difficult conditions under which the plastic must
be applied down hole placed some critical restric-
tions on resin properties, The resin must (1) have
sufficient strength to prevent grain-t~grain attrition,
spalling, or plastic flow under high overburden
stresses; (2) retain suficient permeability to provide
adequate well productivity; (3) have sufficiently low
viscosity to pump down hole in reasonable time
intervals and to achieve good and uniform penetra-
tion into the formation; (4) be compatible and bond
with a wide range of formation minerals; and (5) be
resistant to formation fluids and treating chemicals
at formation temperatures and pressures.
The first plastic material used commercially was a
phenol formaldehyde resin. No overflush fluid was
used in placement, and formation permeability was
gained by shrinkage of the resin during setting, Per-
meabilities of formations consolidated with this resin
were reduced by 50 to 80 percent, and therefore the
applications were restricted to high-permeability
sands. Several other consolidation resins have been
developed and commercialized since 1947, and the
principal consolidation processes today use phenol
formaldehyde, epoxy, and furan resins. Several of
these processes and field results have been described
in JPT, but space prevents elaboration on their prop-
erties, Permeability retention no longer depends only
upon resin shrinkage; it also results from the use of
overflush fluid or from phase separation of the resin,
As a result, in most cases the permeability of the
formation does not place a severe restriction on
applicability of the process. However, the presence
of bentonitic clays adversely affects resin properties,
and treatments in dirty sands have not been very
successful, Recently, special chemical prcflushes and
modified epoxy resins have been used in attempts to
alleviate the problem,
Factors Affecting Sand Consolidation
Field experience and laboratory testing have shown
that the success or failure of a consolidation treat-
ment depends critically on application procedures
and quality control, In 1961, Hewer and Brownzo
conducted a large-scale laboratory study of sand-
consolidation techniques that provided engineers
with a better understanding of critical factors in
consolidation treatments and outlined some of the
important requirements for good treatment results.
The basic consideration that runs through their
studies of job success is the need to avoid formation
damage and to treat through all perforations uni-
formly. If preventive care is not taken during all
phases of well operations drilling, completion, and
consolidation the sand control treatment is likely
to fail. For example, productivity may be perma-
nently damaged if permeability damage is sealed in
place with plastic; or sand control may break down
if a single plugged perforation prevents plastic from
1456
reaching the formation, However, Hewer and Brown
were the first to show that formation composition ?s
well as treating con~ itions critically affect the success
of plastic consolidation. Tne treated sand must be
relatively clean; the presence of more than about
4 percent of reactive clays adversely affects consolida-
tion with common plastic agents.
Recently, Brooks demonstrated improved per-
meability retention in dirty sands consolidated
with phenol formaldehyde resin when preflushes of
n-hexanol and monobutyl ether of ethylene glycol
were used. This work was carried out with sand
samples containing less than 4 percent clay minerals.
But no one has reported a co,mistently effective solu-
tion to the problem of conscllidating dirty sands hav-
ing clay contents greater than about 7 percent, either
with chemical preflushes or modified consolidation
resins, However, experim~nts along this line continue
with other materials, and there is some promise that
they may relieve this difficuh problem.
Improvement of Plastic Distribution
The need for uniform and effective treatment of the
entire producing interval cannot be overemphasized.
In recognition of this need, trohm et
al.
developed
a new, multiple injection too] that permits simul-
taneous packoff of several short intervals arid con-
trolled injection of plastic. The new tool increases
consolidation success through better fluid control,
reduces chemical costs a,ld pumping time, and per-
mits one-trip coverage of several different zones,
Stabil~tyof Sand Arches
One final publication should be mentioned. Most
papers on sand control have described materials or
processes directly associated with a particular engi-
neering problem, Hall and Harrisberger20 have pre-
sented a fundamental study of the mechanical
process of failure of the sand structure around the
wellbore and the factors that affect the stability of
the formation, They concluded that the two condi-
tions required for stability of an arch of sand are
dilatancy and cohesiveness. Their paper contributes
to our understanding of the sand control mechanism
and should lead t o the improvement of sand control
processes.
Acidizing
Although acid treatment of oil wells was tried as
early as 1895, the process was only infrequently
used during the ensuing 30 years. In 1932 the Pure
Oil Co. and Dow Chemical Co, wccessfully stimu-
lated several oil wells in Michigan in limestone for-
mations with hydrochloric acid treatments. As word
of these tests spread, interest in acidizing to improve
well productivhy mushroomed, and several com-
panies were organized to provide the service com-
mercially.
The success of acid stimulation of limestorles
raised interest as to the effectiveness of similar
treatments in sandstones, and early in 1933 the Hal-
liburton Co. pumped a mixture of hydrochloric and
hydrofluoric acids into a well in Texas. The results
discouraged for many years further work with hydro-
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fluoric acid for well stimulation. The sandstone
formation disintegrated, causing a sand problem in
the wellbore, and well productivity declined, leading
to the conclusion that the formation permeability
was plugged by acid reaction products. Although
mixtures of hydrochloric and hydrofluoric acids were
introduced commercially in 1939 by Dowell as
Mud Acid for removing mud filter cake from the
wellbore, their use for formation stimulation was
largely neglected for more than 20 years.
Since its first commercial use in 1932, hydro-
chloric acid has remained the primary acid treating
agent for oil wells because of its effectiveness and
relatively low cost. During the past 25 years, several
other acids
formic, acetic, and hydrofluoric
have been used to a limited extent for special appli-
cations involving deep, hot wells, for wellbore treat-
ments, for stimulation in the presence of certain
metals such as aluminum and chromium, and for
other unusual conditions. Although the basic chenl-
istry of acid treating has been established for many
years, the economics find effectiveness of the treat-
ments arc strongly dependent upon local conditions
in the wellbore and formation. A number of inlpor-
tant considerations have been brought to the indus-
trys attention througfl various publications in JPT.
The importance of these publications is discussed
below.
Applications of Organic Acid
In 1961 Harris brought to the industrys attcn[ion
a number of special problems in well treating that
could be more effectively handled with an organic
acid (acetic) then with hydrochloric acid. The inher-
ently slower reaction rate of acetic acid, its uniform
corrosive action, as opposed to pitting, and ihe abil-
ity to inhibit it against all types of steel at elevated
temperatures, makes this acid adaptable to many
special problems, Harris discussed the properties of
acetic acid and dcscribcd special applications in
completion, stimulation, and workover. Engineers
were thus made aware of a new chemical tool for
solving many of their problems.
Effect of Flow on Acid Reactivity
During the early years of acidizing it was assumed
that acid uniformly entered and enlarged formation
pores, and thereby increased the flow capacity. How-
ever, in more recent years it has been shown that
the acid spends very rapidly in such matrix acid-
izing and penetrates very little beyond the wellbore.
Thus the prima~ effect is to remove wellbore
damage.
In tight carbonate rock it is dificult to avoid pres-
sure parting and, therefore, acidizing usually occurs
in natural, or hydraulically created fractures. In fact,
in most cases deep penetration of acif i through frac-
tures is desirable to achieve large productivity in-
creases. Inasmuch as penetration of spent acid into
the formation provides little benefit, it is important
in designing an effective treatment to know the
spending time of the acid in a fracture.
Many studies have been made of acid reaction
characteristics under static conditions, but applica-
DECEMBER, 1973
~ion of tm:se results to the dynamic conditions exist-
ing in a fracture during field acidizing leads to
considerable error in designing practical well treat-
ments. A JPT paper in 1962 by 13arron et al.~ was
the first to take into account the effects of dynamic
conditions in a fracture. Their study of acid reaction
rates during flow between limestone plates showed
that an increase in injection rate provides deeper
penetration before the acid is spent, but the effect
diminishes with penetration depth. Although this
pioneering study involved simplifying assumptions
as to tcrnpcrature, fracture roughness, and fracture
orientation, the correlation of acid penetration in a
fracture with treatment variables resulted in inl-
provcd acidizing proccdurcs, In 1972, Williams and
Nierode; developed a more sophisticated dynamic
model without the above simplifications. The model
accurately predicts acid penetration distance and
can be used to maximize stimulation ratios.
Wrnula ion of Sandstone Reservoirs With
Hydrofluoric Acid
Although hydrotluoric acid has been used for well-
bore cleanup since 1939, the application of large-
volurne treatments for formation stimulation in
sandstones was minor, Some unsuccessful field tests
and insufficient understanding of the chemistry of
hydrofluoric acid reactions in sandstones appear to
have hindered wider application. However, in 1965,
Smith and Hendrickson; discussed the reactivity
and kinc[ics of HF acid, and the effects of common
variables cmcountcrcd in the field. HF reactions
with rock minerals and secondary depositions were
studied theoretically, and core plugging tests were
conducted with Bereri sandstone cores. This study
removed much of the mystery in HF acidizing for
petroleum engineers, and pointed the way to im-
proved practical applications. An important out-
growth of this work was the use of tapered acid
treatment designs, involving hydrochloric acid spear-
heads and tail-ins, to inhibit deposition of plugging
reaction products.
Improved Treatments With
High Concentration Acid
Wells commonly were stimulated with 15 percent
hydrochloric acid; use of high-strength acid was lim-
ited to occasional isolated cases, primarily because
there was a lack of technical information and knowl-
edge of how best to use it in the field. However,
during the past 10 years, since some successful jobs
were performed in Utah, applications have increased
rapidly, and 28 percent acid has been used to solve
stimulation problems in many reservoirs and to
improve results in others.
In 1966, Harris et
al :
presented the technology
of acid concentration effects and the practical aspects
of using high concentrations, Extensive laboratory
studies and field investigation brought out new facts
concerning concentration and sho ;~ed that some of
the previous assumptions were not valid. Laboratory
studies indicate that at HC1 concentrations greater
than 15 percent, acid properties change significantly
with increasing concentration. With a better knowl-
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edge of what these changes are and how they occur,
it has been possible 10 engineer high-strength acid
treatments to obtain greater fracture conductivity and
deeper fracture penetration.
Deposition of Iron After Acidizing
Formation plugging from secondary deposition of
iron after acidizing is a problem that was not recog-
nized for many years, During the trip down hole,
acid dissolves metallic iron and iron scale and, after
leaving the pipe, attacks iron compounds present in
the formation. The dissolved iron remains in solu-
tion until the acid is spent, but :hen precipitates as
the pH of the spent acid rises. Precipitation of iron
hydroxide or other iron-containing compounds can
seriously damage the flow channels opened by acid
reaction.
Smith et al, discussed this problem in detail in
a 1968 publication, providing petroleum engineers
with a basis for evaluating potential formation-plug-
ging problems in their operations and with methods
of avoiding or minimizing them. They showed, for
example, that iron-sequestering agents are required
for successful acid treatment of formations contain-
ing 42to 31/2percent iron, Of the sequestering agents
tested, only citric acid, EDTA, and NTA were
capable of holding 3,000 ppm Iron 111 in spent acid
solutions for more than 4 hours at temperatures
above 175F.
Diverting Agents for Improving Treatment Results
To this point, our discussion has related to applica-
tions of the chemistry of acid treating. However, the
final effectiveness of the treatment is often strongly
affected by physical conditions, such as injection
rates, the presence of organic coatings on the for-
mation to be treated, and the distribution of acid
over the productive interval.
The problems of treating long intervals, multip e
pay zones, or fractured zones have long plagued the
industry. A common experience is dissipation of
most of the treating fluid in a single, short, thief
interval. High fluid injection rates, straddle packers,
ball sealers, and liquid or granular diverting agents
are being used to cope with this difficult and costly
problem. The use of ball sealers and straddle packers
is limited to cemented and perforated casings or
liners, but channels behind the pipe often negate
their etiectiveness. Use of high injection rates is
costly because of the excessive horsepower require-
ments and large volumes of fluid needed.
Granular and liquid diverting agents have been
used for many years with varying degrees of success,
Most have deficiencies of one sort of another: some
are excessively soluble in the treating fluid, some
are insoluble in the produced fluid and therefore
damaging to the permeability of the producing zone,
and some have poor diverting characteristics. In
1969, Gallus and Pye]~ compared the effectiveness
of some common diverting agents on the basis of
diverting ability and volubility. Because of deficien-
cies of commonly used products, they developed to
rigid specifications a new material that yielded im-
proved results, both in the laboratory tests and in
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field operations. Field results with the new material
were significantly better than with the commercially
available products. Following the introduction of
this new material in JPT, it has been widely accepted
by the industry for acidizing treatments and is un-
doubtedly responsible for the recovery of much
additional oil.
Preiiushes and Afterfiushes
To insure effective acid treatments requires proper
conditioning of the rock before and after the treat-
ment. Many field treatments have been converted
from failures or questionable successes to excellent
economic successes by sandwiching the acid between
chemical rock-conditioning agents. Asphaltic and
resinous deposits often interfere with acid reactions
under formation conditions, but they can be elim-
inated by proper pretreatment with solvents: forma-
tion of acid sludges, which plug flow channels, can
be avoided or reduced with chemical preflushes. As
mentioned earlier, precipitation reactions with hy-
drofluoric acid treatment may be minimized by a
preflush with hydrochloric acid.
However, even with a well designed acid stimula-
tion system employing a preflush, the success ratio
may be unexpectedly low, And in many cases sub-
stantial stimulated production increases are followed
by rapid declines, Gidley concluded that adjusting
the nettability of the fines and rock surfaces after
the acid contact could help control the post-treat-
ment problems. His tests, reported in JPT in 1971,
revealed that certain surface-active materials dra-
matically improved stimulation results. One material,
mutual solvent ethylene glycol monobutyl ether, dem-
onstrated a broad range of effectiveness, and since
the process was released
t o the industry it has
become widely used in field treatments.
Hydraulic Fracturing
The hydraulic fracturing technique for stimulating
the production of oil and gas wells is one of the
major developments in petroleum engineering, Before
1950, acidizing was the primary method used to
stimulate well productivity. However, stimulation of
nonreactive formations such as sandstones was gen-
erally ineffective until the hydraulic fracturing
process was introduced to the industry by Clark in
the first issue of JPT. Since then, several hundred
thousand fracturing treatments have been carried
out successfully in both acid-reactive and acid-
insoIuble formations,
The occurrence of pressure parting of formations
in acidizing, waterflooding, squeeze cementing, and
drilling operations had been long recognized, A
common observation in all these operations was that
below a certain injection pressure the formation
would accept only nominal amounts of fluid; but
with only a small increase in pressure, increasing
amounts of fluid could be injected with little change
in pressure. Farris, in the Stanolind Research Lab-
oratory, imaginatively grasped the implications of
controlling the creation and location of fractures in
the producing formation, and in 1948 disclosed his
ideas in a patent applicatiorl (issued in 1950). In
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1949, Clarks landmark paper introduced to the
industry the concept of pumping a viscous liquid
down hole at a high rate to build up pressure to
rupture the rock. Sand was added to the fluid to
prop the created fracture, thus in effect widening the
wellbore, The viscous fracturing fluid was designed
to break back to a thin liquid to facilitate effective
cleanout of the fracture and wellbore. In the initial
tests, significant production increases were obtained
in 11 of 23 wells,
Clarks paper
and reports of some spectacular
production increases
fired the imagination of the
industry, and fracturing technology developed explo-
sively. From injection rates of 2 to 5 bbI/min first
used by Clark, improvements in pumping equipment
and the introduction of friction-reducing additives
led within a few years to treatments at rates as high
as 400 bbl/min, Treatments at 20 to 30 bbl/min
became commonplace.
The evolution of fracturing fluids contributed
importantly to the rapid development of hydraulic
fracturing and to improvement of stimulation results
in a variety of formations. Because of space limi-
tations, we shall not be able to give recognition to
the many contributors to these advancements; how-
ever we should briefly mention the changing trends
irr fracturing fluid technology.
The first treating fluids were Napalm gels, but
recognition of their limitations soon led to the use
of lease oil or water pumped at high rates. An
important influence on the trend toward high rates
was the introduction of friction-loss reducers and
,~iti-ioss control agents. Fundamental studies on
the importance of fluid properties on fracture width
and extent, and on proppant placement resulted in
a reversal of this trend. In recent years, new devel-
opments have emphasized very viscous fluids, either
oil base or water base, pumped at low rates. The
viscous fluids create wide fractures, effectively carry
high sand concentrations, improve fluid loss control,
and increase proppant transport. Some of the com-
mon fluids now used are guar gels, cross-linked guar
gums,
~scous oil-external emulsions, cellulose poly-
mers, and gelled oils. One approach to pumping
oil-base systems of very high viscosity has been to
surround the viscous plug with a slickened water
ring. Fluid blocking of fractured gas wells led to
the development of unique gelled fluids that vaporize
at formation temperature.
Over ail, the development of fracturing technol-
ogy has been rapid and prolific, and hundreds of
interesting papers have been written to describe the
results. The following sections discuss only a few
of the many studies that have led to important
advances in practical field applications.
Mechanics of Hydraulic Fracturing
One of the basic publications that has strongly
affected the design and interpretation of hydraulic
fracturing treatments was a study of the mechanics
of hydraulic fracturing by Hubbert and Willis.z For
several years after the commercialization of hydraulic
fracturing, the most prevalent opinion of fracture
orientation was that pressure parted a formation
DECEMBER, 1973
aIong a bedding pIane and lifted the overburden,
thus resulting in a horizontal pancake fracture.
This interpretation of field observations was ques-
tioned, however, by a number of engineers and
scientists who pointed to a large body of data
showing breakdown pressures that were significantly
less than would be predicted on the basis of over-
burden weight. It was inferred that when breakdown
pressure is less than that due to the overburden the
fracture should be vertical. On the other hand, some
laboratory experimentation indicated that horizontal
fractures were formed preferentially when the frac-
turing fluid penetrated the rock porosity, and vertical
fractures were created when the fluid did not
penetrate.
Hubbert and Willis studied the fracturing of rocks
theoretically and concluded that when pressure is
applied in a borehole the fractures created should
be approximately perpendicular to the axis of least
stress, regardless of the type of fluid used. It follows
from their analysis that in tectonically relaxed areas
characterized by normal faulting the fracture should
be vertical and should be formed with injection pres-
sures less than the total overburden pressure; in
tectonically compressed areas, the fractures should
be horizontal and formed at pressures equal to or
greater than total overburden pressure. These con-
clusions were supported by experimental results with
a laboratory model and by field observations.
In the following years, a growing body of evidence
supported the analysis by Hubbert and Willis, and
most engineers now concede that the majority of frac-
tures in deep wells are vertical, and that horizontal
fractures most commonly occur in shallow wells.
Exceptions to this generalization may be expected in
areas like California, where tectonic compression is
taking place. As predicted, in deep wells in Califor-
nia, injection pressures greater than total overburden
pressures are common.
Fracturing Treatment Design
Treatment cost and effectiveness are affected by
many treating parameters
type of fluid, fluid-loss
rate, injection rate, type of proppant, formation
characteristics, and others. Many authors have in-
vestigated the effect of these variables, and today
most service companies and many operating com-
panies have computer programs that use the results
of these studies to optimize hydraulic fracturing
treatments. Treating parameters can be selected to
achieve a desired fracture penetration in a given
formation; then, from the expected fracture penetra-
tion and a predetermined fracture conductivity, the
productivity increase is predicted.
The first attempt to analyze the factors affecting
fracture extension was published by Howard and
Fast* in 1957. They investigated the effect of reser-
voir and fracturing-fluid properties on fluid loss to
the formation, and related the results to fracture
penetration. They showed that the effective design of
a fracturing treatment depends on an accurate knowl-
edge of the fluid-loss properties of the fracturing fluid;
reducing the fluid lost out of the fracture has the same
effect on fracture area as increasing the pump rate.
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To provide a numerical measure of the effectiveness
of different fluids, they defined fracturing fluid coeffi-
cients, which are now used in many predictive models.
The concepts developed in this work provided impe-
tus for the development of more effective fracturing
fluids.
The fracturing fluid coefficients defined by Howard
and Fast are determined from static tests. Hall and
Dollarhide and Williams showed that static test
conditions did not adequately represent actual fiuid-
10SSconditions in a fracture, and that dynamic fluid-
10SS tests provided a better simulation of the fluid
lost to the walls of the fracture during hydraulic
fracturing operations. Dynamic fluid-loss rates were
determined for commonly used additives, and it was
concluded that the values provided a basis for more
accurate prediction of fracture extension,
As mentioned earlier, most service companies
offer predictive calculations of the effectiveness of
fracture treatments, The information, usually in the
form of Frac Guides,
is based on a study pub-
lished by McGuire and Sikora( in 1960. Their
publication describes an experimental analog com-
puter study that relates well productivity increases
to fracture length and conductivity. When other pub-
lished information on the effects of various param-
eters on fracture conductivity is related to these
curves, it becomes possible to explain the results of
actual field treatments and to build on this informa-
tion to improve future jobs. For example, the data
show that if sufficient attention is not paid to pro-
viding adequate conductivity in the fracture, the cost
of creating a deeply penetrating fracture is not justi-
fied, because the well productivity will be little
better than that obtained with a shallow fracture of
the same conductivity. Thus, we see again that pub-
lished information of this nature can be of con-
siderable value to the engineer who takes time to
study JPT.
This basic study was refined and extended by
Tinsley et
al.
in 1969 to take into account the situ-
ation when the fracture height and the formation
may not be equal,
Mechanics of Sand Movement
For many years,
engineers designing fracturing
treatments assumed that the proppant travels at
nearly the same velocity as tne fracturing fluid, and
therefore that the last sand into the hole ended up
closest to the wellbore. As a consequence, in many
cases it became rather common practice to use larger
diameter sand as a tail-in to provide high fracture
conductivity near the wellbore and also to improve
bridging on the perforations. An important labora-
tory study by Kern et al.: i n 1959 showed that the
assumed sand transport mechanism was incorrect,
and their work laid the basis for improvements
in proppant placement. Using a visual model, the
authors showed that sand settles rapidly to the
bottom of a vertical fracture unless the injection rate
per foot of