Articulo1 SPE

7/24/2019 Articulo1 SPE

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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-

JOURNAL OF PETROLEUM TECHNOLOGY


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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,

1450

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

1451


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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,



7/16

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

1453


8/16

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



9/16

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

1455


10/16

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-


.


11/16

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-

1457


12/16

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

1458

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



13/16

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.

1459


14/16

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

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