DEVELOPMENT and APPLICATION of "FRAC" TREATMENTS
`in the PERMIAN BASIN
`
`R. E. HURST
`
`J. M. MOORE
`MEMBERS AIME
`
`D. E. RAMSEY
`JUNIOR MEMBER AIME
`
`DOWELL INCORPORATED
`MIDLAND, TEX.
`
`T. P.4032
`
`ABSTRACT
`The "frac" method of well stimulation has been
`applied successfully to all producing formations in the
`Permian Basin area. During the five years since its
`development, many changes and improvements have
`been made in treating materials, procedures, and equip(cid:173)
`ment.
`A number of fluid carrying agents, having different
`physical and chemical properties, have been developed
`to meet various well requirements. The current trend is
`toward larger gallonage treatments, employing higher
`injection rates. The use of "down-the-casing" techniques
`ha~ greatly reduced high surface working pressures,
`attributable to friction losses resulting from injection
`through tubing.
`Petrographic studies of various Permian Basin forma(cid:173)
`tions, coordinated with laboratory and well log data,
`have been found a valuable guide in planning frac treat(cid:173)
`ments. A knowledge of the extent and orientation of
`naturally occurring fractures and planes of weakness in
`the formation, aid in predicting the ultimate drainage
`pattern resulting from the frac treatment.
`
`INTROI:)UCTION
`The South Permian Basin covers an area in West
`Texas and New Mexico about one-half the size of the
`state of Texas. This vast region has been called the
`
`Manuscript received in Petroleum Bra1].ch office on Oct. 1, 1954.
`Paper presented at Petroleum Branch Fall Meeting in San Antonio,
`Oct. 17-20, 1954.
`Discussion of this and all following technical papers is invited.
`Discussion in writing (3 copies) may be sent to the offices of the
`Journal of Petroleum Technology. Any discussion offered after Dec.
`31, 1955, should be in the form of a new paper.
`SPE 405-G
`
`58
`
`"Permian Basin" for so long that the term will be used
`here. It includes an area south of the Matador Arch,
`approximately 250 miles wide and 300 miles long. Struc(cid:173)
`tural features of importance within the basin are the
`Northwest Shelf, Eastern Platform, Midland Basin, Cen(cid:173)
`tral Basin Platform, and Delaware Basin. The principal
`producing formations include sand, limestone and dolo(cid:173)
`mite, with lesser amounts of shale, anhydrite, chert, and
`various silicates.
`All of the producing formations in the Permian Basin
`have responded to some type of frac treatment. Essen(cid:173)
`tially, a frac treatment may be defined as the injection,
`into a formation, of a fluid carrying agent containing
`a particulated solid (usually sand), for the purpose of
`increasing production. The application of this method of
`well stimulation to many differing Permian Basin reser(cid:173)
`voirs has necessitated numerous changes and improve(cid:173)
`ments in carrying agents, solids, service equipment, well
`equipment, and treating techniques.
`
`CARRYING AGENTS
`A number of different types of fluid carrying agents
`have been developed since the introduction of the frac
`method of well stimulation. These agents have different
`physical and chemical properties, and in many cases the
`extent of production increase derived from the frac
`treatment depends on the choice of fluid carrier. Un(cid:173)
`fortunately, due to many different systems of nomencla(cid:173)
`ture used in the oil field, these differences are not always
`recognized by the oil operator. In general, carrying
`agents may be divided into the following broad classi-
`
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`ncations: (1) hydrocarbon gels, (2) aqueous gels (acid
`or water), (3) emulsions, (4) refined oil, (5) lease oil,
`and (6) miscellaneous fluids.
`
`HYDROCARBON GELS
`Most hydrocarbon gels used as carrying agents are
`quite similar, whether made from gasoline, kerosene,
`diesel oil, or crude oil. They are produced by adding
`a gelling or thickening agent (usually a metallic soap or
`the salt of a fatty acid) to the hydrocarbon. This re(cid:173)
`sults in materially increasing the viscosity of the fluid,
`the extent depending upon the concentration of gelling
`agent added. The ability of hydrocarbon gel to suspend
`sand is a function of the viscosity and density of the gel,
`and the size and shape of the sand grains.
`These hydrocarbon gels may be caused to "break" or
`lose their viscosity in several different ways, depending
`upon the type of gelling agent used. The presence of an
`electrolyte, such as salt water or a mineral acid, will
`cause most of these gels to break. Thinning of the gel
`may also be accomplished by dilution with additional
`quantities of hydrocarbon fluid.
`
`AQUEOUS GELS
`Water-base gels, such as thickened hydrochloric acid,
`are similar in many respects to hydrocarbon gels. The
`type of gelling agent used (usually a carbohydrate or
`cellulose derivative) determines how the gel breaks and
`what will break it. As a rule, a gelling agent is chosen
`which will permit the gel to break on contact with the
`reaction products of the acid and the formation, or as
`a result of bacterial growth within the gel itself. Care
`should be taken not to use a gelling agent that will
`precipitate out in insoluble form after the acid has be(cid:173)
`come spent. The sand suspending ability and fluid loss
`characteristics of these aqueous gels are related to their
`viscosity and density, as in the case of the hydrocarbon
`gels.
`Gelled acids are adaptable to a wider variety of well
`conditions than are hydrocarbon gels, since the type
`of acid and concentration may be varied, dependent
`on the solubility of the formation. Additional agents,
`which minimize emulsifying and silicate-swelling ten(cid:173)
`dencies of the acid, have been used to advantage in
`many areas. The viscosity of the gel may be varied
`over a wide range as desired.
`The use of gelling agents for the thickening of
`fresh water or brine is desirable for frac treatments
`on fresh water wells or water injection wells, where
`the injection of oily fluids might be undesirable. Such
`gels are thinned by bacterial action or by dilution
`with formation fluid.
`
`EMULSIONS
`The term "emulsion" until recently has been synon(cid:173)
`ymous with trouble in
`the oil fields. When prop(cid:173)
`erly used, however, emulsions have been found ex(cid:173)
`tremely helpful. Emulsions have a number of advan(cid:173)
`tages and disadvantages when compared with the gels
`as possible carrying agents. Although they have high
`fluid loss in comparison with the true gels, they possess
`excellent sand carrying characteristics.
`Essentially, an emulsion consists of a homogeneous
`mixture of two immiscible fluids, one of which exists
`in the form of tiny droplets as the inner phase, sur(cid:173)
`rounded by the other fluid known as the outer phase.
`Normally such mixtures rapidly separate into
`two
`distinct layers; however, certain types of chemical
`compounds, known as emulsifying agents, have the
`
`ability to keep such liquids in emulsion form tor In(cid:173)
`definite periods of time. Such emulsifying agents fre(cid:173)
`quently occur naturally in crude oils,
`resulting
`in
`troublesome emulsions of crude oil and brine. Such
`emulsions are thick and gooey, and interfere with the
`production of oil from a well.
`in frac
`The emulsions used as carrying agents
`treatments are physically similar to these naturally
`occurring emulsions; however, the emulsifying agents
`used produce relatively unstable emulsions which tend
`to break down, once they have entered the formation.
`The two principal emulsion type carrying agents used
`in frac treatments are acid/kerosene emulsions, and
`crude oil/water emulsions.
`The physical and chemical properties of an emul(cid:173)
`sion are determined by the emulsifying agent,
`the
`volumetric ratio of the two liquids in the emulsion,
`and the amount of agitation given the mixture.
`Acid/kerosene emulsion type carrying fluids will
`break down on contact with acid reaction products,
`or because the emulsifying agent is adsorbed onto
`type emulsions may be
`formation. Oil/ water
`the
`broken by the presence of any material tending to
`reverse the emulsion, so that water becomes the outer
`phase. Most emulsions are sensitive to heat. Regular
`crude oil treating compounds will usually break emul(cid:173)
`sion type carrying agents. Dilution of the outer phase
`will thin the emulsion to a lower viscosity.
`One of the chief advantages of this type carrying
`fluid is that an external gel-breaker is not required to
`cause the viscous fluid to revert to a thin, free-flowing
`liquid. This is particularly advantageous in low bot(cid:173)
`tom-hole pressure wells, where lengthy cleanup pe(cid:173)
`riods are required after other type frac treatments.
`In most crude oil/water type emulsions, the water
`and emulsifying agent make up less than 4 per cent
`of the total volume. Such emulsions break down in
`the presence of an electrolyte such as brine or acid.
`They are readily thinned by dilution with crude oil.
`If a low fluid
`loss carrying agent is desired,
`the
`aqueous phase of the emulsion may be made from
`thickened fluids. Inert solid particles also may he
`added to reduce the fluid loss.
`
`REFINED OILS
`The term "refined oils" as used here refers to any
`crude oil from which the very light and very heavy
`hydrocarbons have been removed. This would include
`kerosene, heavy fuel oils, and all intermediate prod(cid:173)
`ucts. Since the heavier oil fractions are more com(cid:173)
`monly used in frac treatments, they will be discussed
`first.
`Certain green, paraffin-base crude oils when re(cid:173)
`fined properly, will yield a dark green viscous prod(cid:173)
`uct which boils between 350 0 P and 750 0 P at atmos(cid:173)
`pheric pressure. This oil fraction, commonly called
`"fuel oil" by refinery personnel, can be made into an
`ideal frac fluid by blending with a high analine point
`hydrocarbon, such as kerosene or diesel oil, to thin to
`desired viscosity.
`Kerosene and diesel oil have been used as carrying
`agents in wells already having open fractures. Such
`treatments are valuable in removing paraffin deposits
`from the formation and wellbore or to clean up emul(cid:173)
`sions caused by a previous treatment, drilling fluid,
`or formation water. When used in wells where emul(cid:173)
`sion difficulties have been encountered, a demulsify-
`
`VOL. 204, 1955
`
`59
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`ing agent usually is added to the kerosene or fuel
`oil. It is important that preliminary tests be run to
`determine the proper agent to be used. Most refined
`oils have less tendency to form emulsions than does
`lease oil, due to the removal of fine solid particles by
`the refining process.
`Care should be taken when using refined oil as a
`carrying agent to choose one having a pour point at
`least 20 degrees below the formation temperature of the
`well in order to avoid precipitation of wax crystals from
`the oil, a phenomenon taking place at 12 to 15 degrees
`above the pour point of the oil.
`
`LEASE OILS
`At the start of most frac treatments, a volume of
`crude oil is pumped into the formation in order to deter(cid:173)
`mine the "breakdown" and feeding pressures, and the
`injection rate. In some cases it is possible to follow this
`with sand-laden crude oil, utilizing the crude oil as
`a carrying agent.
`Such a procedure has certain advantages. For one
`thing, if the crude oil is from the well in which it is
`used, no emulsion trouble should be experienced. If
`a high gravity crude is used, the well should clean up
`readily.
`Such advantages are, however, more than offset by
`the disadvantages attendant the use of crude oil as a car(cid:173)
`rying agent:
`1. Most crude oils have very poor sand-suspending
`properties. Low concentrations of sand must be used or
`the crude will be difficult to pump and "screen-outs" are
`likely to occur. As a result, larger gallonage treatments
`and higher pumping rates are required to displace a
`given amount of sand into the formation.
`2. The fluid loss of most crude oils is very high.
`Higher injection rates are required in order to accom(cid:173)
`plish the same fracture penetration obtained through the
`use of more viscous fluids.
`3. Sand screen-outs or bridging frequently occurs
`when attempts are made to pump sand and crude oil
`through casing perforations.
`4. Crude oils not native to the formation in which
`they are used may cause emulsion problems and difficult
`"clean-up."
`5. A definite fire hazard exists when crude oils are
`handled in open tanks around pumping equipment.
`Sand settling rates are much higher than those of the
`refined oil carrying agents. At formation temperatures
`the fluid loss of most crude oils is too high to be meas(cid:173)
`ured with standard equipment.
`
`SAND
`The exact function of the solids used during a frac
`treatment is somewhat controversial. Several theories
`have been proposed, namely, that:
`1. The solid particles penetrate planes of weakness,
`propping them open after the carrying agent has been
`removed.
`2. The particles act to scour or erode the walls of the
`passages through which they are displaced.
`The solids used in a frac treatment are chosen on the
`basis of the following properties: particle size, shape,
`hardness, compression strength, permeability of a packed
`column, reaction with well fluid, availability, and econ(cid:173)
`omy. Silica sand that has been washed and screened
`appears to be the most practical material for this use.
`The most popular size is 20-40 mesh, which consists of
`sand grains having diameters from 0.015 to 0.030 in
`(0.4 to 0.8 mm).
`
`60
`
`The Humble Oil and Refining Co. has suggested the
`adoption of a visual roundness evaluation chart origi(cid:173)
`nally proposed by Krumbein." This is shown in Fig. 1.
`Roundness is thus defined as the ratio of the average
`curvature of the several corners to the radius of curva(cid:173)
`ture of the largest inscribed circle on the projected
`image of the sand grain.
`The commonly used 20-40 mesh, round grain sand
`(see picture .6 on roundness chart, Fig. 1) has a packed
`permeability of 105 Darcys. In general, the larger the
`grain size, the greater the permeability, with angular
`shaped grains having a somewhat lower permeability
`than round grains of equal size. Field data indicate that
`a high degree of roundness is desirable in order to place
`more sand into a formation without bridging.
`The concentration of sand carried in the frac fluid is
`governed by the equipment through which it must be
`pumped, the type of carrying agoot, and the nature of
`the formation being treated. The quantities of sand and
`carrying agent should be carefully chosen when plan(cid:173)
`ning a frac treatment.
`In general, the more sand displaced into the forma(cid:173)
`tion, the better the results will be. This holds true
`whether either the propping or scouring theory is ap(cid:173)
`plied. The maximum concentration of sand that can be
`handled by any particular carrying agent is dependent
`upon: (1) the agent's ability to support sand; (2) its
`fluid loss in relation to the permeability of the matrix;
`and (3) the anticipated injection rate.
`Field experience has shown that the percentage of
`screen-outs has been reduced by the use of high injec(cid:173)
`tion rates. Another method of minimizing screen-outs
`has been to lower the fluid loss of the carrying agent,
`with respect to the formation. This is dependent upon
`the ability of the formation to accept the fluid being
`used as a carrying agent. Unfortunately, this latter fac(cid:173)
`tor is usually determinable only by trial and error.
`The most practical approach to the problem of
`screen-outs is now indicated from field experience. The
`first step is the classification of formations into two
`groups: (1) those that will accept high rates of injec(cid:173)
`tion, and (2) those that will accept only low rates of
`injection, under the pressure limitations of well equip(cid:173)
`ment. For the first group, high injection rates are in
`most cases sufficient to avoid screen-out difficulties.
`When treating formations which require low rates of
`injection, however, care must be taken to choose a car(cid:173)
`rying agent with excellent sand-supporting propertIes, III
`order to avoid the accumulation of high sand concentra(cid:173)
`tions opposite the formation. Such an accumulation
`usually results in a complete shut-down, due to a fill-up
`of sand in the well bore.
`
`lReferenees given at end of paper.
`
`ROUNDNESS- .1
`
`2
`
`3
`
`.4
`
`,~~ .t~ ~ •• e't let
`I,a ,&~ .., 'tt ,--
`·~f ~t' ,. . ,. ~t •
`t9. 1,-• •• lie II.
`eat _ t, -" " _ ,t-.a
`et. 1._ 'I' .,e .
`
`.6
`
`.7
`
`.8
`
`.9
`
`.
`
`BROKEN
`SANO
`
`FIG. 1 -
`
`ROUNDNESS CHART FOR SAND.
`
`j'ETROLEUM TRAi'"SACTIONS, .HME
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`In evaluating the sand-supporting properties of a car(cid:173)
`iymg agent, the factor of temperature should not be
`overlooked. The majority of carrying agents, which de(cid:173)
`pend upon viscosity for their sand-supporting ability,
`tend to thin down at elevated temperatures. Thus, the
`sand-suspending ability of the proposed carrying agent
`under conditions of bottom-hole temperature must be
`taken into consideration. In general, where temperatures
`exceeding 175 0 F are anticipated, and where injection
`rates are low due to pressure limitations of the well, it
`is necessary to use emulsion type carrying agents, de(cid:173)
`signed for high temperature use.
`
`EQUIPMENT
`The development of frac methods of well stimulation
`has resulted in many changes in wellhead equipment,
`bottom-hole tools, pumping equipment, mixing equip(cid:173)
`ment, and transporting equipment. Although at times
`the transition may have seemed slow, actually the
`change has taken place in record breaking time.
`Pumping equipment has been advanced from units
`capable of pumping 40 gal/min at 5,000 psi, to units
`capable of pumping as high as 300 gal/min at 5,000 psi.
`These units are designed to operate for long periods of
`time at high pressures ~ up to 15,000 psi, whereas
`previously such pressures could be tolerated only for
`short intervals.
`The changes in types of carrying agents employed
`have required the handling of highly inflammable fluids.
`Adequate safety precautions must definitely be made a
`part in the planning of any treatment. Thus far, the
`industry's record has been excellent, but there is still
`room for improvement. Specially designed fire fighting
`equipment is now made available on location in the
`form of improved extinguishers, coverings, and truck(cid:173)
`mounted fire fighting equipment. The demand for more
`and better personnel protective equipment is constantly
`increasing. The increase in monetary loss and extent of
`personal injury has arisen sharply for each accident,
`making it essential that a cooperative and respectful
`attitude toward safety be prevalent among servicing per(cid:173)
`sonnel and personnel in charge of well equipment.
`
`APPLICATION TECHNIQUES
`A study of Permian Basin wells indicates that the two
`basic problems in applying various types of frac treat(cid:173)
`ments are: (1) to inject the sand-laden fluid into the
`producing formation; and (2) to recover the carrying
`agent, while leaving the sand in place and the openings
`free from undesirable materials.
`During early treatments, the accepted method of
`application employed the use of tubing, with several
`types of pack-off tools. These tools varied from single
`casing pack-off elements used primarily for protection
`of casing from high pressures, to complicated multi(cid:173)
`pack-offs used to isolate various zones as well as protect(cid:173)
`ing the casing. The use of these small treating strings
`(normally, 2-in tubing) limited the injection rates and
`consumed valuable horsepower in overcoming friction
`losses of the sand-laden fluid being pumped. Screen-outs
`of sand in the well bore were always a hazard that had
`to be taken into consideration. It was believed that if
`higher injection rates could be obtained, larger volumes
`of sand could be injected before screen-outs would
`occur. However, the high pressures due to friction loss,
`prohibited the use of such high injection rates through
`tubing.
`
`The first producer in the Permian Basin to use high
`injection rate techniques for injecting larger amounts of
`sand into the formation, was the Southern Production
`Co. Instead of applying the frac treatment through tub(cid:173)
`ing, the materials were injected down the casing. Under
`these conditions, even though the injection rate was four
`times that normally used on frac treatments, the surface
`working pressure necessary to inject the sand-laden fluid
`was decreased by 50 per cent. These treatments showed
`that, not only was the mechanical efficiency of applica(cid:173)
`tion improved, but the resulting production indicated
`that the effective increase in bottom-hole working pres(cid:173)
`sures, the increased volume of materials injected, and
`the increased rate of injection were all beneficial to the
`well. As a result, these "down-casing" treatments have
`been extensively employed in the Permian Basin area
`with favorable results. On wells which contained bad
`casing, or had zones requiring isolation which made it
`necessary to inject the frac materials down the tubing,
`the use of larger diameter tubing (normally 3-in) was
`initiated by oil operators.
`Field results have substantiated the fact that large
`volume treatments (10,000 gal or more) result in better
`"conditioning" of many reservoirs because:
`1. Commercial producers have been obtained by
`large volume treatments in wells where smaller treat(cid:173)
`ments failed.
`2. Greater production increases have been secured
`with increases in the size of treatment.
`3. Production declines have been slower as greater
`drainage area was obtained in the well.
`Such higher gallonage treatments have been made
`possible by the use of higher injection rates during frac
`treatments. Such high injection rates also yield the fol(cid:173)
`lowing advantages: (l) deeper penetration of sand(cid:173)
`laden fluids; (2) prevention of screen-outs or lock-ups
`at the wellbore; and (3) reduction of the effect of tem(cid:173)
`perature changes on the physical properties of the car(cid:173)
`rying agent during the treatment.
`It should not be inferred that frac treatments are a
`cure-all that eventually will replace other methods of
`well stimulation, such as acidizing. Some formations,
`especially those in a plugged condition, require an acid
`treatment preceding the frac treatment. Almost any zone
`will be benefitted by a spearhead of regular or mud
`acid. Such a pretreatment results in lowering injection
`pressures and dissolving materials that may cause re(cid:173)
`striction to flow.
`Another controversial question is whether or not an
`overflush following a frac treatment is beneficial, and,
`if so, the amount of overflush which should be em(cid:173)
`ployed. It is believed that some overflush is beneficial
`because it:
`1. Moves the sand back from the well bore, to keep it
`from being produced.
`2. Breaks emulsions that may have formed in the
`formation.
`3. Thins refinery oil, when such has been used as
`a carrying agent.
`4. Benefits the critical area when acid overflush is
`used in carbonate reservoirs. Carbon dioxide gas pro(cid:173)
`duced by the chemical reaction will tend to give the
`well initial life, reducing swab time. It is also believed
`that acid used for overflush will enter small "feeder"
`planes, further conditioning the reservoir for increased
`production.
`Although
`treatments has
`the application of frac
`solved many well problems, it has also created some
`
`VOl .. 204, 1955
`
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`TABLE 1 - RESULTS OF FRACTURING TREATMENTS IN THE PERMIAN BASIN
`
`Well
`
`Pay Zone
`
`Pool
`
`County Well Data
`
`Treatment Data
`
`Before
`
`Results
`After
`
`A
`
`Keystone
`Rustler
`(sandy lime) Colby
`
`Winkler
`
`Open hole
`882'-1050'
`
`20,000 gal acid
`5,000 gal gelled acid
`2,500 Ib sand
`
`Pumped of!
`in 8 min
`
`10,000 SWPO
`
`B
`
`Delaware
`(sand)
`
`Tunstill
`
`loving
`
`c
`
`Yates
`(sand)
`
`South
`Wickett
`
`Ward
`
`5-year-old well
`Nitro-shot
`3299' -3328'
`
`6,000 gal lease oil/
`water emulsion
`9,000 Ib sand
`Inj. rate-7 b~l/min
`
`20-month-old well
`"frac" completion
`2568'-2758'
`
`9,000 gal refined oil
`18,000 Ib sand
`Inj. rate-12 bbl/min
`down casing
`
`D
`
`Queen
`(sand)
`
`la.lglie-
`Mattix
`
`Lea
`
`a-year-old well
`Nitro (300 qts)
`3410'-3587'
`
`5,000 gal lease oil/
`wafer emulsion
`10,000 Ib sand
`Inj. rate-10 bbl/min
`down casing
`
`12 SO PO
`pumping
`
`70 SOPO
`flowing
`
`7 SOPO
`
`3 SOPO
`
`518 BOPO
`potential
`40 SO PO
`(after 8 mo.)
`
`147 BOPO
`flowing
`through
`27/64" choke
`
`Remarks
`
`fresh water well used for injec(cid:173)
`tion program.
`Six alternate slugs of acid and
`. 'frac" materials used during
`treatment.
`
`Test 17 days after treatment.
`
`Originally completed with 2000
`gal "frac"
`treatment
`for 35
`BOPO.
`
`No cJeanout necessary after treat·
`ment in shot hole.
`
`E
`
`San Andres Wasson
`(dolomite)
`
`Gaines
`
`New well
`10,000 gal acid
`completion
`5002'-5140'
`
`10,000 gal refined oil
`10,000 Ib sand
`Inj. rate-18 bbl/min
`down casing
`
`500 BOPO
`3000/1 GOR
`
`1400 BOPO
`potential
`400/1 GOR
`
`Inside location in old pool. Ex(cid:173)
`perimental
`job, following acid
`with "frac" treatment.
`
`F
`
`Glorieta
`San Angelo
`(dolomite)
`
`Howard-
`Glasscock
`
`Howard
`
`New well
`Open hole
`2775'-2995'
`
`Show
`
`88 BOPO
`after 14 days
`
`Field extension-old pool. Sur(cid:173)
`face working pressure-350 psi,
`
`G
`
`Clearfork
`(dolomitic
`lime)
`
`H
`
`Spraberry
`(sand and
`shale)
`
`TXl
`
`Ector
`
`Pembrook
`
`Upton
`
`2-year-old well
`10,000 gal acid
`completion
`5460'-5910'
`
`New well
`Perforated
`6,000 gal
`hydrocarbon gel
`completion
`7000'-7050'
`
`1,000 gal acid
`3,000 gal acid/oil
`emulsion
`6,000 Ib sand
`Inj, rate-5 bbl/min
`down cosing
`
`8,000 gal acid/oil
`emulsion
`24,000 Ib sand
`Inj. rate-24 bbl/min
`down casing
`
`20,000 gal refined oil
`30,000 Ib sand
`down casing
`
`19 SOPO
`
`187 BOPO
`flowing
`
`Test on 7th day following recov(cid:173)
`ery of treating fluids. No diffi(cid:173)
`culty encountered.
`
`50 BOPO
`
`342 BOPO
`flowing
`220 BOPO
`after 18 days
`
`three days after
`Retreatment,
`original completion.
`
`Cisco
`
`Cisco
`
`Scurry
`
`J
`
`Canyon
`(sand)
`
`Pardue
`
`Fisher
`
`2-year-old well
`500 gal Mud Acid
`completion
`6180'-6212'
`
`6,000 gal lease oil/
`water emulsion
`12,000 Ib sand
`down tubing
`
`1% -year-old well
`Open hole
`Natural completion
`4424'-4450'
`
`250 gal Mud Acid
`3,000 gal refined oil
`1,800 Ib sand
`Inj. rate-2 bbl/min
`down tubing
`
`7 SOPO
`
`112 BOPO
`after 54 days
`
`below packer. 40-60
`Treated
`mesh sand used. Previous treat(cid:173)
`ments in area, using 20-40 mesh
`sand, screened out.
`
`40 BOPO
`
`118 BOPO
`through
`12/64" choke
`after 5 days
`
`treatment of offset
`In "frac"
`well, without Mud Acid, forma(cid:173)
`tion would not accept desired
`amount of sand,
`
`K
`
`Devonian
`(lime)
`
`South
`Andrews
`
`Andrews 3 1j,-month-old well 20,000 gal acid/
`6,000 gal acid
`kerosene emulsion
`completion
`30,000 Ib sand
`10,864'-11 ,059'
`down casing
`
`55 BOPO
`
`310 BOPO
`potential
`
`Deepest well treated down cas(cid:173)
`ing, to dote.
`
`l
`
`Waddell
`(sand)
`
`Abell
`
`Pecos
`
`New well
`Perforated
`5516'-5542'
`
`3,000 gal lease oil/
`water emulsion
`3,000 Ib sand
`250 gal Mud Acid
`Ini. rate-3 bbl/min
`down tubing
`
`Show
`
`192 SO PO
`
`Previous treatments ;n this sec(cid:173)
`tion with other carrying agents
`resulted
`in slow "clean·ups,"
`
`new ones. One such problem which has been accentu(cid:173)
`ated by frac work is that of controlling gas and water
`ratios.
`In many cases, where relatively close orientation of
`water zones to the bottom of the well bore exists, the
`use of special types of bottom-hole plugs has prevented
`increases in water production_ One of the most effective
`procedures has been the use of a high concentration of
`sand in a very thick carrying liquid, spotted across the
`zone expected to contain planes of weakness leading to
`water, More recently, the introduction of oil and cement
`slurry squeezes has aided in this type of control by
`blocking off such water leading planes and diverting
`the frac materials into planes of weakness within the
`oil bearing zone,
`
`FIELD RESULTS
`A tabulation of a number of Permian Basin frac
`treatments is given in Table 1. This table includes well
`data, treatment data, and treatment results, These par-
`
`ticular wells were chosen as being representative al(cid:173)
`though the type materials and size of treatment are not
`necessarily recommended for these individual pools, The
`results are as reported from the field and are subject to
`correction, Some wells in these various formations re(cid:173)
`sponded better and others less favorably than these ex(cid:173)
`amples; however, the wells cited are fairly typicaL Frac
`treatments have met with equal success in gas wells,
`High surface pressures apparently are not necessary
`in order to obtain sustained production increases, as evi(cid:173)
`denced by a number of these case histories. One ex(cid:173)
`ample was a San Andres well in the Howard-Glasscock
`Pool, with broken pay from 2,115 ft to 2,220 ft
`The well, originally completed with acid in 1952, was
`retreated with 9,000 gal of refined oil containing 12,000
`lb of sand, in May, 1954, Surface working pressure was
`150 psi, at 20 bbl per minute, with the well going on
`vacuum when the pumps were shut down, Originally
`producing 2 BOPD, the well was still making 60 BOPD
`with some water 45 days after the treatment
`
`62
`
`PETROLEUM TRANSACTIONS, AIME
`
`5 of 8
`
`Ex. 2088
`IPR2016-01517
`
`

`

`BlK. 30
`SE:C. 33
`U NI V ERSI T Y L EASE
`McELRO Y PO O L
`((j R .... VBURG)
`
`7WELLS TAtAUD
`NEW TANKS INSTALLED
`TOTAL COST •• U.OOO
`ACO'L PROD. · IZ,IZS 88LS.
`
`2Wf:LL S 'tREATED
`NEW TANr(S
`INSTALLED
`TOTAL COS T * 12,000
`AOD'L PROO . - 6,940 88LS
`
`•
`
`•
`
`II1IIIIlI1I1IIm PROJEC.TtD PRODUCTION
`IIIIIlIIIIIIlli 8ASED ON TOP ALLOWABLE
`
`FIG. 2 - MONTHLY PRODUCTION ON LEASE, CONSISTING
`OF NINE WELLS
`
`An example of how frac treatments have helped lease
`recovery in an old field is presented in graphic form in
`Fig.2.
`Each of the wells on this lease was treated with
`approximately 15,000 gal of refined oil and 30,000 lb
`of sand, at injection rates from 10 bbl per minute down
`3-in tubing, to 20 bbl per minute down casing. To
`determine which method of treatment was to be used,
`a gauge log was run on each string of casing. Those
`indicated to be in good condition were treated down the
`casing.
`Spinner surveys frequently are conducted when the
`desired results are not obtained following the frac treat(cid:173)
`ment. These may reveal channeling, either around the
`bottom of the casing shoe or behind perforations. Cor(cid:173)
`rection steps then may be taken accordingly.
`Also, spinner surveys will reveal what portion of the
`open hole was conditioned during the treatment. For
`example, spinner surveys were run on four wells in the
`Sprabeny, before and after 20,000 gal refinery oil-sand
`treatments with both the upper and lower Spraberry
`open (separated by about 800 ft). In all four wells, the
`surveys revealed that only about 10 per cent of the
`spinner fluid entered the lower Spraberry. Although the
`wells responded favorably, it is indicated that further
`stimulation work, following decline, should be concen(cid:173)
`trated on the lower zone to obtain additional produc(cid:173)
`tion.
`
`SECONDARY RECOVERY
`Many operators have been hesitant to perform frac
`treatments on wells in secondary recovery projects, for
`fear of early breakthrough of repressuring fluids result(cid:173)
`ing in by-passing of oil. It is conceivable that, under
`perfect flood conditions, the application of frac treat(cid:173)
`ments might be a hindrance; however, such an ideal
`condition is rarely encountered. Many times when a
`flood has been established, it will be found that one or
`more of the injection wells failed to accept the requisite
`amount of water. It is frequently necessary to increase
`the system pressure, requiring the expenditure of exces(cid:173)
`sive horsepower.
`The treatment of water injection wells in waterflood
`projects is a sizeable operation that requires special car(cid:173)
`rying agents. Aqueous gels have been used in fracturing
`
`VOL. 204, 1955
`
`FIG. 3 -
`PHOTOMICROGRAPH OF CORE FROM GLORIETA
`FOHMATlON. OPEN FRACT URE (LOWER LEFT TO RIGHT
`CENTER) IN ANHYDRITIC DOLOMITE.
`
`A number of these narrow. short fractures are present in the rock.
`Anhydrite crystals are white, however, some additional anhydrite
`crys