BAKER HUGHES INCORPORATED
`Exhibit 1017
`
`Page 1 of 8
`
`

`
`WELL COM PLETIONS
`
`
`
`A New Development in Completion Methods—
`
`The Limited Entry Technique
`
`K. W. LAGRONE
`JUNIOR MEMBER AIME
`J. W. RASMUSSEN
`
`sum on co.
`MIDLAND, tax.
`
`Abstract
`
`in Texas and New Mexico, has expe-
`Shell Oil Co.,
`rienced excellent results from an improved well stimulation
`method called the limited entry technique. This method
`has proven much more efiective than any other method
`in treating thick pay sections and in diverting treating
`fluids to multiple horizons. The limited entry treatment
`technique is accomplished by (I) limiting the number of
`perforations in a well and (2) providing sufiicient injection
`rate to require the restricted flow capacity of the perfora-
`tions lo divert
`the treatment to a greater portion of the
`perforated interval.
`in
`to Jan. I, 1963, Shell Oil Co.
`From Dec. 3, 1960,
`Texas and New Mexico has treated 363 wells by this
`technique. The production performance of wells treated
`by limited entry completions is superior to that of con-
`ventionally treated wells. Gamma-ray tracer logs indicate
`most of the pay is being treated even though not covered
`by perforations. The limited entry technique has been
`used successfully in treating two separate reservoirs simul-
`taneously in dually completed wells. Results of
`these
`simultaneous
`treatments have been gratifying in both
`well performance and reduced costs.
`
`Introduction
`
`The efficient simultaneous treatment of multiple porous
`intervals in a reservoir has been a long-standing problem
`in well stimulation. Various methods have been used to
`treat multiple zones with greater or lesser degrees of
`effectiveness. The bridge plug and packer method is
`effective, but is relatively expensive. Further, the injection
`rates are considerably reduced, and it
`is sometimes me-
`chanically hazardous. Temporary plugging agents to divert
`the treatment have been used with apparent success. The
`main disadvantage of temporary plugging agents such as
`moth balls or gel blocks is the difliculty in determining the
`proper quantity of agent required to divert the treatment.
`Ball sealers are often ineffective because of
`(1)
`fluid
`communicating behind the casing between closely spaced
`perforations, (2) failure of the ball sealers to seat on the
`perforations and (3) abrasion of the ball sealers allowing
`fluid to by-pass. These stimulation techniques (for the
`Original manuscript received in Society of Petroleum Engineers office
`April 8, 1963. Paper presented at SPE Rocky Mountain. Regional Meet-
`ing, May 27-28, 1963, in Denver, Colo.
`
`JULY, 1963
`
`SPE 530
`
`purposes of this paper) are considered to be conventional
`treatment methods.
`
`The basic objective of all stimulation efforts is to make
`the best well, compatible with cost. To get an effective
`treatment, it is desirable to treat as much of the perforated
`interval as possible. Also, the treatment should be propor-
`tioned into the perforated intervals. Well performance has
`proven that both of these objectives can be better fulfilled
`by a properly designed limited entry treatment, than by
`conventional treatments.
`
`Limited Entry Technique
`
`in Texas and New Mexico, has expe-
`Shell Oil Co.,
`rienced excellent results from an improved well stimula-
`tion method called the limited entry technique. Based
`upon data obtained to date,
`this method is far superior
`to the other methods of obtaining simultaneous treatment
`of multiple zones or thick pay sections. The treatment is
`performed by (1)
`limiting the number of perforations
`in a well and (2) providing sufficient
`injection rate to
`require the restricted capacity of
`the perforations
`to
`divert the treatment to a greater portion of the perforated
`interval.
`
`in this region was
`limited entry treatment
`The first
`performed in Shell TXL M-3, TXL Tubb field, Ector
`County, Tex., following a review of a paper by Murphy
`and Juch of Compafiia Shell de Venezuela." 2 From Dec. 3,
`1960, to Jan. 1, 1963, 363 limited entry treatments have
`been performed in many different reservoirs (see Fig. 1).
`No mechanical difficulties have been encountered that can
`be attributed to this method of
`treatment. Treatment
`failures due to “sand-outs” have not been increased by
`this method. Treatments have been sucessfully performed
`in carbonate, sandstone, conglomerate and chert reservoirs.
`These reservoirs range in depths from 3,100 to 9,500 ft,
`with bottom-hole pressures varying from 1,000 to 3,600
`psi.
`
`Basic Theory of Fracturing Process
`(lonventional Treatment
`
`The simultaneous treatment of multiple porous inter-«
`vals by conventional methods is depicted in Fig. 2. Three
`zones with different bottom-hole fracture pressures are
`‘References given at end of paper.
`
`695
`
`Page 1 of 8
`Page 1 of 8
`
`

`
`opened up in the same wellbore. The zone which offers
`.the least fracture resistance will take the treatment. This
`zone will continue to take the treatment until a diverting
`method is successfully utilized.
`
`Limited Entry Treatment
`the bottom-
`To treat more than one porous interval,
`hole treating pressure must be raised above the fracture
`initiation pressure of each successive zone to be treated.
`This can be accomplished by limiting the number and
`diameter of the perforations in the casing. As seen from
`Fig. 3,
`the perforation friction pressure varies directly
`with the rate pumped through the perforation. Therefore,
`by increasing the injection rate,
`the perforation friction
`will be increased. In other words,
`the perforations are
`acting as individual bottom-hole chokes. They create an
`increase in available bottom-hole casing pressure as the
`injection rate is increased. The accompanying increase in
`pressure in the casing will then break down or fracture
`the next zone as indicated in Fig. 4.
`The process of breaking down each successive zone
`occurs rapidly, since maximum pressure and rates are
`established early in the treatment. Assuming adequate in-
`jection rate at the surface,
`this process is continued until
`either all of the perforated zones are being fracture treated
`
`the maximum permissible pressure on the casing is
`or
`reached.
`
`Specific Factors Affecting Design of Limited
`Entry Completions
`
`Perforation Friction
`
`results are obtained by maintaining perforation
`Best
`friction at a maximum during treatment. This insures
`treatment of all perforated intervals that will accept fluid
`within the permissible casing pressure limitations. It
`is
`recognized that all
`the perforations could be treated at
`a lesser injection rate. However,
`this would not be true
`if
`the bottom-hole fracture pressure of
`the individual
`porous members varies significantly. Therefore,
`to have
`the most assurance that all zones are being treated, an
`injection rate that will give a maximum permissible casing
`pressure is necessary.
`Small-diameter perforations are preferred in limited
`entry treatments to (1) increase perforation friction and
`(2)
`lower hydraulic horsepower
`requirements. Fig.
`3
`shows that, for the same perforation friction, approxi-
`mately twice as much fluid can be injected through a
`1/2-in. hole as through a 3/s-in. hole. Therefore, by using
`the small perforations,
`less hydraulic horsepower is re-
`
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`INDEX MAP
`
`L E GE N D
`oeuorss AT LEAST ,oNE TREATMENT
`:
`DENOTES NUMBER OF TREATMENTS
`WHERE MORE THAN ONE OCCURRED
`
`Fig. l—Map of limited entry treatments, Shell Oil Co., Midland (Tex.) area and New Mexico.
`
`696
`
`JOURNAL OF PETROLEUM TECHNO-LOGY
`
`Page 2 of 8
`Page 2 of 8
`
`

`
`bottom-hole fracture pressures being similar. Where it is
`recognized that considerable variations exist in the bottom-
`nole fracture pressures of the zones, the treatment design
`should be altered. The zone with the lowest bottom-hole
`fracture pressure would normally receive the most treat-
`ment per perforation. Therefore, the number and/or size
`of the perforations should be reduced in this zone. In the
`zone with the highest bottom-hole fracture pressure,
`the
`converse would be true.
`
`Design of a Limited Entry Treatment
`
`As stated before, the main reason for limiting the num-
`ber of perforations is to maintain control of the placement
`of the fracturing fluids. Therefore, it is important to know
`the number of perforations to use for a desired injection
`rate to obtain maximum perforation friction.
`The equation for perforation friction is:
`.
`P,,,=P,-ISIP—P,.
`.
`.
`.
`P, = surface injection pressure, psi,
`ISIP = instantaneous
`shut-in pressure, psi, and
`P, = casing or tubing friction loss, psi.
`This equation was derived by substitution in the follow-
`ing equations:
`BHFP = P, + P,, — P, — ,,,,
`BHFP = ISIP + P,,
`
`.
`
`.
`
`.
`
`(1)
`
`where
`
`where BHFP = bottom-hole fracture pressure, psi, and
`P,, = hydrostatic pressure, psi.
`The design of a limited entry treatment is made by a
`trial—and-error method. First, a minimum number of per-
`forations is chosen to treat all of the pay interval and
`properly proportion the treatment. Second, an injection
`rate is determined for those perforations that will main-
`tain maximum perforation friction (within casing pressure
`limitations). If the calculated injection rate is considered
`unreasonable (either too high or too low),
`the number
`and placement of the perforations would be reviewed. For
`a sample design calculation,
`see the TXL K-18 field
`example.
`
`Comparison of Conventional and Limited
`Entry Design
`
`4200psi
`
`Zone
`
`A
`
`4200psi
`
`Zone
`
`A Azoopsi
`
`quired to deliver an injection rate adequate to maintain
`a maximum perforation friction. Few difficulties have been
`encountered to date in fracture treating through %-in.
`jet perforations. Therefore, %-in. perforations are gen-
`erally used for limited entry treatments.
`Experiments have been performed by The Halliburton
`Co. and others where a variety of treating fluids with sand
`was pumped through %- and 1/2-in. perforations. During
`the tests,
`small
`irregularities in the perforations were
`quickly smoothed out
`(with sand-oil mixtures) and the
`perforations altered from sharp-edged to round-edged
`orifices. The hole diameters, however,
`remained essen-
`tially unchanged within the normal pumping times of a
`fracture treatment.
`
`Proportioning of Treatment
`Limited entry treatments can be designed so that the
`desired amount of fluids will be injected into each porous
`zone. This is an important advantage where thick zones,
`which require more treatment, are treated in conjunction
`with thin zones. It is assumed that each perforation will
`accept approximately the same amount of fluid. Therefore,
`by proportioning the number of perforations according to
`the thickness of the zone, each zone will be given the
`desired amount of
`treatment.
`
`A word of caution—the above method of proportioning
`fluids into zones through perforations depends on the
`
`STEP 2
`
`
`
` Zone A 4200 psi
`
`Zone 8
`
`
`3800psi
`
`Start Fracture 8 Continue
`Treatment At Fracture
`Pressure Of Zone
`8
`
`
`
`
`
`
`
`F—It'—!Flseoopsr
`
`STEP I
`
`Zone
`
`Zone
`
`A
`
`8
`
`4200 psi
`
`3500951
`
`4000asi
`C
`Zone
`Before Treatment
`
`«HydrostaticTo330095:
`
`[ [ [
`
`,,
`
`STEP 3
`
`STEP 4
`
`[5
`.‘_'
`Es
`1:>.
`[ §
`E
`[
`
`
`Zone
`
`A
`
`4200psi
`
`Zone B 380095:
`
`490095;
`5
`zone
`Finished Treatment
`
`Temporarily
`Treat
`
`Plug
`8‘
`Zone
`
`C
`
`Zane
`etc.
`
`E!
`
`NOTE:
`
`equals bottom hale
`Pressure
`In
`each zone
`f"°°""° P"°55“’°
`
`[ Continuous Pertorations
`Fig. 2——»Fi-acturing process——conventional treatment.
`4.0
`
`9'or
`
`Fig. 5 shows a comparison between the design of a
`limited entry completion vs a conventional completion.
`This well has 5 1/2-in. casing cemented through multiple
`porous zones. In the conventional completion as shown,
`with two perforations/ft of pay, any one zone could accept
`3
`STEP I
`STEP 2
`3
`STEP 3
`g
`o
`m
`2
`-5
`o—
`,2
`§
`*9
`—§
`E
`
`zaaos.
`3EOOpsi é Zone B
`
`Zone
`
`8
`
`380095:
`
`
`
`C 4000pSl
`Zone
`Start Fracture 3 Build
`Up Pressure — Break
`Zone
`B
`
`Zone
`— Larger Rate :
`Pressure
`
`4000usv
`c
`Increased
`
`3/9" JET HOLE
`WATERI
`E’ ,
`
`on.
`3/3" JET HOLE
`
`S"N
`
`E“an
`
`E“a
`
`1/2" BULLET
`“ on. a SAN!)
`
`
`
`Zone
`
`Zone
`
`A
`
`E
`
`3800051
`
`40OOpsI
`C
`Zone
`Be,” Tmmme“.
`
`
`
`
`
`
`
`FLOWRATETHROUGHSVNGLEPERFORATION(BBLS/MIN
`
`
`
`
`
`17:
`
`ix:
`
`..NisIn0
`
`O
`
`200
`
`400
`
`llL
`J
`I400
`I200
`I000
`600
`800
`FRICTION LOSS ACROSS PERFORATIONS
`
`I600
`
`I800
`
`2000
`
`‘E4200psi
`
`
`
`anew
`; Zone 8 380099
`zoops.
`; Zone C 400005:
`Larger Rate = Increased
`Pressure
`NOTEI Pressure m each zone
`equals bottom hate
`fracture pressure
`0- Single Pertoration
`
`STEP 5
`Pressure Zone A
`<—Hyaro'smnc Ie c moons.
`
`4200 psi
`
`L20“ B 3800 as.
`
`Finished
`
`Treatment
`
`
`
`0r
`
`STEP 4
`Zone A 4200 psi
`
`0
`
`o
`
`laboratory measured
`Fig. 3—Flow rate vs friction loss,
`(courtesy of The Halliburton Co.).
`
`Fig. 4--Fracturing process—limited entry treatment.
`
`JULY, 1963
`
`697
`
`Page 3 of 8
`Page 3 of 8
`
`

`
`all of the treatment unless diverting agents were success-
`fully used. In the limited entry design,
`ten %-in. holes
`were distributed into the various porous members to treat
`all of the pay and to properly proportion the treatment.
`The actual number of holes taking treatment can be deter-
`mined from perforation friction calculations made from
`field data taken while treating. It would be difficult, if not
`impossible, to gain this kind of information while treating
`in the conventional manner.
`
`Field Data Used in Treatment Analysis
`The limited entry technique provides field data that can
`be used to determine the number of intervals that were
`treated. If this analysis indicates that all zones are not
`being treated, the completion design can be altered.
`The three essentials necessary to determine the number
`of perforations accepting fluid are: (1) accurate injection
`rates, (2) accurate surface injection pressures and (3) an
`instantaneous shut-in pressure (ISIP) at the beginning of
`the job. Injection rates obtained by averaging over pro-
`longed periods of the treatment are not generally adequate
`for this method. A continuous-rate recorder is considered
`most helpful.
`If a perforation friction calculation is to be made while
`a sand-oil mixture is being injected into the formation, the
`instantaneous shut-in pressure as measured at the surface
`must be corrected for the change in hydrostatic pressure
`due to the addition of sand (see TXL K-18 sample calcu-
`lation).
`Based upon experience, the instantaneous shut-in pres-
`sure should be measured at the start of the treatment. This
`is necessary to calculate the actual number of perforations
`accepting fluid during treatment. A definition of ISIP is:
`that static pressure required to hold a fracture open. Fig. 6
`is a treatment pressure chart. While pumping into the
`formation at fracture pressure, to get an ISIP, pumps are
`stopped instantaneously. The recorded surface pressure
`falls abruptly to a stabilized pressure and then bleeds-ofli
`slowly into the formation. The abrupt stabilized pressure
`point is a measurement of the ISIP. Note that the ISIP
`at the start. of the treatment in Fig. 6 is 2,400 psi and has
`increased to 3,000 psi at the end of the treatment. This is
`not a freak occurrence. The ISIP increases during all
`treatments. Fig. 7 has been prepared to show the rela-
`tionship between ISIP and treatment size.
`The ISIP is plotted against the fluid volume displaced
`into the formation. There is a straight-line relationship
`between these two factors. Included in the volume dis-
`placed into the formation is the volume of fluid in front
`of the fracture treatment, the treatment volume itself and
`CONVENTIONAL
`GAMMA RAY
`LIMITED ENTRY
`COMPLETION
`SONIC
`COMPLETION
`
`r‘\Q
`
`also
`
`“Q
`
`T ma
`
`FT
`FT
`
`PERF.
`
`PERF.
`FT
`PERF.
`FT
`PERF.
`
`the
`In the example of
`any overdisplacement volume.
`Hobbs K-6 (Fig. 7) the ISIP was 2,200 psi at the start
`of the treatment during breakdown with lease crude. The
`[SIP had increased to 3,500 psi at the end of the treatment
`after displacing 35,000 gal into the formation with lease
`crude. It
`is obvious that
`the calculation for perforation
`friction (P,,,) could vary considerably depending upon
`which ISIP is used. In the example of the Hobbs K-6,
`if the final ISIP were used, the calculation for PM would
`have had a negative value. This is an impossible figure.
`Using the final ISIP will not always give a negative value.
`As in the case of the Slator B-8,
`if the final ISIP were
`used, the P,,, would not be negative, but it would be some
`400-psi lower than that if the initial ISIP had been used
`in the calculations. Therefore, the calculated injection rate
`per hole would be too low.
`The only time that an instantaneous shut-in pressure
`is a direct surface measure of actual bottom-hole fracture
`pressure is at the start of a treatment. A theory is pro-
`posed to explain why this is true and why it is necessary
`to use the initial ISIP in the perforation friction (PM)
`calculations. Fig. 8 shows a Wellbore with a perforation
`through which fluid is being pumped into a fracture. In
`this example, the bottom-hole treating pressure inside the
`casing is 5,700 psi and the perforation friction is 1,000
`psi. The formation bottom-hole fracture pressure is 4,700
`psi as measured at the start of the treatment.
`Assume that the bottom-hole treating pressure and per-
`foration friction remain constant during treatment. How-
`ever, Fig. 7 shows that the ISIP does not remain constant.
`The ISIP is a direct surface measurement of the BHFP.
`Therefore, if the ISIP increases during treatment, so must
`the bottom-hole fracture pressure. It is proposed that the
`increase in BHFP is due to a pressure bank which is
`created around the fracture, due to fluid loss from the
`treating fluid. The fluids are forced from the fracture to
`
`
`2400 2000
`
`
`INSTANTANEOUSSHUTINPRESSURE(PS|Gl 400
`
`_
`SLATOR B 5 “L
`
`FIELD
`
`-
`
`--
`
`4000
`
`360
`
`320
`
`2800
`
`Isoogm
`I200
`
`aoo
`
`TOTAL
`I46 PERF. 3x;
`73 FT
`
`W
`
`‘I’
`
`(>\4
`
`TOTAL
`IO PERF.
`75 FT
`
`°
`
`L
`so
`70
`so
`so
`40
`so
`20
`I0
`VOLUME DISPLACED INTO FORMATION (IN THOUSANDS or GALLONS)
`
`so
`
`Fig. 5—-Comparison of Completion design—limiIed entry
`vs conventional.
`
`Fig. 7-Instantaneous shut-in pressure vs volume displaced
`into formation.
`
`698
`
`JOURNAL OF PETROLEUM TECHNOLOGY
`Page 4 of 8
`Page 4 of 8
`
`

`
`/-CASING
`
`BOTTOM HOLE
`TREATING
`PRESSURE
`5700 P SI
`
`
`FRICTION
`PERFORATEJ/'
`1
`I000 PSI
`
`
`
`BHFP 4700 PSI-'-
`
`‘
`
`
`4
`0
`4
`I
`MAXIMUM FRACTURE
`
`I
`
`‘WIDTH
`
`Fig. 8——Pressure bank build-up along fracture.
`
`the matrix faster than they can escape through the matrix.
`This would create an increased pressure area around the
`fracture, or a pressure bank. As this pressure builds up,
`it becomes increasingly more difficult to hold the fracture
`open as evidenced by the increase in the ISIP. In other
`words,
`the pressure bank is attempting to close the
`fracture.
`
`The highest pressure in the pressure bank occurs at the
`borehole at the mouth of the fracture. This region has
`had the longest time to be charged by the fluids that are
`forced from the fracture to the matrix. The pressure bank
`diminishes along the length of the fracture, and at
`the
`end of the fracture it would be essentially zero. Since
`there is no pressure bank build-up at
`the end of the
`fracture,
`the BHFP of 4,700 psi
`is still
`the same as
`measured initially when the treatment was started. Fluids
`can still escape along the fracture at the same BHFP as
`was initially measured at the start of the treatment. There-
`fore,
`the initial ISIP should be used in the P,,, calcula-
`tions. Obviously, as the pressure in the pressure bank
`approaches the pressure inside the fracture, there will be
`a reduction in the fracture width which will eventually
`cause a reduction in the injection rate through each per-
`foration. This, however, is not a normal occurrence.
`
`Comparison of Limited Entry vs
`Conventional Completions
`
`Multiple Porous Interval
`The following data from wells in the TXL-Tubb field
`(Lower Clearfork formation) are offered as a comparison
`of initial performance of similar wells producing from
`multiple porous intervals in an area where the comparison
`is available (Table 1). The wells are comparable in the
`feet of pay developed, the size of fracture treatments and
`the expected ultimate recoveries. The pay is distributed
`over a gross interval of about 400 ft.
`Table 1
`includes all Shell TXL-Tubb wells in which
`pressure build-up tests have been taken. The data are
`considered to be of good quality because of the excep-
`tionally good pressure build-up curves.
`As indicated, the initial measurement of average Kh for
`conventional vs limited entry treated wells has been in-
`creased from 41 to 254 md-ft, or an increase of 520 per
`cent. The productivity index, as calculated from pressure
`build-up data, has been increased an average of 330 per
`cent over that of conventionally treated wells. Specific
`productivity index (PI per net feet of pay) has been
`increased an average of 340 per cent. The average ofiicial
`potential
`test has been 31-BOPD higher for the limited
`entry completions.
`
`Single Porous Interval
`
`Data from wells in the Crossett field (Devonian forma-
`tion) are presented as a comparison of initial perform-
`
`JULY, 1963
`
`ance of similar wells producing from a single porous
`interval
`(Table 2). The average potential
`test was in-
`creased from 208 to 237 BOPD. This increase of 29
`BOPD in favor of the limited entry completions is not
`too significant. However, a review of
`the productivity
`index data shows that much better wells have been made
`by the limited entry technique. The permeability feet
`total
`(Kh) was increased from 121 to 307, or 154 per
`cent higher in the limited entry completions. The limited
`entry completions also have a productivity index that is
`116 per cent higher than the conventionally completed
`wells. Since the conventional completions were generally
`given a slightly smaller
`fracture treatment, an attempt
`was made to correlate P1 with the size of the fracture
`treatment. No relationship could be established. The lim-
`ited entry completions have an average of 63 ft of pay
`Vs 48 ft of pay for the conventional completions. There-
`fore, to eliminate the effect of more pay on the produc-
`tivity index, the specific productivity index was calculated.
`This is the productivity index per foot of net pay. The
`specific PI averaged 63 per cent higher for the limited
`entry completions.
`Figs. 9, 10 and 11 are presented to show the relation-
`ship between PI and feet of pay.
`In the conventional
`completions shown in Fig. 9,
`the PI does not
`increase
`with an attendant increase in the net feet of pay. As indi-
`cated, the PI is the same for 20 ft of pay as it is for 120
`ft of pay.
`Figs. 10 and 11 show a definite relationship between
`the feet of pay and the PI for the limited entry comple-
`tions. For example, from Fig. 10 the PI for 20 ft of pay
`is about 0.20 bbl/psi decrease; the PI for 120 ft has been
`increased to about 2.30. The PI is better in the thicker
`
`pay intervals because the limited number of perforations
`proportioned the treatment over the entire pay interval.
`Whereas, when the entire interval was perforated by two
`TABLE 1—COMPARlSON OF AVERAGE INITIAL WELL PERFORMANCE, MULTIPLE
`POROUS lNTERVAL$—LlMITED ENTRY TREATMENT VS CONVENTIONAL TREAT-
`MENT, TXL-TUBB FIELD, LOWER CLEARFORK FORMATION, ECTOR COUNTY, TEX.
`Treatment Method
`limited Entry
`Conventional
`5
`8
`No. of Wells
`54
`50
`Net Pay, ft
`24
`233
`No. of Perforaiions
`Fracture Treatment
`28,000
`26,250
`Oil, gal
`42,000
`46,000
`Sand, lb
`7
`138
`Ball Sealers
`Official Potential Test
`244
`213
`BOPD
`21/64
`22/64
`Choke, in.
`Bottom-Hole Pressure Build-up Data‘*
`254
`41
`Kh, md-ft
`5.24
`0.81
`K, rnd
`0.351
`0.082
`P*Pl
`7.24
`1.64
`Specific P*PI X 10-3
`P* = extrapolation of pressure
`pay;
`>~’. feet of
`**Kh = permeability (md)
`build-up curve to an infinite shut-in time; Pl = productivity index = barrels (per
`day) per psi pressure drop; and specific P*Pl : productivity index per net feet
`pay.
`
`TABLE 2—COMPARl5ON OF AVERAGE INITIAL WELL PERFORMANCE, SINGLE
`PRODUCTIVE
`lNTERVAL—L|MITED ENTRY TREATMENT VS CONVENTIONAL
`TREATMENT, CROSSETT FIELD, DEVONIAN FORMATION, CROCKETT COUNTY,
`TEX.
`Treatment Method
`Limited Entry
`Conventional
`38
`20
`No. of Wells
`63
`43
`Net Pay, ft
`9
`150
`No. of Ferforations
`Fracture Treatment
`18,600
`11,400
`Oil, gal
`16,700
`14,900
`Sand, lb
`Official Potential Test
`237
`208
`BOPD
`13/64
`14/64
`in
`Choke,
`Bottom-Hole Pressure Build-up Data**
`307
`121
`Kh, md-ft
`4.9
`2.5
`K. md
`0.67
`0.31
`P*Pl
`10.6
`6.5
`Specific P*P| X 10-3
`P* = extrapolation of
`pressure
`f*Kh = permeability .(l'lId) >< feet of pay;
`build-up curve to an infinite shut-in time; PI = productivity index = barrels (per
`day) per PSI pressure drop; and specific W‘?! = productivity index per net
`feet
`BUY-
`
`699
`
`Page 5 of 8
`Page 5 of 8
`
`

`
`or more perforations/ft, only the easier intervals to frac-
`ture took treatment.
`Note the two separate relationships established between
`PI and feet of pay in Figs. 10 and 11, both of which are
`limited entry completions. The wells in Fig. 11 grouped
`themselves into two parts of the field in downthrown fault
`blocks. The wells in Fig. 10 are located in between, in the
`upthrown fault block. The porosity and permeability for
`the Crossett field are considered to be controlled by the
`degree of weathering that has taken place in the siliceous
`limestone. Therefore, it appears reasonable to assume that
`the upthrown block, underlying an erosional unconformity,
`received more weathering and should have better porosity
`and permeability characteristics than that of the down-
`thrown blocks. This could account for the better PI vs feet
`of pay relationship in the upthrown block.
`
`Operational Techniques
`
`Opening Perforations Prior to Treatment
`The major difficulty that has been encountered in lim-
`ited entry treatments has been insuring that all holes are
`open prior to the fracture treatment. Seldom are all of
`the perforations able to accept fluids without first being
`acidized. It is believed that this problem exists with con-
`ventional completions, but usually remains unnoticed.
`Where the number of perforations is greatly limited,
`it
`becomes obvious if some are not open to the formation.
`An acidizing technique has been adopted that is prac-
`tical only for limited entry completions. The procedure
`involves staging the acid in small slugs (100 to 200 gal)
`separated by a maximum of two ball sealers in an oil
`spacer. The number of stages is determined by the num-
`ber of ball sealers required to “ball out” the perforations.
`This allows a better estimate of the number of perfora-
`tions that are open at the end of the acid treatment. After
`ball-out occurs, pressure is held on the remaining acid in
`the casing for a short time interval to provide every oppor-
`tunity for additional perforations,
`if any,
`to be opened.
`Fracture Treatment
`
`Limited entry fracture treatments have been performed
`with injection pressures,
`rates,
`treating-fluid types and
`volumes similar to those of conventional treatments. Some-
`times,
`it
`is undesirable or impossible to have injection
`200
`
`NETPAY(FEET)
`
` I50
`
`o
`
`1.0
`
`2.0
`
`
`3.0
`4.0
`5.0
`PI
`
`P'
`
`rates sufficient to insure treatment of all the perforations.
`In this case, ball sealers can be effectively used as a divert-
`ing agent. Experience indicates ball-sealer action to be
`near 100 per cent effective in limited entry treatments.
`This may be due to higher injection rate per hole and
`greater separation between perforations. Extra precaution
`should be taken to avoid excessive pressure surges due to
`the excellent ball-sealer action.
`
`Individual perforations sometimes sand-out during treat-
`ment. A decrease in injection rate is indicative of the time
`and number of perforations affected when sand out occurs.
`A continuous-rate recorder is necessary for observing the
`loss of perforations taking treatment. It is also most help-
`ful
`in determining the proper number of ball sealers to
`drop during a job.
`
`Field Examples of Limited Entry Treatments
`
`Fig. 12 shows the design and fracture treatment results
`
`zoo
`
`GOrt?"
`
`—A
`
`0
`
`|.O
`
`2.0
`
`§.0
`P I
`
`P
`
`4.0
`
`5.0
`
`Fig. 10—Limited entry completions—P*PI vs net pay,
`Crossett field, Devonian formation, Crockett County, Tex.
`200
`
`NETPAY(FEET) 5o
`NETPAY(FEET) 5o
`
`[50
`
`0
`
`1.0
`
`2.0
`
`3.0
`P. PI
`
`4.0
`
`5.0
`
`Fig. 9—-Conventional eompletions—-P*PI vs net pay,
`Crossett field, Devonian formation, Crockett County, Tex.
`700
`
`Fig. 11—Limited entry completions-—P*PI vs net pay,
`Crossett field, Devonian formation, Crockett County, Tex.
`
`JOURNAL OF PETROLEUM TECHNOLOGY
`
`Page 6 of 8
`Page 6 of 8
`
`

`
`the Wolfcamp formation in Shell TXL K-18, Ector
`of
`County, Tex. This well was fracture treated down the
`casing through nine %-in. perforations at 31 bbl/min.
`The calculations indicated that all nine holes were accept-
`ing treatment. Shell TXL K-18 was fracture treated with
`a radioactive sand. Therefore, any radioactive increase
`above that of the base gamma-ray log is considered to be
`an indication of the fracture-treated interval.
`
`the perforations were placed so that all of
`Note that
`the pay was fracture treated, as indicated by the radio-
`active increase opposite all of the pay, even though it was
`not perforated. The well was potentialed flowing 254
`BOPD,
`through an 18/64-in.
`top choke, with a flowing
`tubing pressure of 300 psi.
`
`Sample Calculation of Design and Analysis of a
`Limited Entry Treatment
`
`Data
`
`The following sample calculations pertain to a limited
`entry treatment conducted on Well No. TXL K-18 located
`in the TXL—Wo1fcamp field, Ector County, Tex. This well
`was completed through 7-in., 23-lb casing with a gross
`pay interval ranging from 7,509 to 7,682 ft, and a net
`pay thickness of 63 ft.
`
`Sample Calculation of Design
`This well
`is to be fracture treated down 7-in. casing
`with a maximum permissible casing pressure of 3,600 psi.
`Based upon the pay distribution as shown by the porosity
`log (Fig. 12), a total of nine 3/s-in. holes was chosen to
`effectively proportion treatment over the pay interval.
`From Eq. 1,
`P,,, = P, — ISIP — P,,
`where P, = 3,600 psi (casing pressure limitation),
`ISIP = 1,700 psi (determined from experience in for-
`mation and area), and
`GAMMA RAY
`
`SONIC
`
`WOLFCAMP
`
` J
`
`7700
`
`-----
`
`LEGEND
`GAMMA RAY LOG aeroas TREATMENT
`GAMMA RAY LOG AFTER TREATMENT
`O—— smcu: PERFORATIONS
`NET PAY
`
`Fig. 12——More eflective pay treatment by limited entry
`treatment, Shell-TXL K-18, TXL Wolfcamp field,
`Ector County, Tex.
`
`JULY. 1963
`
`P, = 190 psi (from friction charts based upon trial
`rate of 25 bbl/min).
`
`Thus,
`
`PM = 3,600 — 1,700 — 190,
`P,,, = 1,710 psi.
`
`From Fig. 3, a perforation friction of 1,710 psi for an oil
`and sand mixture gives an injection rate of 3.3 bbl/min/
`hole. From these conditions, an injection rate through nine
`perforations would be expected to be 9 X 3.3 = 30 bbl/
`min. Since an injection rate of 25 bbl/min was assumed
`to determine the casing friction pressure, calculations
`should be repeated assuming an injection rate between
`25 to 30 bbl/min until the calculated value of total injec-
`tion rate through the nine perforations equals the assumed
`rate. In this case it would be 29 bbl/min, or 3.2 bbl/min/
`hole.
`
`If this
`The calculated injection rate was acceptable.
`injection rate had been undesirable, either too high or
`too low,
`the number and placement of the perforations
`would have been reviewed.
`
`Sample Calculation of Treatment Analysis
`The following data were obtained: perforations—top
`7,509 ft, bottom 7,656 ft, average depth 7,550 ft, nine
`holes; breakdown fluid—oi1, 36° API gravity = 0.365
`psi/ft; frac fluid—oil + 11/2-lb/gal sand = 0.415 psi/ft;
`surface
`treating pressure
`(P,) = 3,600 psi;
`injection
`rate = 31 bbl/min; instantaneous shut-in pressure surface
`(ISIP) = 1,700 psi; and casing friction (P,) at 31 bbl/
`min at 7,550-ft depth = 315 psi.
`This well was fracture treated down 7-in. casing through
`nine %-in. perforations. Instantaneous shut-in pressure of
`1,700 psi was measured during breakdown of formation
`with lease crude. The following calculation was made from
`data obtained while fracture treating with lease crude and
`sand. Therefore, it is necessary to correct ISIP for increase
`in hydrostatic pressure due to addition of sand as follows:
`ISIP Surface — (Frac Fluid, psi/ft — Breakdown Fluid,
`psi/ft) X Average Depth.
`Thus,
`
`ISI