`
`SPE-171183-MS
`
`Single-Size-Ball lnterventionless Multi-Stage Stimulation System Improves
`Stimulated Reservoir Volume and Eliminates Milling Requirements: Case
`
`Studies
`
`Feng Yuan, Eric Blanton, and Jamie Inglesfield, Weatherford
`
`Copyright 2014. Society of Petroleum Engineers
`
`This paper was prepared for presentation at the SPE Russian Oil and Gas Exploration and Production Technical Conference and Exhibition held in Moscow, Russia.
`14—16 October 2014.
`
`This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents
`of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect
`any position of the Society of Petroleum Engineers, its officers. or members. Electronic reproduction, distribution, or storage of any part of this paper without the written
`consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may
`not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
`
`— A
`
`bstract
`
`In the last decade, there has been a tremendous growth in multi-stage fracturing for unconventional plays
`employing stimulation sleeves with open hole (OH) packers or cementing. Standard ball-activated frac
`sleeve systems with graduated ball seats have primarily been used because they can significantly save
`completion time and cost by facilitating the performance of multiple stimulations in a single continuous
`process compared with the conventional Plug and Perforate (P-n-P). However, traditional ball-activated
`frac sleeves have limitations in the number of stages that can be handled, the pressure drop and friction
`loss each one creates and the need to mill through the ball seats after stimulation. As the number of frac
`stages increases, the ball seat sizes become dramatically smaller leading to large increases in the surface
`treating pressure and hydraulic horse power (HHP) needed to generate a given net downhole pressure or
`injection rate.
`To solve these limitations a revolutionary ball-activated fracturing system has been designed. This
`system behaves in similar fashion of activation to the traditional graduated ball seat frac sleeve in that the
`ball locks into place on the seat, but all the ball seats are the same size and retract, allowing the first ball
`to pass through all sleeves until it reaches the lowermost one. Similarly the next ball, which is the same
`size, lands on the next seat up and so on, allowing a Virtually unlimited number of zones to be treated for
`either OH or cemented application. With this new system, there is no milling operation involved and the
`completion‘string maintains full drift inside diameter (ID) ready for production after stimulation opera-
`tions have been completed.
`In this paper the authors will describe in detail the operational mechanism of this new frac sleeve and
`present case studies of its use which illustrates the effect of this new technology in optimizing fracturing
`operations both in horsepower requirements and overall completion time and cost.
`
`Introduction
`
`There is a lot of debate about how best to complete and fracture unconventional formations regarding the
`effectiveness and efficiency differences between frac sleeve and P-n—P methods. Generally speaking,
`P-n-P is a time-consuming frac technique, due to the need for running Tubing Conveyed Perforating
`
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`2
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`SPE-171183-MS
`
`Cemented Sleeves
`
`Open Hole P&P
`
`Cemented P&P
`
`Open Hole Sleeves
`
`Figure 1—Percentages for different frac methods at Weatherford.
`
`(TCP), Coiled Tubing (CT) and downhole tractors, etc. However, P-n-P is still the number one stimulation
`technique being used in unconventional horizontal wells in North America and globally. P-n-P is
`considered to be an effective and flexible multistage fracturing technique for individual stimulation across
`laterals, because each stage can be perforated and treated optimally with fracturing design changes before
`guns are fired. Many operators choose P—n-P to complete their wells because they are familiar with it and
`consider it to be a low risk option
`However, openhole multi-stage (OHMS) completion techniques (frac sleeves + OH packers) are
`becoming more common in both North American unconventional plays and globally; for instance, OHMS
`techniques are the primary completion method for most new drilled shale/tight gas wells in the Bakken
`formation. The ball drop type of frac sleeve is well known to be a more efficient frac method and uses
`an “on-the-fly” method of isolating below the sleeve, opening a port, fracturing and then moving to the
`next zone, as well as being repeatable and reliable. The major advantage of frac sleeve is that all frac
`treatments can be performed in a single trip, with a continuous pumping operation without the need for
`a rig or CT or Wireline (WI) intervention. Dissolvable balls have already been used which will not
`impede production and could eliminate costly well intervention to drill out stuck frac balls. Figure 1 shows
`the distribution in percentages for different frac methods used in operations performed by Weatherford
`which reflect closely the overall distribution throughout the industry.
`In principle, the P-n—P option can be more effective in individual stimulation across the laterals and the
`conventional frac sleeve option can be more efficient by completing more stages in less time. However,
`both methods have their drawbacks, the former requiring multiple re-entries and mill out operations, the
`latter having a limited number of fracturing stages due to the graduated seat sizes needed and the
`probability of the need of milling out the seats upon completion to remove flow restrictions. With frac
`sleeves, operators need to weigh the advantages in efficiency against potential operational risks such as
`premature sleeve opening or screen-out. With P-n-P, they need to compare the advantages of more
`effective interval coverage against the increased time required to complete the entire lateral.
`In general, major benefits associated with OHMS against P-n-P can be summarized by elimination of
`the following operations and occurrences (Rivenbark et a1. 2013):
`
`o Eliminating TCP or CT perforation gun for the first stage before stimulation treatment begins.
`0 The time, equipment and cost associated with rigging up, running and rigging down WL for bridge
`plug (BP) and perforation operations.
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`SPE-171183-MS 3
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`o The milling out of BPs after the stimulation
`and flowback.
`
`o Misfires from P-n-P operations.
`0 Reduction of equipment and personnel on
`location, reducing overall HSE exposure.
`0 No well intervention during stimulation.
`0 Stimulation treatment
`involving the entire
`lateral allowing natural fractures to contrib—
`ute to production.
`
`Challenges in Hydraulic Fracturing
`
`
`
`Figure 2—Floppy latch-down wiper dart.
`
`With longer lateral sections drilled in horizontal
`wells for unconventional resources, more frac
`stages will be needed to optimize the fracturing
`design and increase production. The effectiveness
`of hydraulic fracturing is the key to both successful
`initial production and long life for the wells. Oper-
`ators report that not all perforated clusters in P-n-P
`treated wells are producing. One study shows that
`about a third of all perforated clusters do not con-
`tribute to production and also the uneven stimulation indicates uncontrolled frac dimensions (Miller et al.
`2011).
`The industry has realized the efficiency and economic advantages of using frac sleeves, but conven-
`tional ball drop frac sleeves have graduated ball seats that limit the number of frac stages and add
`treatment pressure drops through them during operations. This will require an increase in surface pumping
`pressure to achieve planned fracturing rates. In addition, the milling-out of ball seats may be required to
`remove flow restrictions and achieve higher production rates (Wozniak, 2010). In terms of hydraulic
`fracturing, OHMS has less control over frac initiation points, frac length and frac placement. Also,
`completion tools like hydraulic set OH packers and even the liner itself may induce stress and create frac
`initiation points (Daneshy, 201 i). In some cases, reservoir conditions may dictate a cemented completion,
`because packers cannot withstand the high temperature or suitably sized OH packers are not available.
`To take full advantage of sleeves for longer frac and more control over where fracturing initiates, one
`of the most significant innovations of the cemented completion may be the opportunity to use cemented
`frac sleeves activated with balls or CT. Some studies have shown that production comparisons between
`P-n-P and cemented sleeve completions show little difference. Also, using microseismic mapping and oil
`soluble tracers together, the single entry point provided by the sleeve option did not hamper production
`when compared to the multiple entry points of the P-n-P approach (Stegent et al. 2013; Adcok et al. 2013
`and Bozeman et al. 2009). However, the cemented conventional ball—drop frac sleeves have graduated ball
`seats and result in limitation of the number of frac stages. Efficient cement displacement is Vital in the
`tapered string of a ball drop sleeve completion and a long multi—finned floppy latch down wiper dart in
`Figure 2 is often used and can pass through a ball seat ID of 2.063” based upon the lab testing.
`By comparing the advantages and disadvantages between P—n-P and conventional ball drop frac
`sleeves, the improvements that are needed to enhance current the results from multistage frac systems are
`as follows:
`
`o No limitation in the number of frac stages for OH or cemented sleeve application.
`0 Lower surface pressure to minimize HHP needs.
`0 Monobore completion to reduce pressure losses.
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`4
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`SPE-171183-MS
`
`5 Count Bane Unlt
`
`Inner sleeva
`
`Ball Catcher
`
`Rotary Cage
`
`
`
`Figure 3—Main items of this new frac sleeve.
`
`0 Elimination of intervention requirements.
`0 Reduction of equipment, manpower, traffic and time on location to enhance HSE considerations.
`0 Reduction of overall costs.
`
`New Frac Sleeve introduction
`
`To address the limitations of the conventional graduated-seat multistage frac system, an unlimited and
`intervention-less multistage ball-activated fracturing system has been developed which provides a viable
`alternative to both the P-n-P and conventional ball-drop frac sleeves. This new sleeve is a ball-activated
`frac sleeve with single size balls and ball seats for all stages, which allows an essentially unlimited number
`of frac stages and is the only single size ball intervention-less frac sleeve system currently available for
`OH and cemented fracturing completion.
`
`Operational mechanism
`
`To explain how this new sleeve works, the sleeve with 5 count base unit is chosen as an example in Figure
`3. The main items of this new frac system include: 1) The Top Sub, 2) The 5 Count Base Unit, or with
`Extension Count Subs, 3) The Rotary Cage, 4) The Inner Sleeve, 5) The Coil Spring, 6) The Ball Catcher,
`and 7) The Bottom Sub. To achieve unlimited fracturing multistages, this new frac sleeve has three (3)
`distinct sections: 1) The Rotary Cage pre-positioned in a sub with a series of recesses, 2) The Inner Sleeve
`and 3) The Ball Catcher to isolate the lower stimulated zone.
`To illustrate the operational mechanism, this new frac sleeve with the 5 Count Base Unit and the Rotary
`Cage pre-positioned in 5 count position (the uppermost recess) is chosen to describe how this system
`works. When the four balls separately advance to the Rotary Cage and move it along a series of recesses,
`these balls are counted before continuing downhole to next sleeve. Since the Ball Catcher is not seated
`yet, 4 (four) balls can pass through the sleeve. Finally, when the Ball 5 advances the Rotary Cage, it will
`push it to shift open the Inner Sleeve to overcome shear value of shear pins. When the Inner Sleeve slides
`open, it simultaneously activates the Ball Catcher to form a ball seat so that the ball is caught on the seat
`to isolate lower zone, and the zone is ready for frac stimulation (Yuan et al. 2013). Figure 4 shows an
`overview of how the ball pushes and passes the Rotary Cage which shifts open the Inner Sleeve and
`simultaneously activates the Ball Catcher to form the ball seat Based on the number of frac stages,
`Extension Count Subs can be added right below the Top Sub to suit clients’ needs.
`
`Benefits versus current frac completion methods
`This new frac sleeve behaves in similar fashion to the graduated ball seat frac sleeve in that it is activated
`by dropping a ball for each zone, but it has a unique design which can make single size balls pass through
`all retractable ball seats thus precluding the need for a seat milling-out operation. The retractable ball seat
`also comes in handy in the event of screen-out, because pulsing the well allows the ball seat and ball to
`retract, the ball can then fall through the seat and the sand washes away and the operation can continue.
`While conventional graduated—seat designs require different-sized balls and seats for each separate zone,
`this new ball-drop system is different, using a single ball size throughout the entire well enables
`stimulation of a virtually unlimited number of zones. In addition, because there aren’t ball seats to mill
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`5 F
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`m :loovu chm: open, ball In! In fut-mod, and ball lands on soul-outing loworlnurval.
`
`SPE-171183-MS
`
`
`
`3‘“ flow. ofiun and back to surface.
`
`Figure 4——An overview of operational mechanism for the new frac sleeve.
`
`out, time-consuming interventions can be eliminated reducing the number of people and the amount of
`equipment needed on site to allow the job to be done faster and more efficiently.
`There are plenty of benefits to using one ball size throughout the well:
`
`No risk of sending the wrong-sized ball downhole and actuating sleeves out of sequence
`No more need for costly and planned milling operations
`No risk of prematurely actuating ball seats due to stimulation pressure
`A near-monobore completion from top to bottom, which minimizes downhole pressure drops
`Improved flow efficiencies, so less topside horsepower is needed to maintain an effective
`stimulation
`
`Compared to other methods of multistage stimulation, this new sleeve delivers significant savings
`potential. For instance, at 40 stimulated zones (the limit of graduated-seat sleeves), this new sleeve is very
`cost competitive with technologies that take longer and require costly intervention, etc. Compared to a
`P-n-P operation with a toe sleeve, the total well cost of this cemented new sleeve is at least 18% lower
`(Yuan et a1. 2013).
`Using the same horsepower to stimulate from toe to heel, graduated-ball sleeves are far less efficient
`at the toe. This new sleeve, however, provides a uniform bore and delivers a much more effective
`stimulation as pressure and friction loss are dictated solely by lateral length, not by ball-seat restrictions.
`Used in an OH application, this new sleeve is the most efficient multistage stimulation option available,
`and compared to a P-n-P system with TCP, the new sleeve reduces onsite-services requirements by as
`much as 66 %.
`
`Advantages versus sleeve systems with graduated ball seats:
`
`Advantages versus plug-and-perf systems:
`
`Eliminates milling
`Reduces time on site
`Accelerates operations
`Reduces water usage up to 30 percent
`Reduces logistical activities
`Reduces the number of onsite personnel
`Decreases overall capital expenditures and operational cost
`
`III'IC.
`
`
`
`Eliminates milling of ball seats
`Increases the number of production zones
`Decreases horsepower requirements
`Enables screen-out recovery with no need for intervention
`Eliminates risk of pressure-actuating ball seats
`Reduces surface equipment and site size
`Reduces the number of onsite personnel
`Reduces logistical activities
`
`
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`6
`
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`SPE-171183—MS
`
`
`
`Figure S—Well location of Case 1 study.
`
`this new frac sleeve can be cemented in place more easily than traditional
`More importantly,
`graduated—seat frac sleeves. For instance in a situation where bottom hole temperatures are too high for
`OH packers, the new system eliminates major restrictions in the completion string. The minimum ID of
`this new frac sleeve, which is as close as possible to the host tubing ID, eliminates the need for milling-out
`ball seats and makes cementing applications much easier. This approach also negates the need for OH
`packers for zonal isolations, thereby reducing the complexity and cost of the completion.
`Milestone events
`
`Around May of 2012, field trials of the 4.5" new ball-drop sleeve technology were started in North
`Dakota’s Bakken shale and then commercialized at the end of 2012. In total around 970 of these new
`sleeves have been run in which 75% of sleeves are OH application, 25 % are cemented sleeve as of May,
`2014. To date, the maximum number of stages run is forty-five (45) with this new 4.5” cemented sleeve
`application in which all sleeves were operated using 3.31” balls and kept at 3.5” full-bore ID post-frac.
`Since 2014, dissolvable balls are available for this unique sleeve with 10, 000 psi differential pressure
`rating; and its application eliminates the possibility of the frac ball being stuck downhole thus impeding
`production.
`
`Case Studies
`
`There are three (3) case studies from wells in major US shale or tight-gas sandstone formations. Case 1
`is OHMS application and both Cases 2 and 3 are new sleeve cemented application. Case 3 will show some
`operational issues such as screen-out and how those issues have been solved and interpreted.
`
`Case Study No. 1- 0H application
`The well was drilled horizontally to 16, 846 ft in measured depth (MD) with true vertical depth (TVD)
`of 7, 510ft) in Permian basin in New Mexico (Figure 5). 4—1/2” liner with this new sleeves and OH packers
`was run in OH with a total of 28 stages (27 new sleeves+ toe sleeve) isolated with open hole packers with
`325 ft of an average interval length. All 28 zones were individually treated at 50bbl/min and injection rate
`of 200, 0001bs of proppant per stage in 8.44 ppg fresh water with maximum treating pressure of 7, 500psi.
`This new sleeve with OHMS application has the design ability to present positive opening signature
`at surface pressure indication which provides the peace of mind that the stimulation is reaching the right
`part of the reservoir. Frac chart in Figure 6 shows typical positive opening signature of what should be
`presented while opening this sleeve.
`In this case, all 28 stages were successfully treated in an average time of one hour per zone — this
`compares to a typical 4 hours per zone using P-n-P methods. Each ball was displaced at frac rate of 20
`bbl/min towards the desired sleeve. Once it arrived at the sleeve it did not have enough momentum to open
`the sleeve and fluid bypassed the ball. This created approximately 100 psi pressure increase due to
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`SPE—171183-MS 7
`
`Mum N0!
`
`1:91!!! ' "."_"_‘_'.‘..";"..
`
`spun nape-mu WM:
`
`1
`
`Figure 6—Typical sleeve opening signature with positive indication.
`
`restricting the flow. At this point, pumping rate was increased creating sufficient differential pressure
`across the ball, giving it enough force to open the sleeve. Once the sleeve is open, the ball drops to the
`newly formed seat and creates a seal, pressure will spike as the fluid was trapped inside the pressure
`indication ring. Once the pressure differential across the pressure indication ring was high enough, the ring
`burst allowing a communication path into the desired open hole zone and the pressure dropped back off.
`At this point, stimulation of this zone can commence.
`Due to the nature of this new sleeve setting sequence being dependent on flow, opening signatures are
`not always present; so other indicators that the sleeve has been opened must be recognizable. Under some
`wellbore conditions, the surface indication will not be as expected regardless of the sleeve technologies
`used. These scenarios are as follows:
`
`1. Higher than Expected Surface Indication
`
`0 Charged zone below
`
`J If the zone below the sleeve is charged with pressure, the sleeve will have to overcome the
`pressure from below in addition to the shear rating on the sleeve.
`J This will result in a shifting pressure greater than the shear rating on the sleeve.
`
`2. Lower than Expected Surface Indication
`
`0 Long laterals below the sleeve
`
`J The large volume below the sleeve could act as an accumulator and dampen the indication at
`surface.
`
`0 High gas content in the stimulation fluid
`
`J As the gas content of the fluid increases, so does its compressibility. Compressible fluid will
`attenuate the indication at surface.
`
`0 Pressure on the outside of the sleeve
`
`J Any pressure present on the outside of the sleeve will have to be overcome to start the
`treatment. This could dampen the pressure signature read at surface.
`
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`8
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`SPE-171183-MS
`
` South Texas’ stacked all and gas plays
`
`The Eagle Foyd shalt-21's nestled among vmioos geologic layms. many at which also are otoducing oilend gas. Here's
`a look at how the various piays stack on top of each other
`Diagram Is tot lllunrauv: pmpmes and Is not complete or to scale. man the complexlw a! [napping geologIc
`lath across dlflmnt parts at me state. But It gives a general Man of the shallows: and deeper have"; across the
`
`
`
`
`
`
`/ “WWW
`FORMATIONS MORE
`
`
`
`.— l
`- *anlflne
`
`r 1",—
`
`__,.__—r AM — limestone
`
`__.~—-— Awfln -— rnalk
`z...- mm - shale
`
`
`
`
`_ H'H- Edwards -A llmsmne
`
`'—— MRO“ —1a’me5’tone
`-—_'_-_.JL-—._.__
`“‘ PM—shaleflmestone
`-- - —
`
`
`
`
`.. u
`___
`
`-,__-_ . —F
`- East: Ford
`‘ Sham play
`
`
`
`» None are considered
`» Like the Eagle Ford. the
`» Depthsvary across
`D Formations may be
`
`all formattons
`
`as large or as lucrative
`formations may produce
`Iora or less prevalent
`n different areas
`as the Eagle Ford Shale.
`ml or gas in dllferent areas.
`
`
`
`
`
`-_;._-‘_n-..
`
`|.-.-..,«n1r, n} rum ['kdnyylj! Ernnnma {in-mm“
`
`.m-uar.‘n (w .‘alrlnrtH mmw
`
`my.“ I Izhali".:1r\ Arlfrjaur} I. mun-an. dwar—
`
`Figure 7—Esc0ndido formation above Eagle Ford.
`
`Case Study No. 2 — Cemented application
`
`The well was drilled horizontally to 11, 336 ft in MD with TVD of 6, 166 ft in Escondido formation in
`Figure 7 which is dry tight gas sandstone formation and shallower than Eagle Ford formation, and was
`exploited before Eagle Ford was discovered. A 4-1/2” liner with 32 stages (31 new sleeves + toe sleeve)
`was cemented in 6 % ” lateral section and tied back 4.5” tubing to surface. The average zonal length was
`150 ft.
`
`The well was treated at rate of 20bbl/min. with a maximum pressure of 6, 000 psi during proppant
`treatment and at higher rates when needed to activate the sleeves. The stimulation was pumped with linear
`gel and the proppant with X—linked gel with total proppant of 120, 000 lbs per stage. Treating fluid as per
`the schedule in Table 1 has been pumped from Stages 2 through 32. All 32 stages were successfully
`treated in a total of 48 hours with continuous operating time. Figure 8 illustrates a typical sleeve opening
`and treatment for this cemented sleeves system.
`
`Case Study No. 3
`The well was drilled horizontally to 14, 420 ft in MD with TVD of 7, 829 ft in Three Forks Shale play
`located in the Williston Basin. A 4-1/2” liner with 46 stages (45 new sleeves + toe sleeve) was cemented
`in 6 ” lateral section and tied back 4.5” to surface. The average zonal length was 133 ft. Main completion
`information was summarized in Figure 9. Frac fluid system consists of 10# linear CMHPG, 20# linear
`CMHPG and 20# Zirc cross-link for each stage. Table 2 shows treating fluid information as per the
`schedule in detail.
`
`Due to the screen-out issues, this well’s frac operation included two separated series of frac jobs: one
`is from Stages 1-19 at frac rate of 25 bpm per stage and the other Stages from 20-46 at frac rate of 40 bpm
`per stage. All two screen-outs occurred in first series frac job from Stages 1-19. Figure 10 illustrates the
`operation performed and two screen-outs experienced in the first frac operation. The first 12 stages were
`treated without incident, but a screen-out occurred on the Stage 13 which was cleared by flowback and
`pulsing the well causing the ball to drop and relieving the screen-out so that operations could continue,
`but Stage 19 again resulted in a screen-out which was unable to clear. Operations were shut down in order
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`SPE-171183-MS
`
`
`9
`
`Table 1—Schedule of fracturing fluid from Stages 2 through 32.
`
`Time,
`
`-_-__
`
`Sand SizeVoI._|
`lbs
`a -
`
`_
`
` Ami/ate Slag/2|
`;
`
`mmm MI
`
`I'm;
`
`r. 4800
`
`MK)
`MD“
`540’)
`$200
`
`mu
`«m
`no.)
`«no
`3m
`3500
`
`w‘1 a::IE:3on 5.9:nm2'. o2
`
`I
`
`i
`
`—
`
`.
`
`__
`
`_
`
`e
`
`' "
`
`\
`
`'—
`
`.
`
`.
`
`4-
`
`arr-v
`
`'
`
`_ ‘J‘fi—"H‘
`
`-—
`
`'
`
`'
`
`/___/—'
`
`I
`
`“X...~__
`
`533 1!-
`
`8:34:53
`
`8:36.11;
`Treatment Time, hints
`
`2; we
`
`a 191)
`
`§§§
`um
`Jnm
`.
`.
`Moo
`2000W
`7x»
`1m
`1m
`w»2200
`mo
`831m
`
`Pressure,psi
`
`
`
`
`
`
`
`PumpingRate,bpm
`
`If}
`
`aa
`
`m
`
`)0
`
`Figure 8—Typical sleeve opening signature and treatment chart.
`
`to bring in a special tubing string of 2—1/16” with a 2.5” mill and motor on bottom to clear the screen-out
`and make the well ready for continued operation. Figure 1 1 indicates typical sleeve opening signature and
`treatment chart for this case.
`During the delay period discussions with reviews led to the decision that the fracture operation would
`be carried out by a different frac company pumping the same fluid and proppant design as the previous
`19 zones but with higher pumping rate at 40 bpm instead of 20 bpm. The remaining 25 zones were
`successfully treated without any further incident.
`
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`10
`
`SPE-171183-MS
`
`
`Fm:
`’ hm
`
`2-3i
`
`
`
`
`
`
`
`
`
`is"::5:2:2.x:2:332tn:3.22:“),
`
`
`
`'1'r.2:1:mm-
`
`
`
` s7mmmgmw
`
`6 W0 {3 7329'
`7 KOP @ 7314'
`nNmmERNSMESWWAHE
`MCI: STHIHG
`
`
`
`
`
`':2..15-.».I.-5u
`
`
`
`
`
`u
`
`
`
`
`
`1 FM SLEEVEBIH-Jfi
`2 45'5IlUE @1436“?
`
`3 CEMENTED LINER
`NORTHERN STATES HANGER,
`PACKER. 5 PER SLEEVE
`
`Figure 9—C0mpletion diagram for 46 cemented new sleeve system.
`
`Table 2—Schedule of fracturing fluid system from Stages 2 through 46.
`
`
`
`
` mmwmmAwN—L
`
`
`20#ZirXL
`1
`
`2mm
`
`20#ZirXL
`20#ZirXL
`10#CMHPG
`10#CMHPG
`
`10#CMHP
`
`Screen-out Discussion
`
`Among tens of thousands hydraulic fracture operations, although a lot of work has been done to‘optimize
`the fracture design and improve the operation execution performance to reduce the screen-out possibility,
`screen-out still occurs. There are many factors that can affect risk of screen-out such as completion type,
`formation characteristics, fluid and proppant system, perforation strategies and conductivity requirements,
`etc. However, the relationship between rate, Viscosity and proppant is an important one to understand.
`Also, tortuosity is a key aspect that needs to be included as one of the major reason that screen-outs occur,
`in addition to non-optimal design and poor onsite execution. There is a random tortuosity effect that
`occurs depending on the reservoir rock and fluid Viscosity at the perfs/ports at the time of breakdown. The
`
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`15% _
`10#CMHPG
`10#CMHPG
`2011mm;
`
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`

`

`SPE-171183-MS
`
`11
`
`Screen-outon Stag‘e13but
`was recovered.
`‘
`
`Screen-omen Stage 19
`cannot be eliminated.
`
`
`
`.11 2‘11": 111 mull ill;11
`
`Figure 10—Screen-out occurred in first part of operation from Stages 1-19.
`
`
`
`(Hum/gal:
`w~~“—|53¢h(im ("one
`Main Um: (7011::(lhm/gul)
`-
`[um 41
`lmnmiimi (ilmi gal)
`
`lilumlw‘ Run: nth-1r. ) (Isl-Jul
`
`w
`
`~v- WI mutiny. l’t'cmum (pen
`Backside 1%“:me was
`
`8m
`
`
`
`Prnssur‘1pm{Ra-II(bpm)
`
`Formallon Breakdown
`
`.
`
`b...to»
`
`u9
`
`Mt:
`(i
`i? 9
`
`‘.
`
`Rate&Concentration
`
`
`
`Pressure(psi)
`
`
`
`
`34“
`
`Time (min)
`
`Figure 11—Typical sleeve opening signature and treatment chart.
`
`more erosion, particularly at low concentrations and at higher downhole rates, the more the tortuosity is
`eroded away to minimize screen-out.
`Screen-out can lead to the added expense of clean out with CT which presents little problem in the
`P-n—P or this new sleeve system; however, in sleeves with graduated ball seats it can be a major issue if
`screen-out occurs near the toe of the completion where the smaller seat sizes are placed. The small
`opening which exists can make it difficult, if not impossible, to access the problem depth with CT to wash
`out
`the accumulated proppant. In these circumstances if flowback does not fix the problem,
`then
`perforating above the screen- out in order to access the upper stages is a possibility. Otherwise the only
`option may be to mill out the completion and tailor a custom completion suited to the well condition. If
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`12
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`SPE-171183-MS
`
`screen-out occurs in this new sleeve system, the probability of recovery without intervention is signifi*
`cantly higher than with traditional graduated ball seat sleeves. Pulsing of the well will very often relieve
`the screen-out because it will lead to the ball and seat releasing, allowing proppant to drop lower in the
`well as in the above case study.
`In the event this does not happen, the constant fiJll ID of this new sleeve system allows for relatively
`easy fixing of the problem by clean-out with CT or coupled pipe, no matter at what level the screen-out
`occurs.
`'
`
`Summary
`
`Use of this new sleeve provides a proven means of performing unlimited stage fracturing operations with
`cemented sleeves and offers a unique approach to the future direction of shale/tight gas extraction
`potential. Though this sleeve can be used in open hole applications, the cemented approach provides for
`longer fractures and more control over where each fracture initiates and represents a major innovation in
`fracturing technology. Following is a summary of the features and advantages of this new frac sleeve:
`
`0 Provides for an essentially unlimited number of zones to be stimulated with thru ID as close as
`possible to the host tubular string for OH and cemented application.
`Single ball size ensures that no ball seats need to be drilled up.
`Large ID reduces friction through the sleeve providing greater stimulation efficiencies.
`Presents major efficiency and cost advantages over P-n-P and conventional sleeve methods.
`Monobore feature reduces HHP requirements and improves operational efficiency by use of
`smaller stimulation fleet.
`
`o Eliminates the need for post frac milling of ball seats, since they disappear post stimulation,
`increasing production while reducing rig time and associated costs.
`0 Screen-out recovery could be conducted with no need for intervention.
`0 HSE improvement with less equipment, manpower, traffic and time on location.
`
`Acknowledgements
`The authors would like to thank Weatherford management for the permission to present and publish this
`paper and also special thanks for John Tough, Michael Cast and George Van Hoosier with data support.
`
`Nomenclatures
`
`BP
`BPM
`
`CT
`HHP
`HSE
`ID
`
`MD
`OH
`OHMS
`P-n-P
`PPG
`
`TCP
`TD
`TVD
`WL
`
`Bridge Plug
`Barrel Per Minute
`
`Coiled Tubing
`Hydraulic Horsepower
`Health, Safety and Environment
`Inside Diameter
`
`Measured Depth
`Open Hole
`Open Hole Multi-stage
`Plug and Perforate
`Pounds Per Gallon
`
`Tubing Conveyed Perforating
`Total Depth
`True Vertical Depth
`Wireline
`
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`
`References
`1. Adcok, G., Wellhoefer, B., Daher, S. and Fruge, E. 2013. Cemented Multi-Stage Sleeve Com-
`pletion Improves Efficiency of Fracture-Stimulation in an Eagle Ford Shale Well. Paper SPE
`163842 presented at the SPE Hydraulic Fracturing Technology Conference held in the Wood-
`lands, Texas, USA, 4-6 February.
`Bozeman, T., and Degner, D. 2009. Cemented Ball—Activated Sliding Sleeves Improve Well
`Economics and Efficiency. Paper SPE 124120 presented at the SPE Annual Technical Conference
`and Exhibition held in New Orleans, Louisiana, USA 4-7 October.
`. Daneshy, A. 2011. Hydraulic Fracturing of Horizontal Wells: Issues and Insights. Paper SPE
`140134 presented at SPE Hydraulic Fractur