A Unique Method for
`Perforating, Fracturing, and
`Completing Horizontal Wells
`
`A.P. Damgaard, SPE, Maersk Energy Inc., and D.S. Bangort, SPE, D.J. Murray, R.P. Rubbo,
`SPE, and O.W. Stout,* SPE, Baker Oil Tools
`SPE 19282
`Summary. This paper describes the evolution, laboratory testing, and field installation of a completion system developed to per-
`forate, fracture stimulate, and isolate multiple zones in North Sea horizontal wells. This system is designed to reduce overall completion
`time and well control problems significantly and to allow selective zone control in production and restimulation phases. The field per-
`formance of this system is compared with that of previously used methods.
`
`Background
`Maersk Oil & Gas A/S began drilling horizontal wells in the Dan
`field in 1987 with the primary goal of improving productivity in
`the low-permeability chalk. A feasibility study concluded that a
`matrix-acidized horizontal well would yield a productivity equal
`to or slightly better than that of a successfully propped, hydrauli-
`cally fractured conventional well, albeit at a higher cost.1 There-
`fore, to make horizontal wells economically attractive, fracture
`stimulating multiple zones in the drainhole section would be nec-
`essary. Before the use of this new technique, three Dan field horizon-
`tal wells—Wells MFB-14, MFB-15, and MFB-13—were completed
`with multiple fracture stimulation treatments. Production experi-
`ence from these three horizontal wells confirmed that production
`increases by a factor of three to four over that of a conventional
`well. Thus, the decision was made that further field development
`would be based mainly on multiple fractured stimulated horizontal
`wells.
`
`Completion Experience With Existing Horizontal Wells. Suc-
`cessful liner installation and cementation is considered a prerequi-
`site to ensure adequate zonal isolation for multiple fracture
`treatments in horizontal wells. The radius of curvature for both the
`short- and medium-radius methods (33 to 50 ft and 300 ft, respec-
`tively) would make successful liner cementation difficult. For this
`reason, the long-radius directional drilling method was considered
`to be the most attractive option.
`Although the first horizontal well (Well MFB-14) was equipped
`with a 51/-in. liner across the reservoir, 7-in. liners have been in-
`stalled in subsequent wells to allow more flexibility in the selec-
`tion of perforating and stimulation tools.
`Because an initial concern was that the annular area between the
`7-in. liner and the 81/2-in.-diameter hole would be insufficient for
`a good cementation job, 63/4-in. liners were considered as an op-
`tion. A Cement Evaluation Toolsm , Variable Density Log sm , and
`gamma ray and casing-collar locator logs run in all Dan field
`horizontal wells indicated that zonal isolation had been achieved
`with the 7-in. liners that had been well centralized and rotated dur-
`ing cementation. This was confirmed during execution of fractur-
`ing jobs where no communication between individual fractures was
`observed.
`
`Previous Perforating/Sdmulating Techniques. The following ab-
`breviated history of completion systems used in previous Dan
`horizontal wells corroborates the need for an improved comple-
`tion system for multiple stimulated horizontal wells.
`Well MFB-14 was perforated and stimulated with the following
`procedure (see Fig. 1).
`1. The zone was perforated and stimulated with a conventional
`drillstem test string.
`2. After the well was killed with brine and losses were cured with
`lost-circulation materials, a bridge plug was set above the zone.
`•Now at The Western Co.
`CoPYtIght 1902 Society of Petroleum Engineers
`
`SPE Production Engineering, February 1992
`
`3. The next zone was perforated, stimulated, and tested.
`4. After the well was killed, the bridge plug was milled and
`pushed to bottom, and a new bridge plug was installed above the
`latest set of perforations, after which a new zone could be perfo-
`rated and stimulated.
`This procedure required three trips to stimulate one zone. This,
`together with problems with curing losses and gains experienced
`when the bridge plugs were milled and pushed to bottom, resulted
`in an excessive total stimulation time.
`To reduce time during the perforating and stimulating operations,
`a straddle packer assembly (Fig. 2) was used successfully on the
`second horizontal well, Well MFB-15. This well was stimulated
`with acid without proppant. To maintain well control during trip-
`ping, it was necessary to flow each zone after the stimulation be-
`cause of the 300- to 400-psi supercharging from the stimulation
`fluids.
`A new packer assembly was designed for stimulation of Well
`MFB-13. The objective of the new design was to enable isolation
`of the fractured zone immediately after stimulation to prevent the
`gain/loss situation experienced in Well MFB-15. This would be
`achieved by placing the retrievable bridge plug above the last treated
`interval while picking up a new tubing-conveyed perforating (TCP)
`assembly. Fig. 3 shows this tool string. Two different bridge plugs,
`one inflatable and the other mechanical, were used, with some oper-
`ational problems.
`
`Dovolopmont of Method
`Cost and Performance Objectives. Drilling and completion of
`Welts MFB-14, MFB-15, and MFB-13 were finalized in mid-1988.
`An operations review showed that the scope for significantly im-
`proving drilling time was limited, but there was a potential for sig-
`nificantly reducing completion time and associated costs. Therefore,
`the decision was made to design completion tools/techniques for
`horizontal wells with the following objectives: (1) to reduce stimu-
`lation and completion time for both acid fracturing and propped
`hydraulic fracturing; (2) to reduce or eliminate losses of expensive
`completion fluids and thereby improve well control during com-
`pletion operations; (3) to allow selective restimulation of the in-
`dividual zones without a drilling rig or workover hoist; and (4) to
`permit isolation of or to shut off zones producing excessive amounts
`of gas.
`
`Completion System Development. With a thorough understand-
`ing of the desired completion system characteristics, the designers
`conceived numerous alternatives, ranging from modifications of ex-
`isting techniques to novel methods that would require extensive de-
`velopment. Four of the most viable alternatives were developed
`to a degree sufficient to project the performances and characteris-
`tics of the systems. For each concept, a proposed completion pro-
`gram was generated that described each required operational step
`in sequential order. A performance matrix comparing the relative
`merits and disadvantages of each system was also produced. Fi-
`nally, an economic analysis covering total projected costs for each
`
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`O
`
`BRIDGE PLUG,
`MILLED AND
`PUSHED TO
`BOTTOM
`
`WORKING
`STRING
`
`PERFORATED
`JOINT
`
`
`
`1,
`RODUCT1ON
`LINER
`
`AAA
`
`TCP
`N
`
`A
`
`N
`
`\--- SAND FILLED
`FRACTURES
`
`50x SW
`
`PLANNED PERFORATING
`INTERVAL
`
`PACK ER
`
`BRIDGE
`
`Fig. 1—Stimulation with millable bridge plugs.
`
`\\\\9 ii/r cam
`
`TOP CHALK
`
`WORKING
`
`STRADDLE
`PACKER
`
`PRODUCTION
`LINER
`
`AAA
`
`50% SW
`
`PLANNED PERFORATING
`INTERVAL
`
`CIRCULATION
`VALVE
`
`TCP
`GUN
`
`FRACTURES
`
`A
`sun-
`
`L CM
`MATERIAL
`PLUG
`
`Fig. 2—Stimulation with straddle packer.
`
`option was conducted. This analysis included, but was not limited
`to, hardware procurement, expense of performing each operation,
`and potential cost of fluid losses. The analysis indicated that the
`option selected addressed each performance objective, offered to-
`tal cost advantages, and was based on proven technology. The op-
`tion selected was the perforate, stimulate, and isolate (PSI) system.
`
`PSI System Description
`The completion system selected for development was designed to
`permit each interval to be perforated, stimulated, and isolated in
`a single workstring trip. This system consists of three basic assem-
`blies: a permanent sump packer with bull-plugged bottom (Fg. 4),
`a downhole assembly for isolating each interval after treating and
`permitting selective production or stimulation (Mg. 5), and a serv-
`ice assembly for perforating and stimulation operations (Fig. 6).
`The downhole and service assemblies are made up with the 214 -
`in. concentric workstring and TCP gun assembly installed concen-
`trically inside the downhole assembly (see Fig. 7). These two com-
`ponents are run into the well simultaneously. Following perforation
`and stimulation operations, the downhole assembly is positioned
`and set in a manner to isolate the perforations; then the service as-
`sembly is retrieved from the wellbore.
`After all zones are isolated and the production tubing string is
`installed, a coiled-tubing-conveyed manipulation tool string is run
`in to open the sliding sleeves. The tool string can be run at any
`time in the future to close off any zone or to reopen a zone that
`was previously closed. The tool string includes a:backflow valve,
`an emergency release device, and a washing device to dean out
`the sliding sleeves before they are moved.
`
`62
`
`Downhole Assembly. The downhole assembly consists of three
`main parts (see Fig. 5). The first is a locator seal assembly used
`to provide pressure integrity between the sump packer and the down-
`hole assembly. The second component is a sliding sleeve used to
`provide selective production control. The third is a hydraulically
`set, retrievable isolation packer.
`A 41/4-in.-OD, 12.6-lbf/ft L-80 tubing with premium threads is
`made up between the seal assembly and the sliding sleeve. This
`section typically is 20 to 80 ft long.
`The sliding sleeve, which is run in the closed position, contains
`a sleeve valve that can be opened by shifting upward and closed
`by shifting downward with a coiled-tubing-conveyed manipulation
`tool string.
`An additional length of 41/4-in.-0D, 12.6 lbf/ft L-80 tubing with
`premium threads is made up between the sliding sleeve and the iso-
`lation packer. The length of this section is governed by interval
`spacing, but it typically ranges from 200 to 400 ft.
`The last component in the downhole assembly is a hydraulically
`set, retrievable isolation packer. This packer contains a sealbore
`that will accept seal assemblies. The isolation packer's setting piston
`is hydraulically balanced to prevent presetting. It cannot be set un-
`til the locator seal assembly has been stabbed into the sump packer.
`
`Service Assembly. The service assembly contains five main com-
`ponents (Fig. 6). The lowermost consists of 20-ft-long, 31/4- or 3 %-
`in.-OD TCP guns and firing head. The firing head is actuated by
`hydraulic pressure. After actuating, there is a time delay before
`detonation to permit underbalanced perforating if desired.
`The second component is a mechanism that automatically retracts
`the TCP guns and firing head to a position inside the downhole
`
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`\\\\9 5/B" CASING
`
`WORKING
`STRING
`
`PERFORATED
`JOINT
`
`TOP CHALK
`
`SOC
`
`PRODUCTION
`LINER
`a a
`
`TCP
`GUN k OVERSHOT
`
`FRACTURES
`
`50s SW
`
`PLANNED PERFORATING
`INTERVAL
`
`PACKER
`
`RETRIEVABLE
`
`BRIDGE
`PL
`UG
`
`Fig. 3—Stimulation with retrievable bridge plugs.
`
`CASINO
`T" O.D.
`
`Fig. 4—Setting sump packer.
`
`assembly after perforating. The TCP guns are retracted to allow
`full circulation and thus to avoid sticking problems should a prema-
`ture screenout occur during fracturing.
`The third component is a circulation device that allows fluid to
`flow from the workstring ID through the annular space around the
`perforating guns and into the lower casing annulus.
`A length of 236-in.-OD concentric workstring is used to separate
`the lower three service assembly components from the upper com-
`ponents. This workstring is also used to space the TCP guns, fir-
`ing head, and gun retractor so that the TCP guns are positioned
`below the seal assembly after the downhple and service assemblies
`are connected.
`The fourth component in the service assembly is the disconnect
`sub. It is used to make a pressure-tight, rotationally locked, me-
`chanical connection between the service assembly and the down-
`hole assembly. The upper end of the 2% -in. tubing is suspended
`from the disconnect sub. The two assemblies are disconnected with
`30,000 lbm tension.
`The fifth component is a mechanically operated stimulation packer
`whose design is based on standard compression-set squeeze tools.
`The conventional rotational control system used during setting and
`releasing operations was replaced by an automatic J-slot control
`system, which is operated with 21/2 ft of reciprocation. This pack-
`er is run immediately above the disconnect sub and is attached direct-
`ly to the workstring.
`
`Operational Procedures. The basic operational procedures used
`with this completion system are as follows.
`1. Run the bull-plugged sump packer on drffi- pipe and set it
`hydraulically at a point below the bottom interval (see Fig. 4). Pull
`the drillpipe and setting tool.
`2. Make up the downhole assembly and temporarily suspend it
`from the rotary table.
`
`SPE Production Engineering, February 1992
`
`TUBING
`
`LOCATOR
`SEAL MISSIZI
`
`pnatrixiornt norm Kroabr
`Fig. 5—Downhole assembly.
`
`3. With a gravel-pack screen-handling table (false rotary table),
`run the lower portion of the service assembly through the down-
`hole assembly ID. Run the service assembly until the disconnect
`sub can be made up into the top of the downhole assembly's isola-
`tion packer. The TCP guns will be spaced below the locator seal
`assembly at this time.
`4. Run the combined assemblies to perforating depth (see Fig.
`7) and set the stimulation packer by picking up 2 1/2 ft at the packer
`and then slacking off 10,000 lbm.
`5. Pressure the workstring to actuate the TCP guns. Guns will
`automatically retract after firing (see Fig. 8).
`6. Stimulate according to the program (Fig. 9).
`7. Pick up and release the stimulation packer. Establish reverse
`circulation and slack off to remove any proppant remaining inside
`the casing (Fig,. 10).
`8. Stab the seal assembly into the sump packer and pressure the
`workstring to 6,000 psi to set the isolation packer (see Fig. 11).
`9. Bleed the pressureand pick up the workstring 30,030 lbm over
`string weight to disconnect the service assembly from the down-
`hole assembly (Fig. 12). Retrieve the service assembly.
`
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`CIRCULATION
`OEM
`
`CrOrTnameL
`r
`
`SERVICE MCMINN
`DISCONNECT
`
`col-1 Luton
`lop
`RETRACTOR
`(=NM ecemon)
`Fig. 8—Service assembly.
`
`WORK SUNG
`
`Fig. 7—Running In hole.
`
`GU
`IWCTED)
`OKT
`
`SUN
`
`(RI OCTINKITRCASMON)
`
`Fig. 8—Perforated.
`
`Fig. 9—Stimulating.
`
`10. Repeat Steps 2 through 9 until all intervals have been perfo-
`rated, stimulated, and isolated by stacking the required number of
`downhole assemblies on top of one another.
`11. Make up and run production tubing and completion equip-
`ment as required. Land the production-tubing seal assembly in the
`sealbore of the uppermost isolation packer.
`12. Run and land the tubing banger. Make up the wellhead.
`Sliding-Sleeve Manipulation. The sliding sleeves are shifted open
`to commingle the stimulated zones with a shifting tool carried on
`coiled tubing. Before the sliding sleeves are shifted, a separate
`coiled-tubing run is made to wash out any debris that may have
`accumulated in the sliding-sleeve profiles during completion.
`1. Wash run. Run in the hole, maintaining circulation until just
`above the first sliding sleeve. Increase the pump rate to about 1
`bbl/min and continue down to bottom. Then pull out, continuing
`to wash until out of the horizontal section.
`
`2. Opening the sliding sleeves. Run down the vertical section of
`the well, maintaining sufficient pressure to allow circulation. Be-
`fore the horizontal section is reached, increase the pump rate to
`about 1 bbl/min and continue down to total depth (TD). Pull up
`to the first sliding sleeve until the shifting tool engages; then con-
`tinue pulling to open the sleeve. After a few seconds, the weight
`indicator will slowly drop off, indicating that the sliding sleeve is
`opening. Repeat this procedure at each sliding sleeve until all slid-
`ing sleeves are open.
`
`Summary of Component and System Tests. It is standard prac-
`tice to test new equipment thoroughly before introduction in the
`field. The first problem encountered during test preparation of the
`PSI system was that all the test facilities were designed for vertical
`completions. Simulation of horizontal well conditions required the
`fabrication of a 7-in.-casing horizontal test fixture with adequate
`
`64
`
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`NETINEWALE
`SE
`PACXERRIMEET)
`
`Fig. 10—Reversing.
`
`NETINEMVILE
`PACISMCCEUNSET)
`
`NETRIENPOLE
`COMPLETION
`tAgcER
`
`Fig. 11—Setting completion packer. .
`
`Fig. 12—Isolated with workstring removed.
`
`space around it for running tools in and out of the fixture. This
`particular fixture did not include a curved section to simulate a build
`angle because this completion was to have a maximum build of only
`6°/100 ft. The 7-in. test fixture was about 120 ft long. A hydraulic
`manipulator was made up to one end of the casing, with a test cap
`at the opposite end. The hydraulic manipulator was a long-stroke
`hydraulically actuated piston to provide back-and-forth motion of
`the components in the PSI system. The test cap and hydraulic
`manipulator allowed application of annulus or tubing pressure to
`simulate downhole conditions. The hydraulic manipulator also al-
`lowed simulation of the application of set-down weight or pickup
`tension from the rig floor.
`Component Tests.
`1. The service packer was set and released in the horizontal po-
`sition. An 8,000-psi pressure test at ambient temperature and 220°F
`was performed.
`2. The isolation packer was set, pressure tested to 7,500 psi at
`ambient temperature and 220°F, and retrieved.
`3. Swab-off tests to determine circulation limits were performed
`on both packers.
`4. The automatic gun retractor was actuated with 5,000-psi nitro-
`gen as the driving medium.
`Complete PSI System Tests With the Horizontal Test Fixture.
`1. Set bull-plugged sump packer on a hydraulic setting tool.
`2. Made up the entire assembly for one zone (see Fig. 7) with
`only one joint of 41/2-in. tubing.
`3. Set the service packer.
`4. Pressure tested to 5,000 psi from above.
`5; Simulated gun detonation and actuated gun retractor.
`6. Simulated screenout conditions against the service packer by
`pressuring tubing to 7,500 psi.
`
`SPE Production Engineering, February 1992
`
`7. Released service packer.
`8. Stroked hydraulic actuator in to land locator seal assembly in
`sump packer, which was set in the bottom of the test fixture.
`9. Pressure tested the upper annulus to 2,000 psi to verify seal
`integrity.
`10. Set the isolation packer.
`11. Pressure tested the isolation packer to 7,500 psi both above
`and below.
`12. Pulled disconnect sub from the isolation packer and removed
`the service assembly.
`13. Shifted the sliding sleeve open and then closed it.
`14. Released the isolation packer with the retrieving tool and
`pulled the isolation string from the fixture.
`As a result of these tests, the equipment was deemed ready for
`field runs in nonpropped stimulation applications.
`A sand-slurry fracture test of the equipment was also conducted
`to evaluate the suitability of the equipment in situations where prop-
`pant might be required. Tools were assembled and installed in the
`7-in.-casing horizontal test fixture. The slurry was circulated through
`the tools until a total of about 600,000 lbm of sand was pumped
`at a rate of 30 bbl/min through the test fixture. Fresh water was
`then circulated through the fixture to remove most of the sand. The
`equipment assembly was then pulled from the 7-in. casing. Exami-
`nation of the tools indicated that turbulence caused erosion around
`the holes and joints over which the slurry had passed.
`It was concluded that some special attention must be given to these
`areas before this system could be used to conduct sand fracturing
`operations in one trip per zone. Sand fracturing operations currently
`must be performed with the PSI system by perforating in one trip
`and running the service (less TCP assembly and gun retractor) and
`downhole assemblies in a second trip on drillpipe.
`
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`TUBING HANGER
`
`LOCATOR TUBING SEAL
`ASSEMBLY (TYP.)
`
`ISOLATION PACKER (TYP.)
`
`SLIDING SLEEVE (TYP.)
`ZONE 8
`
`O
`
`0
`
`ZONE 7
`
`O
`
`0
`
`ZONES
`
`O
`
`0
`
`ZONES
`
`SIDE POCKET MANDREL
`
`O
`
`0
`
`ZONE 4
`
`EXPANSION JOINT
`
`RETRIEVABLE SEAL
`BORE PACKER
`
`LINER HANGER
`
`O
`
`0
`
`ZONE 3
`
`ZONE 2
`
`ZONE I
`
`SUMP PACKER
`BULL PLUG
`
`Fig. 13—Horizontal-wall completion.
`
`Application Summary
`Installation Review. All completion equipment was function test-
`ed, made up in 30- to 40-ft-long subassemblies with tubing pup joints
`in each end for easy handling, and subsequently pressure tested to
`the required pressure. After the logs for Well MFA-13 were evalu-
`ated, plans were made to complete the well with eight zones, all
`to be acid fractured. Actual completion operations began by run-
`ning of the sump packer.
`The first makeup of the PSI system was time-consuming, requiring
`about 8.5 hours. Two initial attempts to run the PSI system on the
`nonrotational service packers were not successful because the as-
`sembly would not enter the top of the 7-in. liner from the 9%-in.
`casing. After the liner top was dressed, a different service packer
`was chosen and the procedure described below was followed.
`1. Run the PSI system in the hole on 31/2- and 5-in. drillpipe to
`perforating depth and set the service packer.
`2. Rig up the fracturing tree and lines.
`3. Test the string against the ball valve.
`4. Cycle the ball valve to the circulation position and displace
`the string to filtered seawater.
`
`66
`
`5. Cycle the ball to test position and pressure up to activate the
`TCP guns.
`6. Rig up the fracturing lines and stimulate the zone.
`7. Cycle the ball valve to the circulation position and reverse out
`seawater (displacement fluid).
`8. Rig down the fracturing tree. Rig up the drillpipe/circulating
`head and pressure test to 6,000 psi.
`9. Unset the service packer and engage seals into the previous
`isolation packer.
`10. Set the isolation packer by applying 6,000-psi surface
`pressure.
`11. Release the service packer from the downbole assembly and
`pull out of the hole.
`The installation of the first five zones was fairly uneventful ex-
`cept for a minor failure of the service packer and the ball valve.
`On the basis of increasing experience, the time between fracturing
`was continuously reduced and actual waiting time on the stimula-
`tion vessel resulted from haitor trips for chemical reloadings.
`A leak was observed during installation of the isolation packer
`for isolation of Zone 6. A pressure test of the =ulna indicated
`
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`I l I
`LEGEND
`TYPE 1- Tripping 'Time
`TYPE 2- Stimulating Tins
`
`TYPE S- Failure Time
`
`TYPE 4- WaitingTim•
`'
`
`TYPE 6- Other Tine
`
`TYPE 6- Find Completion Mom .
`TYPE 7- CoMd Tubing Time
`
`.
`.
`
`-
`
`-
`
`Time (Hours)
`I WU :
`
`900 : c'' \
`800 :
`\
`700:
`600 .
`
`!,1
`4
`,
`-
`500 :
`:4 '
`II
`400:
`
`i '
`'NI
`300 :
`N
`:
`200:
`• .
`'4
`:
`
`1 00 . :
` r
`V
`/0
`N
`442 N
`Si
`e.
`t4
`N
`%,_ 0 0
`laPICL
`• WITTim4L
`TY E 1 TYPE 2 TYPE 5 TYPE 4 TYPE 1 TYPE 6 TYPE 7
`P
`O.
`E
`922
`upsaj.zeisse
`
`,
`
`N
`
`273
`
`57
`
`0
`
`94
`
`311
`
`92
`
`0
`
`4
`
`MFB-13, 7-Zonse
`
`ng
`
`130
`
`111FA-13,11-Zonee
`
`egg
`
`17
`
`40
`
`43
`
`160
`
`121
`
`0
`
`23
`
`206
`
`50
`
`20
`
`61
`
`0
`se
`
`Fig. 14A—Completion-time comparison chart.
`
`>
`
`
`
`• MFB-15
`
`• MFB-13
`
`MFA-13
`
`0
`
`4
`
`6
`
`8
`
`10
`
`12
`
`14
`
`Brine Loss (BBLs x 1000)
`
`Fig. 1413—Fluid loss.
`
`frill packer integrity, indicating that the leak point was somewhere
`in the 41/2-in. isolation string, most likely in the seal assembly or
`the sliding sleeve.
`After the service assembly was released and retrieved, an un-
`successful attempt to release the isolation packer was made with
`the dedicating retrieving tool.
`During these operations, significant losses occurred and further
`attempts to retrieve the isolation assembly from Zone 6 were abort-
`ed. To cure the losses and allow perforation and stimulation of the
`two remaining zones, a short assembly consisting of an isolation
`packer, tubing, and a nipple profile with a blanking plug was in-
`stalled on top of the isolation assembly.
`Perforation and stimulation of the two zones were also fairly un-
`eventful except for one failure of the service packer during attempts
`to enter the 7-in. liner.
`
`Installation of the eighth isolation assembly was completed in a
`record time of 25.5 hours from the assembly makeup until the serv-
`ice packer was out of the hole.
`After installation of the final completion (Ng. 13), 11/2-in. coiled
`tubing was rigged up and the following runs were made.
`1. Ran in the hole to the top of the plug at Zone 6 and circulated
`clean.
`2. Ran in the hole with a pulling tool and retrieved the prong
`from the blanking plug.
`3. Ran in the hole with a pulling tool and attempted to retrieve
`the blanking plug. Pulled out of the hole without the plug.
`4. Ran in the hole and retrieved the plug.
`5. Ran the wash tool to TD and circulated clean.
`6. Ran the shifting tool for the sliding sleeve and began opening
`sleeves from the top down (Zone 8, 7, etc.). Unable to peas Zone 4.
`Pulled the shifting tool out and found it to be sheared.
`
`SPE Production Engineering, February 1992
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`7 of 9
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`RETRIEVABLE
`SERVICE
`PACKER
`
`SIDE MOUNTED
`GUNS WITH
`FIRING
`HEAD
`
`RETRIEVABLE
`COMPLETION
`PACKER
`
`LOCATOR
`TUBING
`SEAL
`ASSEMBLY
`
`BALL SEAT
`
`SLIDING SLEEVE
`
`Fig. 15—Parallel gun system.
`
`7. Ran a circulation nozzle to TD while circulating without any
`obstructions.
`8. Ran the sleeve-shifting tool with one extra shear pin installed.
`Observed increased drag forces from Zone 7 to 'ID, indicating some
`debris being pushed in front of the shifting tool. Shifted all sleeves
`from the bottom up (Zones 1, 2, etc.) with an observed overpull
`of 5,000 lbm at the surface to shift each sleeve. It was found that
`none of the sleeves was opened fully during the first opening run
`(Run 6). The sleeve-shifting tool came out unsheared, confirming
`that all sleeves had been opened.
`After eight coiled-tubing runs in 58 hours, the first well with the
`PSI system installed was ready to begin production.
`
`Performance of PSI System and Previous Systems. To compare
`the performance of the PSI system with that of previous systems,
`an actual completion/stimulation time analysis was constructed. The
`time spent for different operations is broken down into the follow-
`ing categories: Type 1—tripping time for successful trips; Type 2—
`stimulating time; Type 3—time spent as a result of equipment
`failures, including tripping time; Type 4—any type of waiting time;
`Type 5—other operations, such as packer setting, circulating, and
`curing losses; Type 6—final completion time; and Type 7—coiled-
`tubing operations. Figs. 14A and 14B show the time and fluid loss
`breakdown comparison for Wells MFB-15, MFB-13, and MFA-13.
`Additional time studies showed that the application of new
`methods reduced the average time spent per zone from 106 hours
`on Well MFB-15 and 78 hours on Well MFB-13 to 61 hours on
`Well MFA-13. Compared with Well MFB-13, use of the PSI sys-
`tem on Well MFA-13 reduced total completion time by 136 hours.
`Comparisons of the different types of operations show that time
`spent on tripping has increased as a result of the PSI system (130
`hours on Well MFB-13 and 177 hours on Well MFA-13). How-
`ever, a significant time saving on packer setting, circulation, and
`curing of losses has materialized. Time saving on equipment failure
`operations also materialized, despite the complicated nature of the
`PSI system.
`Use of the PSI system resulted in a significant brine saving from
`about 11,000 bbl on Wells MFB-15 and MFB-13 to about 3,300
`bbl on Well MFA-13. This is a direct saving of 7,700 bbl. Scaled
`for the number of zones, the saving is some 9,300 bbl of brine.
`At a cost of about $20 U.S./bbl, the total brine savings amounted
`to roughly $186,000.
`
`Conclusions
`During project evaluation, the perforating/stimulating time per zone
`was estimated to be 48 hours. When comparing this with the actu-
`al 61 hours spent per zone, one must conclude that the expected
`time saving did not materialize. However, the estimate of 48 hours
`was based on optimal performance; i.e., no allowance for equip-
`ment failures was made. If the actual time spent is corrected for
`equipment-failure-related time plus about 50% of the coiled-tubing
`
`68
`
`time (for plug retrieval), the time spent per zone comes to about
`43 hours, which compares well with the estimated time con-
`sumption.
`The brine consumption with the PSI system was estimated to be
`about 2,700 bbl for seven zones. The actual losses were 3,300 bbl;
`but for eight zones, which if scaled dotiin to seven zones comes
`to a consumption of 2,900 bbl. The estimated brine consumption
`was also based on optimal operation. The bulk of the actual con-
`sumption occurred during the time when Zone 6 was exposed to
`losses caused by a leak. Hence, it is considered that the estimated
`brine saving did materialize.
`The possibilities of restimulating selected zones individually and
`closing off zones producing at high water cut or GOR's are still
`to be tested; however, sliding sleeves have successfully been shift-
`ed in older wells in this field several years after installation. There-
`fore, we are confident that these options can be used when required
`later in the producing life of these wells.
`Further development of the PSI system is needed to achieve a
`one-trip system for sand operations. Sand erosion problems must
`be solved to increase tool life.
`Successful deployment of this horizontal-well completion system
`was the direct result of close collaboration between the operator
`and the service company. Both companies provided unique perspec-
`tives and complementary areas of expertise, which resulted in the
`development of this system in a very short period of time.
`
`1992 Updato
`Maersk Oil has successfully installed the PSI system in 14 horizontal
`wells since the field test of the system in the Dan Well MFA-13
`in 1989. In total, 126 zones have been completed with the PSI sys-
`tbm. The system has been deployed in conjunction with matrix-
`acidized, acid-fractured, and sand-propped fractured intervals.
`The average completion time per zone has been 85 hours, with
`a maximum of 110 hours and a minimum of 48 hours; hence, the
`originally estimated average time for completing a zone has never
`materialized. However, a significant saving in brine consumption
`has been achieved in all wells completed with the PSI system.
`The system has basically been used as originally designed, ex-
`cept for the retractable gun, which has never been field tested be-
`cause of erosional problems with the circulating sub and potential
`retrieval problems after firing and stimulating. The PSI system has
`consequently been run in two trips—one trip to perforate and a sec-
`ond to stimulate and isolate to complete matrix-acidized and sand-
`propped fractured intervals. This constraint in the current version
`of the PSI system has partially accounted for the additional com-
`pletion time spent in comparison with the initial estimates. A one-
`trip system, however, has been used in acid-fractured zones by use
`of a short 2%-in. TCP gun on the inner string extending out the
`end of the locator-tubing seal assembly.
`A parallel gun system (see Fig. 15) has also been developed to
`facilitate a one-trip system for sand operations. This system con-
`
`SPE Production Engineering, February 1992
`
`8 of 9
`
`Ex. 2079
`IPR2016-01514
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`

`Authors
`
`Damgaard
`
`Murray
`
`Stout
`
`Rubbo
`
`Anders Darnmeard
`Is the manager of
`Drilling Services of
`Maria Energy Inc.
`In Houston. Since
`joining Mast* Off &
`Gash Copenhagen
`In 1981, he has held
`various drilling and
`nobelium positions
`for North Sea ac-
`tivitles. Damgaard
`holds a BS degree
`In electronics from the Danish Engineering Academy. Dan
`Banged is director of Technical Services for Baker 011 Tools
`In Houston. During his 16-year tenure there, he has held posi-
`tions In research, U.S. and International operat