Copyright 2005, SPE/IADC Drilling Conference This paper was prepared for presentation at the SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 23-25 February 2005. This paper was selected for presentation by an SPE/IADC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the SPE, IADC, their officers, or members. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers or the International Association of Drilling Contractors 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 where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract The challenge with through tubing sidetrack completions has been dealing with small clearances and the lack of ready-made equipment. Over the last 10 years and 450 coiled tubing drilling sidetracks on Alaska’s North Slope a number of unique completion designs have been developed to maximize production and achieve vertical/zonal isolation. These completion techniques are now proven, and may make lower cost through tubing sidetracks more feasible for other mature fields. Introduction Low cost reservoir access is a key component to sustaining production from maturing fields. Coiled tubing drilling (CTD) and through tubing rotary drilling (TTRD) can achieve significant cost savings by sidetracking through existing production tubing. However, the critical completion phase of these sidetracks is challenged by small clearances and custom equipment. During the course of completing over 450 CTD sidetracks through 4 ½-in. and 3 ½-in. production tubing in Alaska, a number of innovative completion designs have been developed to maximize production, achieve zonal isolation, allow for selective multilateral production, and preserve the parent wellbore for additional sidetrack opportunities. This paper will detail specialized liner cementing equipment and techniques and provide design and operational guidelines for several proven through tubing completion options:

• Tapered 3 3/16-in. x 2 7/8-in. fully cemented liners. Placement of larger 3 3/16-in. liner in the upper build section permits future sidetracks (with 2 ¾-in. bit) to other undrained oil deposits.

• Insertion of a specialized sub in the liner provides flexibility for low cost selective multilateral

production or low cost patch isolation of upper oil lense perforations.

• Combined cemented and slotted liner “bonzai” completions save tubing conveyed perforating costs.

• Preserving parent wellbore production - Standing valves in inflatable bridge plugs or in whipstock anchor packers provide protection to existing perforations while drilling and allow production to be re-established. When the lateral liner has to be cemented, hollow whipstocks can be used to re-establish production from the parent wellbore.

• Aluminum kickoff billet at top of liner provides 100% lining of wishbone multi-laterals.

• Work is progressing with expandable screens and solid liners to address unconsolidated sands and wellbore instability.

Continuous innovation and close collaboration with the service industry has yielded successful solutions for challenging through tubing completions. These proven techniques have positioned CTD as the preferred method for re-entry sidetracks on Alaska’s North Slope (figure 1). The completion options discussed in this paper may make low cost through tubing sidetracks more feasible for other mature fields.

0

20

40

60

80

100

120

1993 1995 1997 1999 2001 2003

Rotary sidetracks

CTD sidetracks

CTD performing majority of Prudhoe Bay sidetracks

sid

etra

cks

/ ye

ar

Fig. 1 – CTD is performing the majority of sidetracks at Prudhoe Bay, currently about 50 per year. CTD application and openhole sizes Many of the reservoirs on the North Slope range in depth from 8600 ft to 9200 ft true vertical depth (TVD) and have a combination of gas cap and waterflood/aquifer drive. As such, most sidetrack completions are required to provide vertical and zonal isolation with a cemented liner. Exceptions occur in

SPE/IADC 92392

Unique "Through Tubing" Completions Maximize Production and Flexibility Mark O. Johnson and Paul G. Hyatt, SPE, BP Exploration Inc.; Ted O. Stagg, SPE, Orbis Engineering; and Lamar L. Gantt, SPE, Conoco Phillips

2 M. JOHNSON, P. HYATT, T. STAGG, L. GANTT SPE/IADC 92392

predominately waterflood areas, or in shallower viscous oil sands (4000 ft to 7000 ft TVD). In these areas, a simple slotted liner to hold open weak sands and shales within the reservoir is often appropriate. CTD has been successful in both types of reservoirs by sidetracking away from depleted bottomhole locations and targeting areas of undrained oil to increase oil rate and reserves recovery. North Slope CTD typically drills a sidetrack of 2500 ft measured depth (MD) in length which includes a short high dogleg build section followed by a precisely placed horizontal lateral. A new world record sidetrack depth of 17515 ft MD was reached with CTD in March of 2004. By drilling through tubing to save decomplete/recomplete cost and with high build rate capability to stay within the reservoir, CTD is able to achieve a 30% cost savings compared to an equivalent rotary rig sidetrack on the North Slope. The high build rate capability allows kickoff within the formation avoiding overburden shales and protective casing strings. For example, a 45 degree per 100 ft build rate can turn from 0º inclination to horizontal (90º) in 127 ft TVD. Most parent wellbores in Alaska penetrate the top of reservoir at inclinations >35º making it possible for CTD sidetracks to hit horizontal in less than 54 ft TVD. Through tubing and high build rates are two distinct cost saving advantages of CTD. Several papers describe the drilling process in more detail (references 1-3). The continuous pipe is also well suited for drilling in severe lost circulation environments and in underbalanced mode (references 4-5). The most common CTD through tubing sidetrack in Alaska has been drilling 3 ¾-in. openhole through (below) 4 ½-in. production tubing (figure 2). Reliable through tubing whipstocks have a 3.65-in. outer diameter (OD) for running in hole and then expand to set in liner sizes up to 7 5/8-in. to create the kickoff point below the 4 ½-in. tubing tail. Once a 3.80-in. window is milled, the high dogleg build section is drilled with a 3 ¾-in. x 4 1/8-in. bicenter PDC bit to horizontal in the target sand. A trip is required to reduce motor bend and then the horizontal lateral is drilled with 3 ¾-in. PDC bits to TD. This CTD hole size combination is designated as “big hole” on the North Slope and accounts for over 350 of the 450 sidetracks to date. The latest completion design consists of a tapered 3 3/16-in. x 2 7/8-in. cemented liner. The 3 3/16-in. is run from the 4 ½-in. tubing tail through the build section into the target sand. The liner then crosses down to 2 7/8-in. for the majority of the lateral section to facilitate getting liner to bottom. The 3 3/16-in. section with a special drift clearance 2 ¾-in. inner diameter (ID) provides for future sidetrack options. A “slimhole” sidetrack option with downsized bit and steerable bottom hole assembly (BHA) has also been developed that allows penetrations through (below) 3 ½-in. production tubing and drills a 2.70-in.x3-in. bicenter openhole. About 100 of these sidetracks have been done to date. It is this downsized BHA that allows the option of a subsequent “slimhole” sidetrack anywhere from the 3 3/16-in. liner section of the “bighole” completions. As the fields mature and sidetracks continue, it is believed that CTD slimhole drilling

may become the dominate technique in Alaska. High production rates are possible through the slimhole 2 3/8-in. cemented or slotted liner completion since it makes up a relatively short portion of total well length and flows under bottomhole pressure conditions. Figure 3 shows the slimhole sidetrack option drilled from the bighole completion.

3 3/16“ liner

2 7/8“ liner

4 1/2“ productiontubing

7“ liner

Top of 3 3/16“ in4 1/2” tailpipe

liner crossover

CTD “bighole“ completion

CTD Sidetrack

throughtubingwhipstock

4 1/8“ or 3 3/4” openhole

liner cement

Fig. 2 – CTD “bighole”sidetrack completion

optional “ slimhole“sidetrack fromexisting “bighole”sidetrack

2 3/8“ liner

whipstock set in 3 3/16“ liner

Fig. 3 – CTD “slimhole” sidetrack option In summary, CTD sidetracks are designed to maximize reserves recovery and production in the near term, and when possible, preserve the wellbore for a future re-sidetracking to another undrained oil target. Tapered 3 3/16-in. x 2 7/8-in. liner The small CTD openhole (3 ¾-in. or 4 1/8-in. ID) requires custom liner equipment. The tapered liner string consists of 3 3/16-in. L-80 6.2 lb/ft thin wall tubing (0.194-in. thickness) with special clearance TCII coupling crossed down to 2 7/8-in. L-80 6.5 lb/ft flush joint ST-L. Both joint connections provide sufficient clearance and demonstrate adequate strength through high dog leg severity build sections. They routinely

SPE/IADC 92392 UNIQUE "THROUGH TUBING" COMPLETIONS MAXIMIZE PRODUCTION AND FLEXIBILITY 3

tolerate 45 degree/100 ft MD dogleg severity, and have maintained integrity several times through dog legs of >60 degs/100 ft. Custom integral blade special clearance box x box ridged blade centralizers (figure 4) are manufactured locally and maximize pipe liftoff and cement swirling action while minimizing reduction in annular flow area. The 3 3/16-in. centralizers have a 3.70-in. spiral blade OD on special clearance 3.45-in. OD coupling while the 2 7/8-in. centralizers have 3.5-in. OD blades with flush body. Centralizers are placed at every connection to provide quality cement jobs and to reduce pipe to formation friction when running in hole.

Fig. 4 – Custom made centralizers maximize pipe standoff from formation and cement swirling action while minimizing reduction in annular flow area. Drifting the liner is critical due to close tolerance liner wiper plugs and the potential for a 2 ¾-in. drillout from the 3 3/16-in. section in the future. A steel float shoe on the 2 7/8-in. is either bullnose or conical in shape to get by a problem whipstock or troublesome shale formation, respectively. Aluminum float shoes are now avoided because the soft material was found to occasionally deform and wedge preventing passage by whipstock window ledges. Future drillout of the 2 7/8-in. liner shoe is unlikely, so a steel float shoe is preferred. The top of the liner has a deployment sleeve rather than the traditional hanger/packer because of tight clearances, desire to maintain maximum ID, and the inability of coil tubing to weight set a packer. With the deployment sleeve, the liner must be placed on bottom or to a point it cannot be moved down further. The coil and special liner running tool (LRT) are used to run the ~3000 ft liner to TD. Once on bottom, a ball is inserted in the coil and pumped to the LRT to activate the release from the liner. (Phenolic or aluminium balls should be used if the LRT is near horizontal.) Pressuring up to ~2000 psi removes backup from collets and releases the liner. The ball seat is then sheared out and caught in the nose cage of the liner wiper plug. This re-establishes circulation down the liner for cementing. A pressure seal between the LRT and deployment sleeve is maintained by exterior seals on the LRT riding on the polished inside bore of the deployment sleeve.

After pumping cement into the coil, a coil wiper plug is inserted and displacement begins. The coil wiper latches into the liner wiper and added pressure shears the combo plugs to continue displacement to the landing collar for final latch up. This system cannot be used when electric line (EL) is within the coil. Historically a reel swap to “ EL-free” coil is done for cementing jobs. However, a novel technique for cementing with EL coil (avoid reel swaps) is in testing stages. From an operational standpoint, swelling and dispersing shales tend to give CTD more hole trouble than seen with conventional rotary rigs likely due to the lack of wiping from rotating drillpipe. Ledges can develop at sand shale interfaces and getting the nose of the liner past these areas can be problematic. Recently a liner was steered to bottom with a guide shoe, bent joint, sacrificial hydraulic orienter, circulation sub, and landing collar on the bottom of the liner. The liner stopped at two known openhole ledges while running in the hole. The orienter was cycled with pump pressure to change the toolface of the bent joint allowing successful passage by both trouble areas and on to total depth (TD). A ball was then dropped through the liner running tool to open the circulation sub just above the orienter and the cement job was pumped in the conventional manner. In another case a slotted liner was steered to bottom with a bent joint, but this time the entire liner was rotated by the electric over hydraulic orienter used with the EL drilling BHA. Both techniques mentioned above were firsts for Alaska in 2004. Extra caution is taken when shales are penetrated near TD of the well. They do not get the same conditioning time as shales encountered earlier in the hole. As such there is a greater chance of swelling and potential packoff near the float shoe during the cement job potentially leading to poor cement jobs. Consideration is given for relaxing the hole after reaching TD and re-reaming the shale prior to tripping for liner. Relaxing the hole in this case refers to reducing the ECD by pulling up into production tubing with the drilling BHA and shutting off the pumps for 4 hours to allow the shale to swell in. One last reaming trip is conducted prior to pulling out of hole for the liner. Liner Deployment. Pumping a coil wiper plug around the coil reel at surface verifies clean coil, reel volume for accurate displacement, and coil connector drift. Planned depth for top of liner is in the middle of the tubing tail to facilitate future re-entry into the liner. Depth is based on electric line measurements (ELM) of the tubing tail rather than drill pipe measurements (DPM) because the CTD sidetrack total depth is usually tied into gamma ray markers from an EL primary depth control log. Using DPM alone can result in an error for actual top of liner depth with the worst case being the top of liner is inadvertently placed in the large 7-in. casing below the smaller 4 ½-in. production tubing tailpipe, potentially leading to liner re-entry difficulty. When tailpipe size is greater than 4 ½-in., scoop tops are placed on the deployment sleeve to guide re-entry.

4 M. JOHNSON, P. HYATT, T. STAGG, L. GANTT SPE/IADC 92392

A typical CTD big hole liner completion is as follows:

• 2 7/8-in. Float shoe ( ST-L) (round or tapered steel nose)

• 2 7/8-in. Float collar (ST-L) • 2 7/8-in. - One 30 ft joint of liner (ST-L) • Landing Collar (ST-L) • 2 7/8-in. Liner (ST-L) with 3.5-in. OD centralizers • 10 ft marker joint • LSL (locate/sealbore/latch) crossover sub – to be

discussed in next section • 3 3/16-in. TCII liner with 3.70-in. centralizers • 3 ½-in. ST-L x 3 3/16-in. TCII crossover • 1 jt of 3 ½-in. • “ X” nipple 3.70-in. OD, 2.813-in. ID • 3.70-in. liner deployment sleeve w/ “ GS” profile • Liner running tool (LRT) with liner wiper plug • Big bore hydraulic disconnect • Swivel • Coil connector

Cementing Considerations. Once the liner is on bottom, circulation is verified and the liner is released. The entire wellbore including openhole is displaced to 2% KCL water to eliminate incompatibility between the Xanthan polymer based drilling fluid and liner cement. This essential step flushes drilling fluid from the openhole to improve cement bond and reduces annulus friction and equivalent circulating density (ECD) during pumping of the cement job. The cement job is pumped with sufficient volume to bring top of cement (TOC) a minimum of 200 ft above the window (lap volume) and includes 40% excess in the openhole by liner annulus to cover hole washout. A 15.8 pound per gallon (ppg) acid resistant latex blend is standard with the addition of expander agent (magnesium oxide) dependent on individual field experience. Pump rate is adjusted to target an annular velocity of >250 fpm during the job. By the time the liner wiper plug has been displaced to the landing collar there are often cement returns over top of liner. In the past the cement was circulated out of the well at the LRT right after pulling out of the liner deployment sleeve. However, a high ECD is created by moving the heavy and viscous cement out of hole during the cleanout resulting in a number of liner lap test failures. Cement was being pushed down out of the lap area and leakoff during testing was believed to occur to the openhole just outside the window. To improve lap integrity a new technique was developed to eliminate annulus friction by only replacing coil voidage on the way out of hole with 2 pound per barrel (ppb) biozan water rather than circulating the cement out of hole at full rate. The biozan retards the cement such that it can be cleaned out by circulation during a combination mill and motor cleanout/ memory compensated neutron logging (CNL) run. This replacing voidage technique helps preserve the lap cement and has cut the number of liner top packer runs in half. If a lap test were still to fail, a retrievable packer with seal stem is run by coil into the deployment sleeve to seal the lap leak.

In some instances a very short liner lap of 30 ft above the window is utilized to preserve the wellbore for another bighole CTD sidetrack from the 4 1/2-in. liner above. Historically this “ shorty lap” has not provided cement integrity in the lap area and a liner top packer is automatically run. These through tubing completion practices have resulted in a very successful program of isolating gas and water zones from the oil bearing sands in the CTD sidetrack program. Critical isolation is achieved on a consistent basis as proven by production testing. In addition, pulse neutron logging (PNL) passes before and after injecting a borax solution into perforations shows 100% injection into formation across from open perforations and no channelling up or down the CTD liner (figure 5). Several of these borax PNLs and conventional cement bond logs have verified cement isolation integrity.

NoCement

Channels

wellboreprofile

horizontal

build section

Fig. 5 – Good cement job. Pulse Neutron logging passes before and after borax injection indicates all solution went into formation across from perforations (shaded), no up or down channeling. Selective Multi-Lateral Producer Gas that is produced with oil at Prudhoe Bay is currently separated and re-injected back into the reservoir. Oil offtake from the field is gas handling facility limited, so the lower gas to oil ratio producing wells make the most net oil contribution

SPE/IADC 92392 UNIQUE "THROUGH TUBING" COMPLETIONS MAXIMIZE PRODUCTION AND FLEXIBILITY 5

to daily offtake. A relatively high Kv/Kh of 0.10 at Prudhoe Bay makes for an efficient gravity drainage primary recovery mechanism, but near wellbore gas coning is common and negatively impacts oil production. Because of gas coning, wells are often cycled on and off production to allow the gas cones to re-saturate with oil. This production practice increases oil production, but results in under utilized wellbores during the shut-in cycles. A low cost multi-lateral completion with the ability to selectively cycle production from one horizontal leg to another can provide incremental oil rate benefit and continuous production from the well. Oil production from one leg can occur while a gas cone is healing with time in the isolated second leg, and vice versa. A unique low cost through tubing selective multi-lateral completion of this type was installed in a Prudhoe Bay well in 2002 (figure 6). The well had already been sidetracked to horizontal with a 4 ½-in. cemented liner put in place by a rotary rig. A second horizontal lateral was added by CTD in 2002 with the sidetrack kickoff at the very deepest point in the horizontal 4 ½-in. liner to maximize gas standoff. For the sidetrack window, a 4 ½-in. packer with orientation slot and seal receptacle was set in the horizontal section by coiled tubing. Slot toolface orientation was recorded in memory mode. The next run on coil with a whipstock, retrievable latch, and orienting lug on bottom was timed for a 90° toolface exit and snapped into place. The window was milled and 1300 ft of horizontal lateral drilled as close to the bottom of the reservoir as possible for vertical standoff from gas. The CTD lateral leg was drilled in the opposite direction of the rotary leg to maximize spread between drawdown points in the reservoir. A 2 7/8-in. slotted liner was run into the new lateral openhole with the top of liner dropped off 4 ft outside the window. The whipstock was retrieved from the packer with a cut lip guide die collar overshot and mud motor. A 2 7/8-in. selective production string was run with seal stem on bottom and latched into the packer. The top of the string consisted of a deployment sleeve (seal receptacle) spaced out to 7 ft below the existing XN nipple in the 4 ½-in. production tubing. The top of the selective string is at an inclination that allows wireline access to install a toggle sub that stings into the top of the selective string seal receptacle and locks in the XN nipple. The toggle can be easily configured to allow commingled flow, or isolated flow up the inside of the selective string (rotary lateral) or isolated flow up the selective string by 4 ½-in. liner annulus (CTD lateral).

7“ Liner

4 1/2“ cemented and perforated 2 7/8“ slotted liner in 3.75” OH

Gas Coning

These perfsgassed out

Shut in this leg forcone to heal

PBU’s First Multi-Lateral “Selective” Producer

CTD Through 4 1/2“ tubing Multi-lateral Sidetrack

Selectively produce oil from this leg

Toggle for Sidetrack onlyToggle for Parent wellbore

Fig. 6 – Selective multilateral producer. Low cost through tubing system provides isolated production from one lateral leg or the other. Note that this completion design has an uncemented openhole junction at the start of the CTD lateral leg. For this leg to be a viable oil contributor it must be placed at the bottom of the reservoir to provide maximum standoff from encroaching gas. In addition, the original cement job on the 4 ½-in. liner must also provide a good seal such that a vertical conduit to gas does not exist. This selective dual-lateral well was first put on production in commingled mode. Since that time 3 toggle configurations have been installed to cycle production from the CTD lateral alone, to the rotary lateral alone, back to the CTD lateral. Oil production from this selective multilateral has met expectations and the well has maintained continuous “ on line” production status. This well completion had an optimum set-up starting with a “ bottom of reservoir” kick off point available in the existing 4 ½-in. horizontal cemented liner (the earlier rotary rig sidetrack completion). In reality, this situation is relatively rare leading to a small candidate pool. LSL Liner Component. CTD routinely places a horizontal cemented liner at the bottom of the reservoir, so if a downsized multilateral junction system could be developed, the candidate pool for selective multilaterals would increase. This cemented liner needed a downsized junction system to facilitate addition of a second lateral leg, and also provide a latch and bottom seal area for the selective string. Preparing a well in this manner allows addition of a second lateral leg at anytime, with capability for cycling production between legs to optimize production. As mentioned before, any open junctions in a gas cap reservoir should be placed at the very bottom of the reservoir to provide maximum standoff from encroaching gas.

6 M. JOHNSON, P. HYATT, T. STAGG, L. GANTT SPE/IADC 92392

A special locate, sealbore, latch (LSL) liner component was designed with a service company partner to create a kickoff point (KOP) in a newly lined and cemented 3 3/16-in. x 2 7/8-in. CTD bighole completion (figure 7). The LSL by design also serves as a crossover from the 3 3/16-in. to 2 7/8-in. liner and is placed anywhere in the well, but usually at the deepest point in the reservoir just beyond the build section in the horizontal. The entire first leg liner of the multilateral is cemented in place to provide the essential vertical isolation from gas. With a 2.8-in. nominal liner ID (2 ¾-in. drift) down to the LSL, a slimhole sidetrack BHA (2 ¾-in. bit) can add the 2nd lateral leg.

Fig. 7 – LSL liner component provides for selective multi-lateral completion option. The only change in the cementing procedure for the first leg was to insert a spacer in the multi-fin liner wiper plug to ensure no fluid bypass of the plug as it traverses the LSL. This plug wipes both 3 3/16-in. and 2 7/8-in. liner sizes during displacement to the landing collar (figure 8).

Fig 8 – Liner wiper plug for 3 3/16-in. x 2 7/8-in. tapered liner with LSL liner component (pictured at top). Coil wiper plug is at right. Previous plug design is shown below.

The LSL’ s integral latch receptacle, orienting slot, and seal bore is designed to accept a corresponding latch assembly on the bottom of the whipstock tray that also includes an orienting lug and seals. The seals isolate the initial production leg. A 2 ¾-in. window is milled followed by a 2500 ft horizontal lateral to a new oil target. It is essential that this lateral leg be held close to the bottom of the reservoir for gas standoff because it is lined with slotted liner, with top of liner left 5-10 ft outside the window. The whipstock is retrieved and a 2 1/8-in. selective string with sealing latch on bottom is installed. Again, a toggle sub at the top of the selective string can provide commingled production or isolated lateral 1 production up the middle of the selective string, or lateral 2 production up the 2 1/8-in. x 3 3/16-in. annulus. An alternative use of the LSL is as a patch system to isolate gassed out perforations in the build section of the sidetrack. These perfs targeted oil lenses that often provide a large initial oil rate benefit, but gas out quickly making the well un-competitive. A traditional cement squeeze of the perforations would have little chance of success, so a mechanical patch is optimum. The sealing latch in the LSL at the bottom of the patch has an ID of 1.85-in. allowing 1 11/16-in. perf guns to pass. The upper part of the patch is a 3 ½-in. or 3 3/16-in. packer. Over 40 LSLs have been installed to date, and every bighole CTD sidetrack now receives the LSL to provide a large future slimhole candidate pool. Combined cemented and slotted liner “bonzai” completions Lengthy horizontal tubing conveyed perforating (TCP) is costly, accounting for 15% of total sidetrack cost in Alaska. When possible, a combination solid cemented liner with slotted liner on the bottom is run to provide vertical isolation but save perforating costs in the horizontal section (figure 9). Rotary rigs on the North Slope have been performing these completions for years with an external casing packer (ECP) to prevent cement contamination of the slotted liner portion. Unfortunately, no ECPs exist for a 3 ¾-in. openhole that maintain a nominal ID of the 2 7/8-in. liner size. Again, the lack of ready made equipment in CTD hole sizes has required innovative techniques to manage the problem.

SPE/IADC 92392 UNIQUE "THROUGH TUBING" COMPLETIONS MAXIMIZE PRODUCTION AND FLEXIBILITY 7

openhole

ported sub

inner string for cementingwith polished stinger

baffle plate

packoff bushing

cementedsolid liner

enlarged below

floatcollar

Fig. 9 – Combined solid cemented and slotted liner “bonzai” completion saves tubing conveyed perforating costs. After drilling the CTD sidetrack, a thick pill (150,000 cP low shear rate viscosity) of fresh Xanthan based drilling fluid is placed in the horizontal lateral. The pill prevents migration of the liner cement into the slotted liner section by using viscosity to limit fluid leakoff to the openhole and a cross linking of the Xanthan polymer (thickening) at the cement/drilling fluid interface due to high pH. Ideally the cement/openhole interface can also be located in an “ uphill” inclination to prevent gravity slumping of the cement into the openhole slotted liner section. Drill out of aluminum and rubber liner wiper plugs is a high risk operation for coil tubing in small liners. The aluminum and rubber tend to wedge along side the BHA resulting in stuck pipe. As such, liner wiper plugs are not utilized in the CTD “ bonzai” completion. Instead, an inner string cementing job is conducted. Accurate displacement volumes are maintained by using a coil wiper dart that is caught, sheared, and then retrieved from the hole within the liner running tool. The “ bonzai” liner consists of the following components tailored for big or slimhole CTD sidetracks:

• 2 3/8-in. or 2 7/8-in. ST-L guide shoe to TD • ST-L slotted liner • ST-L solid liner 1 joint (for cement slump) • “ bonzai” components: baffle plate / ported sub /

float collar assembly at desired depth of cement • One joint ST-L solid liner

• O Ring Sub • ST-L solid liner with centralizers (cemented

portion) • liner deployment sleeve (top of liner in

production tubing tail)

Liner running equipment • 1-in. washpipe (integral tool joint) with 15 ft

slick stick • LRT with release ball and coil wiper dart catcher

feature • Large ball drop disconnect • Coiled tubing connector

An important well control feature when running slotted liner is use of a solid (non slotted) safety joint. The safety joint with stabbing valve should be available for immediate deployment. In the event of well flow while running liner, the safety joint can be screwed into the top slotted joint and then run across the BOP stack to achieve an effective seal. The liner can then be run in the hole on coil to circulate kill from bottom as necessary. Once liner is on bottom and circulation is confirmed through the ported sub, a ball is dropped to disconnect the LRT from the liner. Liner cement is followed by a coil wiper plug and displaced with biozan water. Cement hits the baffle plate, is diverted out the ported sub and climbs up the outside of the solid liner. When the coil wiper dart is displaced to within 2 bbls of the liner running tool, pump rate is slowed down to 0.5 BPM to observe the coil wiper dart land in the LRT. At first sign that the dart has landed the displacement volume is noted. This will be the start point of the prescribed volume to accurately displace top of cement to 100 ft above the baffle plate inside the liner. The coil is pressured up to shear the wiper dart and displacement is continued until the cement is placed at the desired depth within the liner. To avoid over displacement, the total volume pumped must start at the initial recorded dart landing value. For example pressuring the coil up to 2000 psi to shear the coil wiper plug may add 1 bbl volume to the system that must be included in the final displacement volume. The stinger is then pulled out of the O ring sub and remaining cement in the inner string is laid into the liner above the baffle plate. The inner string is pulled out of liner while pumping at only enough rate to replace string voidage. The float is held closed by the outside head of cement. Once the slick stick is within 10 ft of TOL, circulation is increased to contaminate excess cement above the lap with biozan water. After a pressure test of the cement job, a bladed mill and mud motor is run down on enough jointed pipe to mill out the “ bonzai” equipment (float collar and baffle plate) and cleanout to TD. Two wellbore volumes of 2% KCL water are circulated from the far end of the slotted liner to dilute and flush out the drilling fluid.

8 M. JOHNSON, P. HYATT, T. STAGG, L. GANTT SPE/IADC 92392

Preserving Parent Wellbore Production Often times it is beneficial to add a sidetrack lateral to a well but still preserve the parent wellbore production. If the parent is still contributing net production this makes the sidetrack more economic because remaining reserves in the parent do not need to be subtracted from new target reserves. In this scenario it is preferred to isolate the parent wellbore from drilling fluid and cuttings to minimize formation damage during the sidetrack. For wells with production liner that has a greater ID than the production tubing (e. g. 7-in. liner, 4 ½-in. production tubing), an inflatable bridge plug (IBP) is set in the 7-in. followed by a through tubing 4 ½-in. x 7-in. whipstock above (figure 10). When the whipstock is expanded and set, there are over 10 square inches of flowby area. The IBP below the whipstock is outfitted with a through bore and standing valve arrangement. The standing valve isolates the parent wellbore from drilling fluid and ECD during drilling of the new lateral leg. When the well returns to production, parent wellbore fluids open the standing valve and commingle with the new lateral production. This technique is often used in waterflood area wells where the lateral liner does not need to be cemented. Ten wells have utilized this completion technique on the North Slope. A tube that extends above the IBP is centered in the wellbore and helps to prevent potential plugging of the standing valve with drill cuttings. Also, it is recommended that the IBP be located as far as possible below the whipstock to minimize temperature impacts to the inflatable. About 10% of the IBPs failed (released) resulting in drilling fluid losses to the parent wellbore during drilling of the new lateral. When liner size is the same as tubing size, a packer with locating slot is set just below kickoff depth. A whipstock with a hollow tube extension down to a hollow latch with seals and locating lug is stung into the packer. The hollow tube extension holds the standing valve and is cross drilled to minimize potential plugging by debris falling past the whipstock. Flow area around the monobore whipstock set in 4 ½-in. liner is still a satisfactory 3 square inches.

Fig. 10 – Inflatable bridge plug with standing valve protects parent wellbore during drilling of the sidetrack and allows production to be re-established. A greater challenge is preserving parent wellbore production in the case where a new lateral leg liner must be cemented in place to provide isolation from the gas cap. To date, six custom made 4 ½-in. hollow whipstocks have been installed. Production from the parent wellbore would be re-established by orienting a perf gun to shoot down through the new cemented liner into the tray face of the whipstock thereby penetrating a hollow chamber in communication with the parent wellbore liner below (figure 11). This technique is only available in monobore applications at this time and consists of setting a packer with hollow latch and extension attached to the hollow whipstock tray. The tray is designed such that the hollow chamber will not be penetrated by the window mill during milling operations. The lateral is drilled and then lined and cemented with a standard liner, but with the addition of an XN nipple placed ~10 ft above the desired perforating location. This provides very precise placement of shot depth when it is desired to re-establish production from the parent wellbore.

SPE/IADC 92392 9

Fig. 11 – Perforations through liner and hollow whipstock allows production from parent to be re-established. Re-establishing parent wellbore production without creating a communication path to the gas cap is still considered a high risk operation. After accurate perforation of the liner and whipstock, there remains only 2 to 3 inches of cement to isolate the production stream from the reservoir rock just outside the sidetrack window. This small thickness of cement exposed to 1500 psi of flowing bottomhole pressure drawdown may not be able to prevent communication to a prolific gas zone. As such, all 6 hollow whipstocks have been placed at the bottom of the oil reservoir to provide maximum standoff from overlying gas. Sidetracking Off of Aluminum Liner Tops Long horizontal multi-laterals grow in popularity in virtually all of the fields on the North Slope. Nowhere has this technology been so important to Alaska than in the shallow viscous oil sands of the West Sak and Schrader Bluff reservoirs. The decades long search for an economic way to tap the 1-3 billion barrels of recoverable viscous oil reserves has finally born fruit. Satisfactory well production rates are now achievable (1000 BOPD sustained rate), but the current challenge is to bring down well cost. It is believed that most of these reservoirs benefit from screens or slotted liners to mitigate hole collapse. The shallow sands are marginally cemented and excessive drawdown has been known to collapse barefoot completions. An innovative technique of creating lower cost multilaterals but retaining the ability to 100% line each leg has been achieved by an aluminum kickoff billet with 1-in. ID integral to the top of a slotted liner (figure 12). In this scenario an initial sidetrack window is milled from the parent wellbore and horizontal lateral drilled to TD. A slotted liner of prescribed length with aluminum kickoff billet on top is run in the hole to TD. The aluminum kickoff billet is placed outside the original window in openhole at the desired depth to create the second lateral. A bent motor drilling BHA with rounded

PDC bit sidetracks off the aluminum and drills the new lateral to TD. This step can be repeated from numerous aluminum top liners. The final lateral is lined from TD all the way back into the parent wellbore. Advantages include:

1) A low cost openhole sidetrack technique 2) Positive guidance of the liner into the second lateral

leg. 3) All multilateral legs are completely lined with the

exception of a ½-in. gap between the aluminum kickoff billet and adjacent slotted liner.

Aluminum liner top kickoff billet

both are slotted liners

Both Laterals 100% lined

Fig. 12 – Aluminum liner top kickoff billet. The aluminum top liner sub utilizes a G fishing neck on top to allow the liner running tool to carry the liner into the hole and release it at desired depth. The 1-in. through bore ensures communication to the leg, although a path outside the liner (liner x OH annulus) also exists. The junctions are purposely planned in sand sections for maximum permeability and ease of creating a sidetrack. To date, two separate wells have successfully received multi-laterals with this technique. Excellent production rates from both wells suggests that the laterals are open and performing at or above expectations. This aluminum liner top kickoff billet technique is expected to grow in popularity both for CTD and rotary applications. Bigger aluminum liner top kickoff billets have already been ordered by rotary rig teams for 6-in. openhole multi-laterals. Expandable Screens and Solid Liners Work is progressing with expandable screens and solid liners to address unconsolidated sands and wellbore instability. As mentioned before, CTD has more trouble with shales within the target formations than rotary drilling rigs. Although drilling fluid systems are inhibited, a swelling or sloughing shale can reduce weight transfer and make drilling ahead more difficult. Shale sand interface ledges can become so large that the drilling BHA cannot pass the area, resulting in a possible requirement to re-drill the lateral.

10 SPE/IADC 92392

For CTD, it would be ideal to be able to place an expandable liner over the troublesome shale, ledge, or washout sections and then continue to drill beyond the area trouble free. As an example for the bighole CTD drilling this would entail an expandable liner of 30 ft x 3.70-in. OD being run through a 3.80-in. ID whipstock window out into 4 1/8-in. ID bicenter openhole. Once placed across the troublesome interval the liner would be expanded out to the 4 1/8-in. hole leaving a 3 ¾-in. through bore ID. A 3.70-in. x 4 1/8-in. bicenter bit and drilling BHA could then travel through this previously troublesome area and continue drilling the lateral. Several service companies have expressed interest in developing this technology. A joint funding project to develop the capability is expected to be awarded in the near future. Conclusions A through tubing completion that maximizes production and provides future flexibility is essential to the overall success and longevity of a through tubing sidetrack campaign. Experienced gained in completing over 450 coiled tubing drilling sidetrack oil wells on the North Slope has led to the development of several proven and reliable through tubing completion designs. Innovation and close collaboration with the service industry has overcome challenges associated with small clearances and the lack of ready made equipment.

1) High quality liner cementing is being achieved via the use of custom 3 3/16-in., 2 7/8-in., and 2 3/8-in. liner equipment and cementing techniques. These cement jobs provide reliable and critical isolation from encroaching gas and water.

2) Selective multilaterals can increase production rate

and keep the well in continuous operation, rather than in an on/off cycle mode.

3) Combination solid/slotted liners provide vertical

isolation while saving an additional 15% of well cost by avoiding tubing conveyed perforation costs.

4) Three techniques for adding a lateral while

preserving parent wellbore production make sidetrack economics more favorable.

5) Aluminum kickoff billets at the top of liners in

openhole allow a lateral to be added at low cost while still lining 100% of the wellbore to hold open an unstable formation.

6) Slimhole expandables will help CTD with wellbore

instability in the future. Low cost reservoir access, such as through tubing sidetracks, is a key component to sustaining production from maturing fields on the North Slope. The completion options discussed in this paper may make low cost through tubing sidetracks more feasible for other mature fields.

Acknowledgements Through tubing completions in Alaska have been successful through the efforts of many individuals and companies. The authors of this paper would especially like to thank David Hearn, Bob Harris, and Carl Diller for their innovative and significant contributions. The authors thank BP Exploration for permission to publish this paper. References

1. Goodrich, G. et al.: “ Coiled Tubing Drilling Practices at Prudhoe Bay” , paper IADC/SPE 35128 presented at the 1996 IADC/SPE Drilling Conference, New Orleans, Mar. 12-15.

2. Williams, B. et al.: “ Field History of Coil Tubing Drilling

in the WOA of Prudhoe Bay” , paper SPE 35663 presented at the 1996 SPE Western Regional Meeting Drilling, Anchorage, AK, May 22-24.

3. McCarty, T. et al.: “ Coiled Tubing Drilling: Continued

Performance Improvement in Alaska” , paper SPE 67824 presented at the 2001 SPE/IADC Drilling Conference, Amsterdam, Feb 27-Mar 1.

4. Pruitt, R. et al.: “ Sajaa Underbalance Coiled Tubing

Drilling “ Putting it all Together,” paper SPE 89644 presented at the 2004 SPE/ICOTA Coiled Tubing Conference, Houston, Mar. 23-24.

5. Weighill, G. et al.: “ Underbalanced Coiled Tubing Drilling

Experience on the Ula Field” , paper SPE 35544 presented at the 1996 European Production Operations Conference and Exhibition, Stavanger, Norway, April 16-17.

6. Queiros, J. et al.: “ Through Tubing Rotary Drilling and Its

Associated Cementing Challenges: A North Sea Experience” , paper SPE 83955 presented at the 2003 Offshore Europe 2003, Aberdeen, UK, Sept. 2-5.

SI Metric Conversion Factors bbl x 1.590 E-01 = m3 gal(US) x 3.785 E-03 = m3 ft x 3.048 E-01 = m inch x 2.540 E+01 = mm psi x 6.895 E-03 = MPa Abbreviations/Nomenclature Bbl = barrel cp = centipoise Kv/Kh = ratio of vertical over horizontal perm psi = pounds force per square inch -in. = inch ft = foot