Coiled Tubing Takes Center Stage

David Bigio nCoiled tubing drilling on Lake Maracaibo, Venezuela. With the well control equip- Andy Rike ment of the CT unit, wells are drilled into suspected pockets of shallow gas. The gas is Anchorage, Alaska, USA drained to prevent it from becoming a hazard to conventional drilling. When it comes to coiled tubing, there can be few doubters left. What Axel Christensen Mærsk Olie og Gas was once a fringe service has moved to center stage in the oilfield the- Copenhagen, Denmark ater of operations. Jim Collins Doug Hardman For many years, coiled tubing (CT) opera- have combined to dramatically expand the Calgary, Alberta, Canada tions occupied the twilight zone of a fringe uses of coiled tubing (above). service offering niche solutions to special- Today for example, coiled tubing drills Denis Doremus ized problems. However, over the past five slimhole wells, deploys reeled completions, Patrick Tracy years, technological developments, logs high-angle boreholes and delivers Sugar Land, Texas, USA improved service reliability, gradually sophisticated treatment fluids downhole. This increasing tubing diameter and an ever- article will look at the technical challenges Glen Glass growing need to drive down industry costs presented by these services and discuss how Suncor Inc. they have been overcome in the field.1 Calgary, Alberta, Canada

Niels Bo Joergensen For help in preparation of this article, thanks to Von 1. This article is an elaboration of a speech given by Cawvey and Lamar Gantt, ARCO Alaska Inc., Anchor- Roberto Monti, President, Schlumberger Dowell: Mærsk Olie og Gas age, Alaska, USA; Dave Ackert, Dowell, Montrouge, “Cost-Effective Technology Levers to Improve Explo- Esbjerg, Denmark France; Larry Leising, Dowell, Rosharon, Texas, USA; ration and Production Efficiency” presented at the Bart Thomeer, Dowell, Sugar Land, Texas; David Baillie, Offshore Northern Seas Conference, Stavanger, Nor- Schlumberger Wireline & Testing, Montrouge, France; way, August 23-26, 1994. Douglas Stephens Mark Andreychuk, Wayne Murphy and Doug Pipchuk, Esbjerg, Denmark Dowell, Red Deer, Alberta, Canada. In this article, SLIM 1, DLL (Dual Laterolog Resistivity), Litho-Density, SRFT (Slimhole Repeat Formation Tester), RST (Reservoir Saturation Tool), Pivot Gun, Power Pak and FoamMAT are marks of Schlumberger. SPOOLABLE is a mark of Camco International Inc. October 1994 9 Drilling Slimhole Wells Injection and shallow tion extended using underbalanced CT Slimhole wells—generally those with a final 160 gas wells 71% drilling, resulted in production three times Through-tubing reentry diameter of 5 inches or less—have the wells 13% greater than predicted rates (see “Prudhoe potential to deliver cost-effective solutions Conventional reentry and Bay CT Drilling Reentry Well” next page). to many financial and environmental prob- 140 deepened wells 12% Wells in Prudhoe Bay are drilled in clus- lems, cutting the amount of consumables Exploration wells 4% ters from pads—the same way that they are needed to complete a well and producing drilled from platforms offshore. The logistics less waste.2 Other benefits depend on what 120 of supplying and servicing an extreme loca- kind of rig drills the well. Compared to con- tion are also similar to those encountered in ventional rigs, purpose-designed smaller the North Sea. However, with about 1200 rotary rigs can deliver slimhole wells using 100 wells—of which ARCO operates half— fewer people on a much smaller drillsite, Prudhoe Bay benefits from potential which cuts the cost of site preparation and economies of scale. significantly reduces the environmental As with any mature operation, there is a impact of onshore drilling.3 80 need to extend field life and gain incremen- Coiled tubing drilling combines the virtues tal reserves at a cost that reflects today’s oil of a small rig with some unique operational price. While the primary aim is to devise a advantages, including the capability to run 60 strategy for low-cost well redevelopment, a the slim coiled tubing drillstring through secondary aim is to improve the productiv- existing completions to drill new sections ity of horizontal wells by reducing forma- CT drilling job count below. There is also the opportunity to har- 40 tion damage associated with conventional ness a coiled tubing unit’s built-in well con- overbalanced drilling. trol equipment to improve safety when In line with these objectives, candidate drilling potential high-pressure gas zones. wells for CT drilling are divided into two 20 This allows safe underbalanced drilling— classes: when the well may flow during drilling.4 •the replacement of waterflood wellbores Although there were attempts at CT that have corroded because of the high drilling in the mid-1970s, technological 0 carbon dioxide content of the water 1991 1992 1993 1994 advances were needed to make it viable. Estimate •horizontal sidetracks to replace conven- These include the development of larger tional gravity drain wells, tapping new diameter, high-strength, reliable tubing, and nThe rapid increase in CT drilling. This zones and improving recovery. the introduction of smaller diameter positive estimate of the number of jobs performed Four years ago, ARCO began sidetracking displacement downhole motors, orienting does not include many informal and the existing wells using conventional Arctic unreported reentries and drilling attempts tools, surveying systems and fixed cutter bits. that have been carried out over the rigs. The corroded tubing was pulled and Furthermore, currently available coiled tub- years—particularly in Canada. new well sections drilled. ARCO realized ing engineering software enables important that this was going to be a necessary proce- parameters to be predicted, such as lock without pulling the production string is a dure for the future, but that conventional up—when tubing buckling halts drilling cost-effective way of sidetracking or deep- technology was going to incur considerable progress—available weight on bit, expected ening existing wells. costs. Using a traditional Arctic rig to enter a pump pressure, wellbore hydraulics and The development of through-tubing, reen- Prudhoe Bay well, drill the sidetrack and wellbore cleaning capability.5 try underbalanced drilling is of great interest run a completion costs over $1 million—as It was not until 1991 that the first positive in the Prudhoe Bay field on the North Slope many as 800 sidetracks may be needed in results of CT drilling were seen with the of Alaska, USA, where operator ARCO ARCO’s Prudhoe Bay unit. deepening of a vertical well in France by Alaska Inc. has an alliance with Dowell to The goal of the Arco-Dowell alliance is to Schlumberger Dowell and Elf Aquitaine, develop coiled tubing technology.8 The develop a lower cost alternative to conven- and the drilling of two horizontal reentry alliance has already scored a number of tional rig sidetracks. To date, promising results wells in West Texas, operated by Oryx technical and commercial successes. For show that CT sidetracks can ultimately be Energy Co.6 Today, experience has been example, a 600-ft [180-m] horizontal sec- performed at half the cost of rig operations. built up, technology development continues (continued on page 14) and the number of wells drilled worldwide 7 is set to increase rapidly (above, right). 2. Randolph S, Bosio J and Boyington B: “Slimhole 5. Simmons J and Adams B: “Evolution of Coiled Tubing More than two thirds of 1994’s expected Drilling: The Story So Far...” Oilfield Review 3, no. 3 Drilling Technology Accelerates,” Petroleum Engineer 150 CT-drilled wells will be injection or (July 1991): 46-54. International 65, no. 9 (September 1993): 26-34. shallow gas wells—including steam injec- 3. “Questioning the Way We Drill,” Oilfield Review 6, 6. Ackers M, Doremus D and Newman K: “An Early no. 3 (July 1994): 4-9. Look at Coiled-Tubing Drilling,” Oilfield Review 4, tion wells in California and pilot wells to Faure AM, Zijlker VA, van Elst H and van Melsen RJ: no. 3 (July 1992): 45-51. relieve pockets of shallow gas in Lake Mara- “Horizontal Drilling With Coiled Tubing: A Look at 7. Leising LJ and Rike EA: “Coiled-Tubing Case Histo- caibo, Venezuela. However, these wells Potential Application to North Sea Mature Fields in ries,” paper SPE/IADC 27433, presented at the Light of Experience Onshore The Netherlands,” paper SPE/IADC Drilling Conference, Dallas, Texas, USA, tend to be no deeper than 1640 ft [500 m] SPE 26715, presented at Offshore Europe Conference, February 15-18, 1994. and take only one day to drill. Aberdeen, Scotland, September 7-8, 1993. 8. “New Life for an Old Slope,” Journal of Petroleum Through-tubing reentry in underbalanced 4. Leising LJ and Rike EA: “Underbalanced Drilling With Technology 46, no. 5 (May 1994): 388-390. Coiled Tubing and Well Productivity,” paper SPE conditions is a category of CT drilling that 28870, presented at the SPE European Petroleum may grow significantly. Reentering wells Conference, London, England, October 25-27, 1994.

10 Oilfield Review Prudhoe Bay CT Drilling Reentry Well

Drilled 3 3/4-in. openhold underbalanced through 4 1/2-in. tubing into two target sands.

Rig operations CT drilling operations

Gas-lift hardware

3 7 3 /4-in. open hole 8 3 2 / -in. predrilled line subsequently underreamed to 4 /4-in. (2 holes / ft plugged with aluminum)

1 4 /2-in. production string

1 7-in. liner 4 /2-in. tubing

Shale

Sadler Rochit sandstone Lower Romeo interval

586 ft

Drilled in 1980, Well 2-16 had been worked over hydrostatic pressure of the mud in the annulus nWell 2-16 after sidetracking and with the ultimate com- a number of times but despite two matrix stimu- and therefore the bottomhole pressure during pletion including the 2 7/8-in. predrilled liner plugged with aluminum. During drilling, gas was injected inside the 4 lation treatments had become a poor producer. drilling, creating an underbalanced situation. 1/2-in. production tubing-CT annulus. As such, it was shut in 50% of the time. To allevi- Nearly 600 ft of horizontal section was drilled ate this, operator ARCO decided to use underbal- through two target sands separated by a thin The openhole size was limited by restrictions anced CT drilling to exploit a horizontal section of shale layer. Drilling proceeded smoothly until a in the production string and 3 3/4-in. natural dia- the relatively poor-quality reservoir—pay zone measured depth of 11,933 ft [3637 m] was mond bits were employed. Above the bit, the bot- permeability is about 50 millidarcies (md). reached; at that point, penetration slowed and the tomhole assembly (BHA) included: A rig was used to pull the completion hardware hole became sticky. • a 2 7/8-in. motor with a bent housing, a check and sidetrack out of the existing casing in the There had been indications of an acceptable valve and a nonmagnetic collar deviated well, drilling until the wellbore was at production rate from the interval already drilled • a SLIM 1 measurements-while-drilling (MWD) 90° and had just entered the target formation. so the well was put on production. Short-term system and gamma ray log Prior to the start of coiled tubing operations, the testing yielded some 3500 barrels of oil per day • an orienting tool to change the tool face down- rig was used to set a 7-in. liner and install a 41/2- (BOPD), about three times that expected from a hole and steer the drilling—needed because it in. production string including gas-lift hardware. conventionally drilled horizontal well in the area. is not possible to rotate the coiled tubing.

With 2-in. CT through the 4 1/2-in. production The well was completed barefoot for an extended The Dowell orienting tool is actuated by pulling tubing, a 3 3/4-in. diameter open hole was test period with a view to running a slotted liner drilled. Artificial lift was used to reduce the later (above). From the start of CT drilling operations to first production took 11 days.

October 1994 11 off bottom slightly and reducing the rate of drilling fluid pumped through it to create a pressure differential of at least 1000 psi inside the tool’s indexing section. Then, by increasing the pump to the maximum rate allowed by the motor, the tool face is changed by a 30° increment. However, once drilling starts, reactive torque—which tends to twist the BHA clock- wise—will alter the actual orientation of the BHA. To allow for this, before the tool angle is adjusted the effect of reactive torque is measured by simply tagging bottom at the intended weight on bit (WOB) and rotation speed. Once the extent of reactive torque has been measured, the tool face may be altered accordingly. Reactive torque may also be used to fine-tune the tool face—the higher the WOB, the greater the reactive torque. A key element of underbalanced drilling is the deployment of the drilling assembly into a live well. To do this, the BHA was divided into three 72 ft segments (next page, right), the longest of which was just over 30 ft [9 m]. These were introduced

34 ft lubricator

1 BOP stack 4 /16-in. Blind rams Shear rams Slip rams Pipe rams

7 2 /8-in. Annular preventer gripper pipe rams 1 7 /16-in. Double- ram BOP Wellhouse work platform

Master valve

Line to plant

12 Oilfield Review a section at a time from the wellhouse work plat- The well is now producing about 4000 BOPD— CT connector form into the wellbore via a 34-ft [10-m] lubrica- by comparison, the best well in the area had pre- 9 in. tor (previous page and below).1 Once all three seg- viously produced 1200 BOPD. Drilling connector 3 ft, 6 in. ments had been successively made up, the entire For ARCO, the well helped prove a number of assembly was ready to be run into the well. technologies: support equipment was field tested; During underbalanced drilling, some oil did deployment procedures and equipment were 6 ft Hydraulic jars flow to surface. To cope with this, the drilling fluid shown to be effective for long tool lengths; the 15 ft, 9 in. was directed through a test separator. Gas was Anadrill SLIM 1 MWD and gamma ray logs pro- separated and returned to the production system vided reliable directional surveys; steering with 14 ft, 3 in. while the polymer mud was cleaned. Cuttings set- the Dowell orienting tool proved effective; and Orienting tool tled in the bottom of the separator. the responses of the three bent-motor BHAs run For a few months, the well produced prolifically during the job helped to better indicate the direc- Nonrotating joint 1 ft, 9 in. compared to its neighbors. Then the open hole tional capabilities of CT drilling. began sloughing, blocking part of the production.

To combat this, the well was reentered and the 1. A number of different drilling platforms and jacking hole underreamed to 4 3/4 in. Then a 2 7/8-in. systems are available for CT drilling. One of the earliest Flow sleeve and simplest examples is described here. predrilled liner was run and hung off in the 4 1/2- Pulsar 15 ft in. tubing at the end of the 7-in. liner. The Nonmagnetic predrilled holes and the end of the liner were drill collar plugged with aluminum, allowing the liner to be safely deployed into the live well. The plugs were Centralizer dissolved using acid once the liner was in place. 30 ft, 6 in. SLIM 1 MWD 70 ft, 9 in. tool with gamma ray n Running in hole for Prudhoe Bay CT drilling jobs. The first of the three BHA sections was installed inside the lubricator in easily handled subsections no longer than 18 ft [5 m]. With the well’s master valve closed, the Gamma ray lubricator—containing the BHA connected to the coiled tubing—was made up to the top of the wellhead blow- 15 ft out preventers (BOP) and pressured up to wellhead pressure. The valve was then opened and the first BHA segment run in hole using the coiled tubing. The 27/8-in. gripper pipe rams of the double-ram BOPs and the annular BOPs were closed around the BHA Battery to ensure isolation from wellbore pressure. After the pressure inside the lubricator was bled down, the CT was disconnected and the lubricator was detached from the BOP and lifted off. The second segment was then installed into the lubricator with enough protruding below to allow its make- Orientation Sub up to the joint of the first section left protruding above the annular preventer. Hydraulic tongs were used to tighten the connection between the first and second segments and the lubricator was stripped over the joint and made up once again above the BOPs. With the pressure equalized, the annular and gripper BOPs were released and the BHA run in hole. The third segment was added in a similar way. 8 ft segment 1 segment 2 segment 3

2 ft

Float sub 1 ft, 6 in. 24 ft, 6 in.

7 2 /8-in. downhole motor 12 ft

3 3 /8-in. bit 1 ft

n Bottomhole assembly divided into three segments, each short enough to be run in hole using the lubricator system.

October 1994 13 The second objective of improving productivity employs underbalanced drilling in new, low-permeability zones. Underbal- anced drilling offers the opportunity to minimize formation damage incurred during drilling and to optimize the productivity of Sidetrack the completion. As the first case study shows, the technique does seem to offer some benefits. Whipstock Underbalanced drilling sometimes helps alleviate other problems like differential sticking.9 Oil production during drilling helps the string slide better and aids hole nYard test example cleaning by carrying cuttings to surface of a sidetrack using more effectively. a 3 1/2-in. whipstock Drilling and directional control equip- inside a hole drilled Window length ment for through-tubing CT drilling is into a cement plug in 6-in. casing. largely proven, although systems require continued refinement and improvement. As higher build rates are achieved, slimmer CT directional tools may be necessary to accommodate through-tubing operations in some existing wells. Bit selection must match the geology, motor specifications and the maximum allowable pumping pressure, while at the same time offer viable rates of penetration with less weight on bit and higher rotation speeds than is normal. Polycrystalline diamond compact (PDC) bits are commonly used in medium-to-soft formations, and thermally stable diamond or natural diamond bits for harder formations. Cement Casing A positive displacement mud motor is used to rotate the bit. Most CT drilling is performed using motors with a diameter less It would, however, be wrong to say that The challenge today is to achieve all this than 31/2 in, such as Anadrill’s 27/8-in. Pow- all the mechanical challenges of drilling through tubing. erPak steerable motor. have been met. For example, transmitting A conventional kick-off technique uses a For directional control, Dowell uses an sufficient weight to the bit can be problem- whipstock plug—a long, inverted steel orienting tool operated by mud-pump flow atic. Since it is impossible to rotate the CT wedge that is set in the wellbore and diverts rate to alter the tool face. Anadrill’s SLIM 1 from surface, it is often difficult to overcome the drillstring toward the side of the hole to MWD system coupled with a gamma ray axial friction along the length of the CT, par- initiate a sidetrack. To achieve this through log is used to monitor the wellbore’s ticularly in deviated wells. Because of this, tubing on Prudhoe Bay wells requires a progress through the formation in real time. the weight applied at surface frequently whipstock that will pass through the 3 3/4-in. Data are transmitted to surface using con- becomes “stacked up” against the borehole minimum restriction inside the tubing but sit ventional mud-pulse techniques. wall instead of reaching the bit. This phe- firmly and reliably inside the casing below There are systems available that use wire- nomenon is well known for slide drilling, that has an inside diameter (ID) of more than line inside the coiled tubing. These can but is exacerbated by the flexibility of the 6 in. So far, this has proved difficult to transmit directional data to surface at a CT and increases with the sidetrack angle. achieve. Various solutions have been pro- higher rate than mud-pulse tools and hold Numerous solutions have been proposed, posed and are being field tested. One system the potential to provide electrical power to including hydraulically activated “crawlers” uses an articulated whipstock that unfolds activate downhole tools. However, installa- that grip the borehole wall and pull the CT once it has passed through the tubing, tion and maintenance of the cable increase into the hole, and hydraulic thrusters that enabling it to reach across larger ID casing. drilling costs. apply weight by pushing on a slip joint or In case the bottomhole assembly gets piston just above the bit. As yet, neither sys- 9. Rike A: “Drilling With Coiled Tubing Offers New stuck, a hydraulic or shear release tool tem offers a complete solution. Alternative,” The American Oil & Gas Reporter 36, no. 7 (July 1993): 20-26. allows the coiled tubing string to be discon- Another area under intense development 10. The Danish Underground Consortium is a consor- nected and recovered in one piece. A flap- centers on using CT techniques to mill a tium of Mærsk Olie og Gas, Shell and Texaco. per valve just above the disconnection point window in the existing casing and sidetrack Mærsk is the operator. prevents any wellbore pressure from enter- out of the well. In 1992, ARCO Oil & Gas Andersen SA, Conlin JM, Fjeldgaard K and Hansen SA: “Exploiting Reservoirs With Horizontal Wells: ing the CT string. was involved in a West Texas well where The Mærsk Experience,” Oilfield Review 2, no. 3 coiled tubing was used to plug back the (July 1990): 11-21. well, mill a window and drill new wellbore. 11. Externally upset equipment has its tool joints on the outside, irregularly increasing the outside diameter 14 of the completion string. Dowell is currently developing two other more it is liable to suffer from fatigue during Delivering Coiled Tubing Completions solutions: horizontal drilling. The availability of larger CT—up to 31/2-in. •A hard and nonbrittle proprietary cement But another important parameter affects diameter—has sparked interest in another plug is set downhole so that a CT milling CT durability: the internal tubing pressure at major advance: underbalanced coiled tub- assembly is deflected against the casing the time of bending. The higher the pres- ing completion. Like CT drilling, this uses wall to cut a window—two field tests sure, the greater the fatigue. This, too, is the coiled tubing unit’s well control capabil- have been carried out so far. related to the tubing diameter because inter- ity to safely run the completion. There are •The inside diameter of the casing is nal pressure depends on the flow rate two basic CT completion options. reduced to accommodate a normal but required to drive the downhole motor, One choice is externally upset comple- slim whipstock that passes easily through which is a fixed value depending on the tion strings, which incorporate traditional the production tubing. motor type and diameter. Larger diameter completion hardware like gas-lift mandrels, In this second solution, a conventional tubing can achieve the required flow rate at landing nipples, sliding sleeves and safety cement plug is set in the liner below the a lower internal pressure than its slimmer valves in the CT string.11 To safely run these tubing. With CT, an oriented 33/4-in. hole is counterpart, thus reducing fatigue. strings into a live well, a window system drilled against the side of the casing through In short, there is an optimum tubing size may be employed. This window allows the which the sidetrack must go. Then a 31/2-in. for any flow rate, and therefore for any BOPs and the injector head to be separated, whipstock is run on coiled tubing. An MWD given motor. All these factors, and many giving enough room for the coiled tubing to system and orienting tool ensure that the others, are taken into consideration by be cut and the various completion devices whipstock is set in the hole in the cement Dowell’s design software when planning the installed. While this is happening, the annu- plug so that its face is adjacent to the casing drilling program and choosing the bottom- lar and ram BOPs seal off any pressure from wall. This is then drilled in the usual way to hole assembly and CT type. To date, the the well below (below). kick off the well (previous page). reduced life expectancy of coiled tubing A more rapidly deployable alternative is Development of CT drilling is not exclu- larger than 23/8 in. limits its use for CT to use compact completion equipment that sive to Alaska. For example, in the North drilling in horizontal wells. may be placed inside the tubing itself. Sea, the Danish Underground Consortium is turning to the technique as an alternative to its pioneering strategy based on long, conventionally drilled horizontal sections completed so that many individual zones 10 may be separately fractured. Because Gooseneck these stimulation treatments and all the associated hardware can be expensive, operator Mærsk Olie og Gas believes that a network of slimhole wells drilled quickly Injector head and underbalanced with coiled tubing may be more cost-effective. To evaluate this development strategy, Dowell and Anadrill drilled the first successful CT drilling offshore development well in the North Sea. The well was completed in Access window May 1994 on Mærsk’s Gorm platform and initially produced some 3000 BOPD—up to four times the anticipated level (see “CT Slip bowl Drilling Offshore Denmark,” next page). To date, CT drilling has not been used as a Annular BOP major exploration drilling tool. One factor that limits its usefulness for exploration BOP rams drilling is the maximum openhole diameter possible. This is increasing as larger diame- Valve Coiled tubing ter coiled tubing becomes available. With hanger bowl 3 2 /8 -in. tubing, a vertical open hole of up to Casing hanger 81/2 in. may be drilled. Because it is stiffer and can extend farther before lock up, larger nExternally upset completion rig up with an access window below the injector head diameter CT also allows longer horizontal and above the BOPs. With the BOPs closed to seal off the live well, components may be sections to be drilled. However, horizontal connected to the CT and moved into the wellbore. Then the window is closed, the BOPs opened and the components run in hole. When another piece of completion hardware drilling necessitates more trips into the well is needed, the BOPs are closed and pressure bled off above. The window may then be and more cycling of the CT over the goose- reopened, the CT cut and the hardware connected. This process is repeated each time neck. And the larger the CT diameter, the a completion component is added to the string.

October 1994 15 CT Drilling Offshore Denmark

The first successful North Sea CT-drilled well employed “just balanced” drilling to deliver 31/2-in. open hole.

Vertical Section 5000

37° Build and turn @3.5°/100 ft 5500

46° Start hold 6000

46° Start build and turn @3.5°/100 ft

Depth, ft 6500 55° Start hold 55° Start build @5.5°/100 ft 83° Start tangent 7000

7500 0 1000 2000 3000 4000 5000 Horizontal step-out, ft Horizontal Plan 0

N 1000

2000 ft

3000

4000

5000 1000 2000 3000 ft

This is the first of a number of wells to determine For this first attempt, the coiled tubing unit was nDanish drilling. The vertical (top left) and horizontal the usefulness of CT drilling for the Danish Under- located on the jackup rig Mærsk Endeavour, (bottom right) plans of the Gorm field CT-drilled well using the Dowell orienting tool in conjunction with ground Consortium’s North Sea wells. Some 3309 which drilled to approximately 7690 ft [2344 m] Anadrill’s SLIM1 MWD system. Drilling using 2-in. ft [1008 m] of horizontal 3 1/2-inch wellbore was measured depth where the 9 5/8-in. casing was coiled tubing commenced just below the completion, at successfully drilled into the chalk formation using set and cemented. The casing shoe was drilled 7690 ft. The angle was built to approximately 85°, which was then held until the bottom of the reservoir 2-inch coiled tubing at a maximum deviation of out and a 41/2-in. completion string was run to was approached when the inclination was increased to 89°. This was more horizontal length than was just below the casing shoe. 89°. The total horizontal displacement from the rotary planned and the measured depth at the completion Drilling was restarted using 2-in. coiled tubing table was 4766 ft. The azimuth was built from 160° to a of the drilling was 11,000 ft [3352 m]. (above). Although CT drilling took 19 days for the maximum of 203° before turning back to the left. The photograph (top right) shows the CT injector 3309-ft section, most of this time was spent in head in the rig’s drawworks. The photo at the bottom the first few hundred feet where unexpected, left is an aerial view of the CT equipment on the deck.

16 Oilfield Review Externally Upset Completion SPOOLABLE Completion

Control line hanger

Coiled tubing hanger chert beds were encountered. Several bits were Coiled tubing hanger with slips and pack-off set used in this formation including natural diamond Spool and PDC bits, both of which were ineffective. Dia- mond speed mills and finally small tricone insert Control line bits were used to drill the last feet of chert to get Coiled tubing into the reservoir. While drilling through the Control line softer formation in the reservoir, a PDC bit was Safety valve used and it took just 7 days to drill the final 2600 ft [792 m].

The intention had been to drill the reservoir Safety valve Gas-lift valves underbalanced. However, true underbalance proved difficult to maintain as the hole tended to slough, creating sticking problems. Therefore, most of the drilling took place with the gas lift creating a “just balanced” situation. This was aided by a surface read-out gauge that relayed Gas-lift mandrel the pressures at the bottom of the completion and valve tubing. However, the final 1000 ft [300 m] of well Locator seal assembly were drilled underbalanced. Polished bore receptacle Reservoir fluids entering the mud were han- Locator seal assembly Flapper dled at surface using conventional surface test hardware—such as chokes, separators and heat Packer exchangers. This is an element of the operation that operator Mærsk believes needs further Nipple development.

Both 27/8-in. and 3 1/8-in. motors were employed to good effect. Since it was necessary nComparing completion systems. Externally upset completions must be made up on- site as they are run in hole. SPOOLABLE completions may be made up off-site and run to steer along the entire 3300-ft section, several in the well conventionally using the reel. trips were made to adjust the motor angles. SPOOLABLE coiled tubing completion coiled tubing. All the wells were about As with the Alaskan wells described on pages equipment developed by Camco Products & 9000 ft [2740 m] deep and all the comple- 11 and 19, directional control was achieved using Services is flexible enough to bend over the tions included a 10-ft [3-m] seal assembly, the Dowell orienting tool in conjunction with the CT reel (above). The whole completion landing nipples and a tubing hanger. On- SLIM 1 system. The orienting tool worked well, string may be assembled and connected to location time improved dramatically with although it was sometimes time-consuming. the CT at the manufacturing plant or work- each job. The first well took 40 hours, the shop, increasing operational efficiency and last just 25 hours. When gas lift was used during drilling, the mud in safety while reducing environmental haz- the annulus became lighter than the mud inside ards. Once on location, the CT and comple- 12. Moore BK, Laflin WJ and Walker EJ: “Rigless Comple- the CT. Consequently, it took longer than usual to tion hardware are simply spooled off the tions: A Spoolable Coiled-Tubing Gas Lift System,” orient the tool face because each time the pumps reel over the gooseneck and run into a live paper OTC 7321, presented at the 25th Annual Off- shore Technology Conference, Houston, Texas, USA, 12 were shut down, the heavier fluid flowed to well with standard equipment. May 3-6, 1993. As with other coiled tubing-related issues, equalize pressure with the lighter before down- Lidisky DJ, Pursell JC, Russell WK, Dwiggins JL and ARCO is using CT in Prudhoe Bay to Coburn GS: “Coiled-Tubing Deployed Electric Sub- hole hydrostatic pressure stabilized. mersible Pumping System,” paper OTC 7322, pre- broaden its completion options. ARCO ran sented at the 25th Annual Offshore Technology Con- the first completion using 2-in. coiled tubing ference, Houston, Texas, USA, May 3-6, 1993. in 1990. Today, 31/2-in. tubing is used (see Dowell and Schlumberger Wireline & Testing have “Combining CT Drilling and Reeled Com- recently formed an alliance with Camco International. This unites Camco’s diverse equipment with Schlum- pletion,” page 19) and the company reports berger’s complementary services and products. that running times for installing such com- 13. Blount CG and Hightower CM: “Advancements in pletions are being cut with each job.13 Coiled Tubing Drilling and Completions Technology in Prudhoe Bay, Alaska,” presented at the 2nd Annual For example, six Alaskan injector wells World Oil Coiled Tubing Conference and Exhibition, were recently completed using 31/2-in. Houston, Texas, USA, March 29-31, 1994. October 1994 17 Depth encoder mounted on injector head

Coiled tubing unit depth monitor Logging data from reel collector 000.0

Junction box Dowell data recording system

Depth signal sent to logging unit

nDepth correlation between coiled tubing and logging units.

Logging and Perforating with information is also used by the Dowell hole logging—whether the wells were Coiled Tubing monitoring system that records coiled tub- drilled using CT drilling or conventional Like CT drilling, coiled tubing logging has ing and pumping parameters. techniques—has been limited by the avail- come of age only in the 1990s. One of its A newly designed coiled tubing head is ability of slimhole hardware. Now that key selling points revolves around the stiff- now available to attach the logging tools to scope is broadening. ness of the tubing, enabling penetration into the CT. The modular head secures the cable Originally, slimhole logging tools were horizontal and high-angle sections. Addi- in place, allows fluid to be circulated developed to gather petrophysical informa- tionally, wireline inside coiled tubing offers through a dual flapper valve during logging, tion in deep, usually hot, wells that required the potential to pump fluids downhole and and provides for electrical connection and extra strings of casing, thereby reducing the log at the same time.14 mechanical release. final well diameter. Alternatively, they were Successful application of CT logging Fundamentally, a CT logging operation is needed to log through drillpipe under diffi- requires the reliable interface of the coiled not much different from its wireline counter- cult hole conditions. These rigorous envi- tubing and logging units. Wireline log part. However, the tubing is stiffer than ronments ensured that such tools were of acquisition systems are driven by depth. To wireline so it tends not to stretch as much, necessity simple, reliable and rugged. supply real-time depth data for CT logging, and the injector head provides a stable Today, CT drilling and slimhole wells are an encoder relays a depth signal from the speed. Coiled tubing may deploy most log- being used, or contemplated, for a broader injector head into the logging unit through a ging tools, as long as they are slim enough dedicated interface (above). This depth to fit inside the wellbore. The scope of slim- 14. Ackert D, Beardsell M, Corrigan M and Newman K: “The Coiled Tubing Revolution,” Oilfield Review 1, no. 3 (October 1989): 4-16.

18 Oilfield Review Combining CT Drilling and Reeled Completion

Well drilled overbalanced and completed using 2-in. and 31/2-in. coiled tubing, respectively.

Like the well described on page 11, Well 2044 ft—subsurface safety valve nipple 18-23A is operated by ARCO in the Prudhoe Bay field. This time, the well was not only sidetracked 2753 ft—gas-lift mandrel using CT drilling, but also completed using 3 1/2-in. coiled tubing (right). 4864 ft—gas-lift mandrel A rig was used to pull the completion and side- 1 track out of the old wellbore, drilling toward the 3 /2-in. coiled tubing new well location but stopping when a horizontal 5174 ft—landing nipple inclination was achieved in the target zone. CT 5176 ft—production packer drilling was then used to drill horizontally through the pay zone. Because the rig did not install any gas-lift hardware, the well was drilled overbalanced. The result was a horizontal section some

800-ft [240-m] long with a 4 3/4-in. diameter. 9081 ft—landing nipple With 2-inch coiled tubing and conventional CT 9082 ft—liner packer 9100 ft—landing nipple 7 well control equipment, a 2 /8-in. preperforated, 1 9618 ft—5 /2-in.shoe plugged liner was run and hung off in a 3-in. by 7 5 1/2-in. packer inside the 5 1/2-in. liner. The com- 10,401 ft—2 /8-in. float shoe pletion assembly—which included an indexing mule shoe, a locator seal assembly, landing nip- 3 4 /4-in. open hole ple, two gas-lift mandrels and a second landing

nipple—was installed onto the 3 1/2-in. CT and then pressure tested. The assembly was then run

in hole and stabbed into the completion packer. 10,405 ft TD The well was placed on production at 3900 17 joints 28 joints BOPD and that rate subsequently increased to blank /514 ft plugged liner/784 ft 4600 BOPD—compared to 1200 to 1500 BOPD from a nearby conventional well. nCT completion. The Alaskan Well 18-23A was completed using 3 1/2-in. coiled tubing. range of well types that have more sophisti- To date, coiled tubing is most often used respond to changes in well behavior. A typi- cated needs. To meet these needs, many for production logging, sometimes com- cal CT production logging job involves the standard and new high-technology imaging bined with CT-conveyed perforation. As following steps: tools have been reengineered to operate in usual, the production logging tool string •Rig up and pressure test equipment. more restricted boreholes. For example, the measures a range of parameters, including •Run in hole stopping to check CT weight. DLL Dual Laterolog Resistivity tool and the spinner revolution, fluid density, pressure •Correlate depth with a reference log using combinable Litho-Density tool have been and temperature; a gamma ray tool and a casing-collar correlation and gamma ray repackaged with diameters of 23/4 in. and casing-collar locator are also included. logs—vital because the CT tends to form a 31/2 in., respectively. Production logging of high-angle or hori- helix in the well. In addition, new instruments have been zontal wells presents a tremendous chal- •Log the well while shut in. designed, such as the SRFT Slimhole Repeat lenge. For example, there may be stationary •Log in both directions with typically four Formation Tester tool for sampling the for- fluid, back- or cross-flow—some zones may passes at say 40, 60, 80 and 100 ft/min mation, the sourceless RST Reservoir Satura- be accepting fluid produced by other zones. tion Tool, and the Pivot Gun for slimhole Only a fraction of the fluids “seen” by the perforation. Combinability of tools and tools may actually be moving. To overcome coiled tubing logging capability are stan- these difficulties, the production logging dard features. program must be sufficiently flexible to

October 1994 19 [12, 18, 24 and 30 m/min] with the well CT Logging and Perforation in Alaska flowing. The intervals between data col- lection may be decreased or the logging Coiled tubing logging located zones offering potential additional pro- speed increased. duction that were perforated using CT-deployed guns. • Observe well anomalies, making some stationary log measurements to look for backflow. CCL Pressure • Pull out of hole. Another production-related CT logging –19 (V) 1 1100 (PSI) 1100 Gamma ray service employs pulsed neutron logs and Temperature 0 (GAP) 200 1:600 175 185 borax solution. The borax is pumped into ft (DEGF) the CT-production tubing annulus at a pres- Well flowing sure above that of the reservoir but below 12,200 the fracturing pressure. Because borax is more effective than reservoir fluid at slow- ing neutrons, pulsed neutron logs can trace where it has gone and hence confirm the location of a suspected channel and indicate high-permeability zones. With additional openhole log data, initial reservoir 12,300 saturation information may also be derived. After the production profile of a well and potential hydrocarbon saturated zones have Suspected gas been identified, reperforation using CT-con- producing zone veyed guns may be necessary (see “CT Log- ging and Perforation in Alaska,” right).

Matrix Treatment 12,400 The most traditional of all coiled tubing services is the delivery of fluids downhole. No account of the practical uses of coiled tubing would be complete without describing Suspected gas producing zone at least one pumping application—a role that has become more important with the proliferation of horizontal wells. 12,500 As in other areas, increasingly sophisti- 13,400 cated pumping services are available. For example, a relatively new matrix treatment tackles an old problem, diversion. Unless a stimulation fluid is successfully diverted into the areas that most need it, the fluid will channel into the high-porosity, high-permeability formation that least requires improvement. Horizontal wells generally have a 13,500 much longer reservoir section than their vertical counterparts, so the problem of diver- Suspected gas sion is proportionally more difficult. To producing zone compound this, few horizontal wells are completed in a way that allows even rudi- nTemperature log using coiled tubing. Production from this virtually horizontal well proved to have a higher mentary zonal isolation. GOR ratio than expected. From this log suspected gas producing zones are estimated to be at a measured Traditionally, diverting materials—like cal- depth of 12,335, 12,450 and 13,530 ft. cium carbonate or rock salt—are introduced So far, ARCO’s sector of the Prudhoe Bay field has perforating guns were used to open up potentially to temporarily plug the zones of the forma- run 12 coiled tubing logging jobs in eight highly productive zones. tion taking most fluid, redirecting flow to more needy parts of the wellbore. But the deviated or horizontal wells. The aims of these Well 15-07A exemplifies the jobs performed in plugging must be reversible—by dissolution jobs were to obtain the production profile and ver- Alaska. It is a virtually horizontal well completed in acid or reservoir fluids—and leave the ify the presence of channels using pulsed neutron with a 4 1/2-inch slotted liner at a total vertical depth formation undamaged. Not an easy criterion logs. Where necessary, coiled tubing-deployed of 8761 ft and a measured depth of 13,545ft. to meet. Drilled as a sidetrack to a much older well and completed earlier this year (April 1994), the well

20 Oilfield Review was found to be producing lower rates of oil at a SIBH much higher gas-oil ratio (GOR) than was antici- 200 (CU) 0 pated. Coiled tubing logging was used to deter- CCL INFD –19 (V) 1 0 (CPS) 1200 mine the source of the gas production, to identify Gamma ray SIGM any nonproductive intervals and to tie in with pre- 0 (GAP1) 100 40 (CU) 0 vious logs using gamma ray, casing-collar locator and temperature logs. 12,000 Gas entry was located using the temperature Tubing log (previous page). Then, using pulsed neutron tail logs in conjunction with borax injection, the gas- oil contact was located and a possible channel Estimated behind the 7-in. liner indicated (right). gas-oil contact Finally, CT was employed to perforate the 7-in. 12,100 liner to contact potentially bypassed intervals.

Some 20 ft [6.5m] of 2 1/8-in. guns were run in hole and detonated using a hydraulic firing head. Depth was correlated using a tubing-end locator. The CT perforation used a new pressure-activated firing head. It allows circulation and reverse circulation before and after firing the 12,200 guns. An operating piston is attached to a sleeve Perforated bypassed that locks the firing pin in place. When sufficient interval differential pressure is established across this piston to sever the shear pins that hold it in place, the firing pin is driven into the detonator

by the pressure. 12,300 To establish this differential pressure, a ball is pumped down the tubing to form a pressure seal Packer in the head. The ball diverts pressure to the ported pipe underside of the operating piston, building up the pressure that severs the shear pins and detonates the guns. Up to twelve 500-psi shear pins can be incorporated into the head. 12,400 Suspected A key advantage of coiled tubing is its higher channel tensile strength than wireline. So, when it comes to perforation, there is no practical weight limit to the number of guns that can be run. The main constraint on gun length is the height of the lubricator. However, the downhole safety valve may Total fluid injected before each borax pass: 65 bbl before pass BS1 PS1 - Base pass #1 (red) BS1 - Borax pass #1 (red) be closed and successive sections of guns run 76 bbl before pass BS2 PS2 - Base pass #2 (green) BS2 - Borax pass #2 (green) into the well and connected together. 100 bbl before pass BS3 PS3 - Base pass #3 (blue) BS3 - Borax pass #3 (blue)

nPulsed neutron logs made in conjunction with borax injection. Three logging passes were made during seawater injection as a base log and then three more after the injection of borax solution. Interpreting the result, ARCO located the gas-oil contact at 12,077 ft and a possible channel behind the 7-in. liner at 12,370 to 12,450 ft.

October 1994 21 A successful alternative employs stable Matrix Treatment in Alberta foam that is generated in the “thief zones” as a diverter. Alternating stages of acid and the CT-conveyed FoamMAT treatment added an estimated deliverability foam—made from water containing surfac- of 2 to 6 million scf/D. tant and nitrogen—are pumped.15 The diverter enters the formation that is taking fluid. Some 10 minutes or so are allowed for This case concerns a Suncor Inc. operated gas Consequently, extensive compatibility tests the foam to build up and, when pumping well, Pine Creek 10-1-56-19-W5M, in Alberta, were run between the mud and proposed acid sys- restarts with a new acid stage, a pressure increase is seen at surface as the foam Canada. It has a 2493-ft [760-m] horizontal sec- tems. The final treatment design included a num- ensures the acid enters some other part of tion, drilled through the carbonate reservoir above ber of stages: the formation. Pressure gradually decreases the water leg to a measured depth of 14,935 ft • tubing pickle, which is used to clean up the until it is time to pump the next foam stage. [4552 m]. inside of the coiled tubing—15% hydrochloric Once production starts, the foam breaks Unlike the usual situation, the best porosity of acid [HCl], inhibitor and surfactant down and flows out of the well leaving undamaged, acidized formation. the horizontal section was believed to be at the toe • preflush, to thin the mud in the wellbore—frac- Coiled tubing is an ideal way of targeting of the well rather than the heel. However, it was turing oil, antisludge agent and nitrogen, creat- the delivery of the treatment fluids to the also believed that these high-potential zones had ing a foam with a quality of 50%1 formation, particularly in horizontal wells. been invaded by drilling mud filtrate. To enhance • Mudclean OB solution, to flush out any remain- Furthermore, because the volume inside CT productivity, it was important to ensure that the ing mud in the well and water-wet the formation is relatively small, a flexible treatment pro- acid was pumped into the toe of the well to open prior to the FoamMAT job—water, surfactant gram may be employed, based on pressure responses observed during pumping (see up fractures and allow the mud to flow out. and solvent as a foam of 50% quality “Matrix Treatment in Alberta,” right). To create the required diversion, it was decided • diversion stages—water and surfactant with to pump a FoamMAT treatment. Foam is pumped nitrogen as a 65% quality foam Looking to the Future into the formation, blocking further entry of the • squeeze acid—15% HCl, with inhibitor, surfac- This tour of coiled tubing applications has acid and diverting it to unstimulated reservoir. To tant, de-emulsifier, antisludge agent, miscible concentrated on events in Alaska and the North Sea. But all over the world operators minimize friction when pumping at the necessary solvent and H2S scavenger. The total volume of and service companies are using coiled tub- rate, 2-in. coiled tubing was used to deliver the the acid, some 33,025 gal [125 m3], was deter- ing for a range of tasks that would have fluids. The relatively large CT diameter also mined by a rule of thumb and past experience of been inconceivable only a few years ago. helped avoid lock-up when running into the long a FoamMAT job carried out on a nearby oil well. As larger diameter tubing and the avail- horizontal section and offered more pulling poten- • postjob flush—fracturing oil and nitrogen. ability of hardware needed to handle it tial if the string had become stuck. Having pickled the CT and negotiated some become more widespread, even more services will be devised and current ones The downhole assembly consisted of a nozzle, problems running in hole caused by a hydrate improved. For example, conventional direc- two memory gauges separated by a knuckle joint, plug, the preflush was pumped with the CT on bot- tional CT drilling techniques will be and a check valve. The knuckle joint added tom—at the end of the toe. Once all the preflush replaced by geosteering. CT completion sys- flexibility to an otherwise stiff assembly. Data had been displaced across the open hole, the well tems will be refined and costs reduced. Log- collected by the gauges were used after the job to was shut in for about 15 minutes to allow it to soak ging with CT will become more extensive. Rigless well workover operations will analyze the buildup and breakdown of the forma- and then flowed back to recover any mud filtrate. become increasingly widespread. tion as successive diversion and acid phases Next the Mudclean OB stage was pumped down- If they weren’t so busy coping with the were pumped. hole and displaced using nitrogen. The well was present, coiled tubing engineers could look A number of factors complicated the choice of then allowed to flow to clean up and another stage forward to the future with excitement. —CF acid additives—which is crucial to the success of was pumped. any matrix treatment. First, as already noted, Sun- When this had been displaced out of the well,

15. Crowe C, Masmonteil J and Thomas R: “Trends in cor suspected that the formation had been invaded the main treatment commenced. A series of 15 Matrix Acidizing,” Oilfield Review 4, no. 4 (October by significant quantities of mud filtrate, which con- alternating acid—1585 gal [6 m3]—and diverter 1992): 24-40. tained a strong emulsifier likely to form an emul- —400 gal [1.5 m3]—stages were pumped at 25 to sion with spent acid. Second, the presence of 25% 80 gal/min [0.1 to 0.3 m3/min]. At the same time,

hydrogen sulfide [H2S] in the well necessitated the use of corrosion-control additives that may react with other chemicals in the fluid.

22 Oilfield Review Duvernay Zone Temperature Limestone 118 (DEGC) 128 Shale Temperature derivative –17.75 (DEGC) –17.85 Minimum distance Wellhead pressure 5000 (KPA) 11000 Beaverhill lake Flowing pressure 21000 (KPA) 25000

Minimum distance from boundary

3650 3750 3850 3950 4050 4150 4250 4350 4450 4550

Depth, m

the coiled tubing was gradually pulled out of the The well was opened up to flow with the nLog data from Suncor’s FoamMat stimulation job hole—at about 10 ft/min [3 meters/min]—from gauges still on bottom. During cleanup, the well tied into a well profile. This shows a derivative of the temperature log while the well was flowing after the the toe to the heel of the well. After pumping a flowed spent acid and an estimated 21,000 gal FoamMat stimulation. Interpretation is difficult, but diverter stage, the pumps were shut down for 10 [80 m3] of mud filtrate. Suncor believes that this the most likely explanation is that there was good minutes before the next acid was pumped. mud came out of the natural fractures of the for- production from the interval at 3760 to 3810 m, and possibly 3860 to 3880 m, 4000 to 4035 m, 4190 to Midway through the job, the well went on a mation. Once the well was cleaned up, the well 4210 m, 4265 to 4290 m and 4420 to 4450 m. How- vacuum. To maintain a positive surface pressure pressure and temperature were logged using the ever, during the initial flowback, significant quantities and gain maximum information about the treat- memory gauges (above). of mud filtrate also flowed and this may be masking ment, it was necessary to reduce the bottomhole The well is currently waiting to be brought into effects of gas flow in the well. hydrostatic pressure. The foam qualities of the production, but Suncor estimates that the acid two fluids were adjusted so that the diverter was treatment reduced the pressure drop across the 70% and the acid 25%. reservoir by 435 to 725 psi. By comparing this to Surface pressure was plotted throughout the pretreatment pressure and rate information, addi- job to assess the success of the diversion stages. tional gas deliverability due to the treatment is Once all the acid was pumped, the CT was run likely to be 2 to 6 million scf/D. back to the toe of the well and the postjob flush 1. Foam quality is defined as the ratio of the volume of gas was pumped to break up the foam in the wellbore in the foam to the total volume of foam—expressed as and hasten the cleanup. a fraction or as a percentage. So a nitrogen-water foam of 75% quality contains 75% by volume nitrogen and 25% by volume water (at downhole conditions).

October 1994 23