Coiled Tubing: The Next Generation PDF

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Coiled Tubing: The Next Generation Ali Chareuf Afghoul Building on a technological resurgence during the 1990s, this unique well-intervention Zakum Development Company (ZADCO) Abu Dhabi, United Arab Emirates technique firmly established a place in mainstream operations. We review advances in surface...

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Coiled Tubing: The Next Generation

Ali Chareuf Afghoul Zakum Development Company (ZADCO) Abu Dhabi, United Arab Emirates Sridhar Amaravadi Stavanger, Norway Abderrahmane Boumali Sonatrach Algiers, Algeria

Building on a technological resurgence during the 1990s, this unique well-intervention technique firmly established a place in mainstream operations. We review advances in surface equipment and downhole tools that increase operational efficiency and safety, improve wellbore and reservoir remediation methods, and also facilitate drilling and completing wells with coiled tubing.

João Carlos Neves Calmeto Petrobras Rio de Janeiro, Brazil Joe Lima John Lovell Scott Tinkham Kean Zemlak Sugar Land, Texas, USA Timo Staal Inverurie, Scotland For help in preparation of this article, thanks to Marc Allcorn, Rex Burgos, Luis Cabanzo, Lambert Dilling, Frank Espinosa, Richard Luht, Robin Mallalieu, Mark Oettli, Radovan Rolovich, Stuart Wilson and Warren Zemlak, Sugar Land, Texas, USA; Tommy Andreassen, BP, Stavanger, Norway; Alastair Buchanan, Stavanger, Norway; Curtis Blount, ConocoPhillips Alaska, Inc., Anchorage, Alaska, USA; Jeremy Kinslow, Rock Springs, Wyoming, USA; Ronald Knoppe, Shell Internation Exploration and Production B.V., Rijswijk, The Netherlands; Jerry Murphy, Kellyville, Oklahoma, USA; Randal Pruitt, BP-Sharjah, United Arab Emirates; Iuri Frederico de Oliveira Santos, Macae, Brazil; and Jodi Wood and Jamal Zakaria, Hassi Messaoud, Algeria. Blaster, Bridge Blaster, CoilCADE, CoilCAT, CoilFLATE, CoilFRAC, CoilLIFE, CoilSAFE, CoilTOOLS, CT Sim, CT EXPRESS, CT InSpec, CT SEAS (Coiled Tubing Safer, Efficient Automated Solutions), DepthLOG, Discovery MLT, FIV (Formation Isolation Valve), Friction Deployed, IIC (Intelligent Injector Control), InterACT, Jet Blaster, MultiSensor, OptiSTIM MP, OptiSTIM ST, Phoenix, PipeSAVER, PowerCLEAN, REDA, REDACoil, Scale Blaster and Sterling Beads are marks of Schlumberger.

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Once considered high-risk and applicable only for niche services, coiled tubing (CT) is now an essential tool for many well-intervention operations. In the late 1980s and throughout the 1990s, this technology gained wider acceptance among operators because of its ability to reduce overall costs, greatly improved reliability and an expanding range of applications, which resulted in significantly increased CT activity (next page).1 Used generically, coiled tubing describes continuous lengths of small-diameter steel pipe, related surface equipment and associated workover, drilling and well-completion techniques. Since its introduction to oilfield operations in the early 1960s, CT utilization has increased because of better manufacturing, larger tube diameters and advances in equipment that improved operational efficiency (see “A History of Coiled Tubing,” page 42). Coiled tubing is spooled onto a reel for storage and transport. These strings can be 31,000 ft [9,450 m] long or more, depending on reel size and tube diameters, which range from 1 to 41⁄2 in. A hydraulic power pack, or prime mover, controlled from a console in a central control cabin

drives the injector head to deploy and retrieve coiled tubing. The large storage reel also applies back-tension on the tubing. The continuous tubing passes over a gooseneck and through an injector head before insertion into a wellbore through well-control equipment that typically consists of a stuffing box, or packoff, riser and blowout preventer (BOP) stack on top of the wellhead. This process is reversed to retrieve and spool coiled tubing back onto the reel. Modern CT equipment and techniques have several advantages over conventional drilling, workover and snubbing units. These include quick mobilization and lower cost, expedited operations with no need to stop and connect tubing joints, and reasonably high load capacities for deeper vertical and high-angle reach compared with wireline and slickline. The flexibility of working under pressure in “live” wells without killing a well and the unique capability to pump fluids at any time regardless of position in a well or direction of travel are also advantages.

Oilfield Review

Well cleanouts Fishing Jetting fluids Acidizing Better injector heads 1,500-ft steel stock Improved manufacturing 1 1⁄4-in. tube HSLA steels 1 1⁄2-in. tube 1 3⁄4-in. tube 3,000-ft steel stock Bias welding 2-in. tube Logging and drilling 2 3⁄8-in. tube 2 5⁄8-in. tube HPHT services 2 7⁄8-in. tube 3 1⁄2-in. tube 4 1⁄2-in. tube Scale removal Selective stimulation Multilateral access Advanced onshore units HPHT inflatable packers Wireless depth control Advanced offshore units Optimized cleanouts

1,200

Worldwide CT unit count

1,000

Gooseneck

800

600

400

200

Injector head 0 1965 1972 1978 1987 1988 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Blowout preventer stack Control cabin

Tubing reel

> Coiled tubing activity—1965 to the present. Development of continuous tubulars began in World War II with project PLUTO (Pipe Lines Under The Ocean) in 1944. In the 1960s, coiled tubing (CT) was used to wash out sand, retrieve subsurface safety valves and lift fluids out of wells with nitrogen. Later, CT applications expanded to include acid and fracturing treatments, tool conveyance, tubing replacement, drilling, artificial lift and well completions. As a result, the number of CT units operating worldwide increased from a few in 1965 to more than 1,000 in 2004.

These capabilities are especially useful in wellbore cleanouts, jetting with inert gases or light fluids, perforation acid washes, acid or fracture stimulations and sand-consolidation treatments, cementing, fishing and milling, underreaming and underbalanced drilling. Adding an electric line, data or power cables inside coiled tubing strings facilitates well logging, downhole monitoring or control, directional drilling and electrical submersible pump (ESP) installations. Deeper high-angle wellbores are increasingly common and many are beginning to require remedial interventions. Going into deeper wells

Spring 2004

increases coiled tubing weight, requiring stronger pipe and injector heads plus improved fluids.2 CT is a viable option for these demanding remedial operations, but detailed planning is required to ensure job safety and efficiency. Better tubular manufacturing and quality control had a significant positive impact, but equipment optimization and improved operational techniques and procedures have been equally important in improving CT performance and reliability. This article reviews the latest developments in CT wellsite efficiency, wellbore and reservoir remediation applications, new downhole tools, reentry and underbalanced drilling operations and artificial lift.

1. Ackert D, Beardsell M, Corrigan M and Newman K: “The Coiled Tubing Revolution,” Oilfield Review 1, no. 3 (October 1989): 4–16. Bigio D, Rike A, Christensen A, Collins J, Hardman D, Doremus D, Tracy P, Glass G, Joergensen NB and Stephens D: “Coiled Tubing Takes Center Stage,” Oilfield Review 6, no. 4 (October 1994): 9–23. 2. Hodder M, Michel C, Kelligray D and Bailey L: “Investigation of Polymeric and Mixed Metal Oxide Fluids for Use in Well Intervention Operations,” paper SPE 89637, presented at the SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, USA, March 23–24, 2004.

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> A Valhall platform, North Sea Norwegian sector. The new CT SEAS unit performs perforating and wellbore cleanout operations before and after proppant fracturing treatments in the BP Valhall field offshore Norway.

Wellsite Efficiency A feasibility study in 2001 and subsequent engineering efforts resulted in a new offshore CT unit, which was launched in 2003. The automated, modular CT SEAS Coiled Tubing Safer, Efficient Automated Solutions system was first installed on a BP Valhall field platform in the North Sea Norwegian sector (above).3 A typical Valhall field horizontal well requires 5 to 12 separate fracture stimulations. To save time, BP performs drilling and completion operations simultaneously on the platform. After well-completion equipment is installed, the drilling rig skids to the next wellhead slot. A large CT unit and a stimulation vessel complete the wells. The first CT run performs wellbore cleanout and perforating. The stimulation vessel then pumps a proppant fracturing treatment. The next CT run cleans out excess proppant, but leaves a sand plug to isolate the preceding fracture. The next interval is perforated, and this cycle continues until all zones are stimulated.

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In the past, conventional CT units operated with a 13-member crew. The equipment spread consisted of a control unit, reel and power pack, well-control equipment, two high-pressure positive displacement pumps, mud shakers, flow valves and chokes, and an injector-head stand. Recent extended-reach wells with 2,000-m [6,562-ft] horizontal sections drilled to tap outer areas of the field are more challenging than previous wells. The ability to use larger, heavier 27⁄8-in. coiled tubing would increase operational efficiency and allow completion of additional intervals, but required a redesigned CT unit. An evaluation of platform operations and requirements, and local regulations helped engineers develop the new CT SEAS unit. The new design targeted decreases in rig-up and overall operational cycle times to achieve a 15% efficiency increase and a 30% reduction in CT personnel. The resulting CT SEAS unit consists of modular components that are easy to deliver and assemble, produce zero discharge and optimize space utilization offshore (next page, top).

Flexibility in equipment layout reduces rig-up time and improves CT operations. Conventional offshore CT units typically involve 54 crane lifts during rig-up; the new unit cuts this number to 36. CT SEAS components travel to the wellsite preassembled and pretested on skids to reduce the number of crane lifts and the amount of manual equipment handling. The injector head is transported with the connector installed. A self-folding gooseneck and partially automated process for stabbing coiled tubing into the injector head limits personnel exposure to hazards. To simplify hookups and pressure testing, the improved skid designs have fewer valves and some piping is connected and tested in advance as modular components. Distributed electric control of valves in place of centralized hydraulic control reduces the number of hydraulic connections. The CT SEAS system has 36 hydraulic connections instead of the usual 84 of older units. Control cabin ergonomics allow operators to react quickly and efficiently to any situation (next page, bottom). Automated process and equipment control reduces crew requirements from 13 to 9 members and allows the unit operator to focus on well-intervention efficiency. Process-control software incorporates automated safety features that reduce risk exposure in settings prone to human errors. During CT operations, job parameters are monitored, recorded and plotted by the CoilCAT coiled tubing computer-aided treatment system for real-time data acquisition. The InterACT realtime monitoring and data delivery system provides secure Web-based, two-way communication that makes field data available at all stages of a CT operation.4 Authorized client and Schlumberger personnel have access to data and can monitor jobs remotely. Streaming data transfer facilitates real-time evaluation of operations to help fine-tune job procedures and speed up decision-making. The CT SEAS unit has improved wellbore cleanout efficiency and allowed completion of more difficult flank wells. The capability of running up to 6,000 m [1,829 ft] of 27⁄8-in. coiled 3. Andreassen T, Langeteig B, Amaravadi S, Mallalieu R and Polsky Y: “Field Launch of a Safer, More-Efficient Coiled-Tubing Unit in North Sea for Valhall Stimulations,” paper SPE 89604, presented at the SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, USA, March 23–24, 2004. 4. Cabanzo LE and Zhou W: “Real-Time Data Delivery in Coiled-Tubing Well Interventions,” paper SPE 89528, presented at the SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, USA, March 23–24, 2004.

Oilfield Review

BOP skid

Control cabin and tool shop

Injector head and jacking frame

Drop-in-drum tubing reel

< A safer, more efficient offshore unit. The CT SEAS unit consists of modular skids containing multiple systems for optimal utilization of platform space, efficient rig-up and easy delivery. This design reduces the number of crane lifts required to rig up on a platform or move from well to well. The principal components are an injector head and jacking frame, blowout preventer (BOP) skid, stackable control cabin and tool shop, shaker and tank system, BOP-control and choke skid, hydraulic power unit and drop-in-drum tubing reel. A self-folding gooseneck and partially automated process for stabbing coiled tubing into the injector head reduce the risk of accidents and injuries. Unit automation further improves safety and efficiency, and reduces unit crews from 13 to 9 members.

Hydraulic power unit

Mud shaker and tank system

BOP-control and choke skid

> CT unit and system control. A cyber-based system in the CT SEAS cabin operates the reel, injector head, well-control equipment, flow-control chokes, mud shakers and pumps.

Spring 2004

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A History of Coiled Tubing

Early coiled tubing (CT) technology can be traced to project PLUTO (Pipe Lines Under The Ocean)—a top-secret effort to install pipelines across the English Channel during World War II.1 In June 1944, Allied engineers deployed several pipelines to provide fuel for D-day invasion forces. Most of the lines were fabricated from 40-ft [12-m] joints of 3-in. inside diameter (ID), 0.212-in. wall thickness steel pipe welded together to form 4,000-ft [1,220-m] sections. These larger pipe sections were welded end-to-end, spooled onto 40-ft diameter floating drums and towed behind cable-laying vessels. Successful deployment of 23 pipelines ranging in length from 30 to 70 miles [48 to 113 km] set the stage for future development and use of coiled tubing in oil and gas wells. Elements of modern CT injector heads can be found in a device developed by Bowen Tools during the early 1960s for deploying radio antennae to the ocean surface from submarines submerged as deep as 600 ft [183 m]. The antennae were stored on a spool beneath the injector for easy extension and retrieval. These basic concepts aided in the design of CT units and injector systems. The first such unit, built by Bowen Tools and the California Oil Company in 1962, included an injector rated for surface loads up to 30,000 lbm [13,608 kg] that ran a continuous string of 1.315-in. outside diameter (OD) pipe. The unit’s 9-ft [2.7-m] diameter storage reel included a hub with a rotating fluid swivel to allow continuous pumping down the coiled tubing. However, low yield-strength steels and the numerous end-to-end, or butt, welds required to fabricate continuous tubing could not withstand repeated bending cycles and high tensile loads. Weld failures, equipment breakdowns and fishing operations to retrieve lost coiled tubing caused operators to lose confidence in this technique. From the 1960s through the 1970s, manufacturing companies, including Bowen Tools, Brown Oil Tools, Uni-Flex, Inc., Hydra Rig Inc. and Otis Engineering, continued making

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improvements in CT equipment and injector heads. These changes allowed larger coiled tubing sizes to be used at greater working depths, improved coiled tubing performance and reliability, and reduced the number of surface equipment failures. Unfortunately, an overall poor success rate and a reputation for limited reliability continued to plague CT operations. The late 1970s and early 1980s represented a turning point for coiled tubing, which up to that time was milled, or formed, in 1,500-ft [457-m] sections. In 1978, improved manufacturing quality and continuous milling allowed fabrication of 11⁄4-in. OD pipe. In 1980, Southwestern Pipe introduced 70,000-psi (70-ksi) [483-MPa] high-strength, low-alloy (HSLA) steel for coiled tubing. The early 1980s saw the introduction of 11⁄2-in. and 13⁄4-in. OD coiled tubing. In 1983, Quality Tubing Inc. began using 3,000-ft [914-m] sheets of Japanese steel to reduce the number of required welds by 50%. Later in the 1980s, Quality Tubing introduced bias welding to eliminate butt welds. This process involved cutting flat steel strips diagonally to enhance coiled tubing strength and life by spreading the heat-affected weld zone spirally around the tube. In addition, a better understanding of coiled tubing fatigue enabled improvements in reliability and pipe performance. In 1990, the first string of 2-in. coiled tubing was milled for a permanent well completion. Soon after that suppliers began manufacturing 23⁄8-, 25⁄8-, 27⁄8-, 31⁄2- and 41⁄2-in. OD sizes for well-servicing applications. Today, coiled tubing is manufactured from steel with high yield strengths of 90, 100, 110 and 120 ksi [620, 689, 758 and 827 MPa], as well as corrosionresistant alloys. Higher strength steel, larger diameters and the need to reduce costs were key factors behind the CT revolution of the 1990s, and subsequently accounted for the extraordinary increase in concentric, or through-tubing, well-intervention work. 1. Wright TR Jr and Sas-Jaworsky II A (eds): World Oil’s Coiled Tubing Handbook. Houston, Texas, USA: Gulf Publishing Co. (1998): 7.

tubing at faster rates has improved well cleaning, eliminated the need for friction-reducing chemical additives and reduced overall job times. In the new CT unit design, the current and future success of this technology can be attributed to platform designs tailored to CT requirements. To date, all of the targeted efficiency gains have not been realized on the Valhall platform, but with each campaign the team moves closer to those goals. The need for efficient CT technology is not limited to offshore operations. Schlumberger developed the CT EXPRESS rapid-deployment coiled tubing service for intermediate-depth onshore wells (next page, top). This system comprises two trucks—a purpose-built CT unit and combination nitrogen and liquid pump—operated by three people. It provides the same capabilities as conventional units with five-person crews. The combination pumper includes a liquidnitrogen tank and liquid-additive systems, and provides electrical and hydraulic power. This unit is designed for applications involving relatively low pump rates, moderate pressures and continuous operations for long periods. Tubing remains stabbed in the injector head during transportation, and the bottomhole assembly (BHA) can be assembled and pressure tested prior to arrival on location. A drop-in-drum tubing reel and innovative BOP pressure-test stand facilitate unit mobilization. For rig-up safety and efficiency, no hydraulic or electric connections have to be made on location. The unit operator controls the reel, injector head and BOP stack from a cyber-based control cabin, which utilizes available personnel more effectively and improves wellsite communication. There are also separate stand-alone control panels for operation of individual equipment components. Statistics from CT operations show that inaction or incorrect actions contribute to at least one-third of all failures. About 83% of the failures were triggered by a downhole event, resulting in forces that exceeded safe CT working limits. To address this problem, the Schlumberger IIC Intelligent Injector Control, which is compatible with both conventional and new CT SEAS units, provides automated control of CT conveyance. In conjunction with CoilCADE coiled tubing design and evaluation software, IIC technology ensures that CT operations remain within specified job parameters. This system performs automated injector load,...